10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2015

Commission File Number	Exact Name of Registrant as Specified in its Charter, State or Other Jurisdiction of Incorporation, Address of Principal Executive Offices, Zip Code and Telephone Number (Including Area Code)	I.R.S. Employer Identification Number
001-31403	PEPCO HOLDINGS, INC. (Pepco Holdings or PHI), a Delaware corporation 701 Ninth Street, N.W. Washington, D.C. 20068 Telephone: (202)872-2000	52-2297449
001-01072	POTOMAC ELECTRIC POWER COMPANY (Pepco), a District of Columbia and Virginia corporation 701 Ninth Street, N.W. Washington, D.C. 20068 Telephone: (202)872-2000	53-0127880
001-01405	DELMARVA POWER & LIGHT COMPANY (DPL), a Delaware and Virginia corporation 500 North Wakefield Drive, 2nd Floor Newark, DE 19702 Telephone: (202)872-2000	51-0084283
001-03559	ATLANTIC CITY ELECTRIC COMPANY (ACE), a New Jersey corporation 500 North Wakefield Drive, 2nd Floor Newark, DE 19702 Telephone: (202)872-2000	21-0398280

Securities registered pursuant to Section 12(b) of the Act:

Registrant	Title of Each Class	Name of Each Exchange on Which Registered
Pepco Holdings	Common Stock, $.01 par value	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

Registrant	Title of Each Class
Pepco	Common Stock, $.01 par value
DPL	Common Stock, $2.25 par value
ACE	Common Stock, $3.00 par value

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Pepco Holdings	Yes  x    No  ¨	Pepco	Yes  ¨    No  x
DPL	Yes  ¨    No  x	ACE	Yes  ¨    No  x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Pepco Holdings	Yes  ¨    No  x	Pepco	Yes  ¨    No  x
DPL	Yes  ¨    No  x	ACE	Yes  ¨    No  x

Indicate by check mark whether each registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days.

Pepco Holdings	Yes  x    No  ¨	Pepco	Yes  x    No  ¨
DPL	Yes  x    No  ¨	ACE	Yes  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Pepco Holdings	Yes  x    No  ¨	Pepco	Yes  x    No  ¨
DPL	Yes  x    No  ¨	ACE	Yes  x    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K (applicable to Pepco Holdings only).  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

	Large Accelerated Filer	Accelerated Filer	Non- Accelerated Filer	Smaller Reporting Company
Pepco Holdings	x	¨	¨	¨
Pepco	¨	¨	x	¨
DPL	¨	¨	x	¨
ACE	¨	¨	x	¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Pepco Holdings	Yes  ¨    No  x	Pepco	Yes  ¨    No  x
DPL	Yes  ¨    No  x	ACE	Yes  ¨    No  x

Pepco, DPL, and ACE meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and are therefore filing this Form 10-K with the reduced disclosure format specified in General Instruction I(2) of Form 10-K.

Registrant	Aggregate Market Value of Voting and Non-Voting Common Equity Held by Non-Affiliates of the Registrant at June 30, 2015	Number of Shares of Common Stock of the Registrant Outstanding at February 5, 2016
Pepco Holdings	$6,802.6 million (a)	254,340,724 ($.01 par value)
Pepco	None (b)	100 ($.01 par value)
DPL	None (c)	1,000 ($2.25 par value)
ACE	None (c)	8,546,017 ($3.00 par value)

(a) Solely for purposes of calculating this aggregate market value, PHI has defined its affiliates to include (i) those persons who were, as of June 30, 2015, its executive officers, directors and beneficial owners of more than 10% of its common stock, and (ii) such other persons who were deemed, as of June 30, 2015, to be controlled by, or under common control with, PHI or any of the persons described in clause (i) above.

(b) All voting and non-voting common equity is owned by Pepco Holdings.

(c) All voting and non-voting common equity is owned by Conectiv, LLC, a wholly owned subsidiary of Pepco Holdings.

THIS COMBINED FORM 10-K IS SEPARATELY FILED BY PEPCO HOLDINGS, PEPCO, DPL AND ACE. INFORMATION CONTAINED HEREIN RELATING TO ANY INDIVIDUAL REGISTRANT IS FILED BY SUCH REGISTRANT ON ITS OWN BEHALF. EACH REGISTRANT MAKES NO REPRESENTATION AS TO INFORMATION RELATING TO THE OTHER REGISTRANTS.

DOCUMENTS INCORPORATED BY REFERENCE

Information required by Items 10, 11, 12 and 13 of Part III of this report will be incorporated by reference to Pepco Holdings’ definitive proxy statement with respect to its 2016 Annual Meeting of Stockholders, if such definitive proxy statement is filed with the Securities and Exchange Commission on or before April 29, 2016.

TABLE OF CONTENTS
			Page
Glossary of Terms				ii
Forward-Looking Statements				1
PART I
Item 1.	-	Business		4
Item 1A.	-	Risk Factors		29
Item 1B.	-	Unresolved Staff Comments		43
Item 2.	-	Properties		43
Item 3.	-	Legal Proceedings		44
Item 4.	-	Mine Safety Disclosures		45
PART II
Item 5.	-	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		45
Item 6.	-	Selected Financial Data		48
Item 7.	-	Management’s Discussion and Analysis of Financial Condition and Results of Operations		49
Item 7A.	-	Quantitative and Qualitative Disclosures About Market Risk		133
Item 8.	-	Financial Statements and Supplementary Data		135
Item 9.	-	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure		351
Item 9A.	-	Controls and Procedures		352
Item 9B.	-	Other Information		353
PART III
Item 10.	-	Directors, Executive Officers and Corporate Governance		354
Item 11.	-	Executive Compensation		354
Item 12.	-	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		354
Item 13.	-	Certain Relationships and Related Transactions, and Director Independence		354
Item 14.	-	Principal Accountant Fees and Services		355
PART IV
Item 15.	-	Exhibits and Financial Statement Schedules		356
Schedule I	-	Condensed Financial Information of Parent Company		358
Schedule II	-	Valuation and Qualifying Accounts		364
Signatures				385
Index to Exhibits Filed Herewith				388
Index to Exhibits Furnished Herewith				389
Exhibit 12	-	Statements Re: Computation of Ratios		389
Exhibit 21	-	Subsidiaries of the Registrant		393
Exhibit 23	-	Consents of Independent Registered Public Accounting Firm		395
Exhibits 31.1 - 31.8	-	Rule 13a-14a/15d-14(a) Certifications		399
Exhibits 32.1 - 32.4	-	Section 1350 Certifications		407

i

GLOSSARY OF TERMS

The following is a glossary of terms, abbreviations and acronyms that are used in the Reporting Companies’ SEC reports. The terms, abbreviations and acronyms used have the meanings set forth below, unless the context requires otherwise.

Term	Definition
2012 LTIP	Pepco Holdings, Inc. 2012 Long-Term Incentive Plan
ACE	Atlantic City Electric Company
ACE Funding	Atlantic City Electric Transition Funding LLC
AFUDC	Allowance for funds used during construction
AMI	Advanced metering infrastructure, a system that collects, measures and analyzes energy usage data from advanced digital electric and gas meters known as smart meters
AOCL	Accumulated Other Comprehensive Loss
ASC	Accounting Standards Codification
BGE	Baltimore Gas and Electric Company
BGS	Basic Generation Service (the supply of electricity by ACE to retail customers in New Jersey who have not elected to purchase electricity from a competitive supplier)
Bondable Transition Property	Principal and interest payments on the Transition Bonds and related taxes, expenses and fees
BSA	Bill Stabilization Adjustment
CERCLA	Comprehensive Environmental Response, Compensation, and Liability Act of 1980
Conectiv	Conectiv, LLC, a wholly owned subsidiary of PHI and the parent of DPL and ACE
Conectiv Energy	PHI’s former competitive wholesale power generation, marketing and supply business, the disposition of which was completed in 2010
Contract EDCs	Pepco, DPL and BGE, the Maryland utilities required by the MPSC to enter into a contract for new generation
CTA	Consolidated tax adjustment
DCPSC	District of Columbia Public Service Commission
DC PLUG	District of Columbia Power Line Undergrounding
DC Settlement Agreement	The Nonunanimous Full Settlement Agreement and Stipulation entered into on October 6, 2015, by Exelon, PHI and Pepco, and certain of their respective affiliates with the District of Columbia Government, the Office of the People’s Counsel and other parties, regarding the District of Columbia Merger approval proceedings
Default Electricity Supply	The supply of electricity by PHI’s electric utility subsidiaries at regulated rates to retail customers who do not elect to purchase electricity from a competitive supplier, and which, depending on the jurisdiction, is also known as Standard Offer Service or BGS
Default Electricity Supply Revenue	Revenue primarily from Default Electricity Supply
DOE	U.S. Department of Energy
DOEE	District of Columbia Department of Energy and Environment
DOJ	U.S. Department of Justice
DPL	Delmarva Power & Light Company
DPSC	Delaware Public Service Commission
DRP	Direct Stock Purchase and Dividend Reinvestment Plan
DSEU	Delaware Sustainable Energy Utility
EDC	Electricity Distribution Company
EmPower Maryland	A Maryland demand-side management program for Pepco and DPL
EPA	U.S. Environmental Protection Agency
Exchange Act	Securities Exchange Act of 1934, as amended
FASB	Financial Accounting Standards Board
FCC	Federal Communications Commission
FERC	Federal Energy Regulatory Commission
FLRP	Forward Looking Rate Plan
FPA	Federal Power Act

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Term	Definition
FS	Feasibility study
GAAP	Accounting principles generally accepted in the United States of America
GCR	Gas Cost Rate
GWh	Gigawatt hour
HPS	Hourly Priced Service
HSR Act	The Hart-Scott-Rodino Antitrust Improvements Act of 1976
Improvement Financing Act	The Electric Company Infrastructure Improvement Financing Act of 2014 enacted by the Council of the District of Columbia on May 3, 2014
IRS	Internal Revenue Service
LIBOR	London Interbank Offered Rate
LTIP	Pepco Holdings, Inc. Long-Term Incentive Plan
MAPP	Mid-Atlantic Power Pathway
Mcf	Thousand Cubic Feet
Merger	Merger of Merger Sub with and into PHI, with PHI surviving as a wholly owned subsidiary of Exelon
Merger Agreement	Agreement and Plan of Merger, dated April 29, 2014 among Exelon, Merger Sub and PHI, as amended and restated on July 18, 2014
Merger Sub	Purple Acquisition Corp., a Delaware corporation and an indirect, wholly owned subsidiary of Exelon
Motion to Reopen	The Motion of Joint Applicants to Reopen the Record in Formal Case No. 1119 to Allow for Consideration of the DC Settlement Agreement
MPSC	Maryland Public Service Commission
MW	Megawatt
MWh	Megawatt hour
NAV	Net Asset Value
NERC	North American Electric Reliability Corporation
New Jersey Societal Benefit Program	A New Jersey public interest program for low income customers
NJ SOCA Law	The New Jersey law under which the SOCAs were established
NJBPU	New Jersey Board of Public Utilities
NPDES	National Pollutant Discharge Elimination System
NUGs	Non-utility generators
OPEB	Other postretirement benefit
OPEB Plan	Pepco Holdings, Inc. Welfare Plan for Retirees
PCI	Potomac Capital Investment Corporation and its subsidiaries
Pepco	Potomac Electric Power Company
Pepco Energy Services	Pepco Energy Services, Inc. and its subsidiaries
Pepco Holdings or PHI	Pepco Holdings, Inc.
PHI Retirement Plan	PHI’s non-contributory, defined benefit pension plan
PJM	PJM Interconnection, LLC
PJM RTO	PJM regional transmission organization
Power Delivery	The transmission, distribution and default supply of electricity and, to a lesser extent, the distribution and supply of natural gas, conducted through Pepco, DPL and ACE, PHI’s regulated public utility subsidiaries
PPA	Power purchase agreement
Preferred Stock	Originally issued shares of PHI non-voting, non-convertible and non-transferable Series A preferred stock, par value $0.01 per share
PRP	Potentially responsible party
PUHCA 2005	Public Utility Holding Company Act of 2005

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Term	Definition
RECs	Renewable energy credits
Regulated T&D Electric Revenue	Revenue from the transmission and the distribution of electricity to PHI’s customers within its service territories at regulated rates
Regulatory Termination	Termination of the Merger Agreement under certain circumstances due to, generally speaking, the failure to obtain regulatory approvals with respect to the Merger or the breach by Exelon of its obligations in respect of obtaining such regulatory approvals
Reporting Company	PHI, Pepco, DPL or ACE
Revenue Decoupling Adjustment	An adjustment equal to the amount by which revenue from distribution sales differs from the revenue that Pepco and DPL are entitled to earn based on the approved distribution charge per customer
RI/FS	Remedial investigation and feasibility study
ROE	Return on equity
RPS	Renewable Energy Portfolio Standards
SEC	Securities and Exchange Commission
SILO	Sale-in, lease-out transaction
SOCAs	Standard Offer Capacity Agreements required to be entered into by ACE pursuant to a New Jersey law enacted to promote the construction of qualified electric generation facilities in New Jersey
SOS	Standard Offer Service, how Default Electricity Supply is referred to in Delaware, the District of Columbia and Maryland
SRECs	Solar renewable energy credits
Subscription Agreement	Subscription Agreement, dated April 29, 2014, between Exelon and PHI
T&D	Transmission and distribution
TEFA	Transitional Energy Facility Assessment, a New Jersey tax surcharge providing a gradual transition from the previous franchise and gross receipts tax eliminated in 1997, to its new total liability under the corporation business tax and the sales-and-use tax (this surcharge was eliminated in 2013)
Transition Bond Charge	Revenue ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds and related taxes, expenses and fees
Transition Bonds	Transition Bonds issued by ACE Funding
VDEQ	Virginia Department of Environmental Quality
VIE	Variable interest entity
VRDBs	Variable Rate Demand Bonds
VSCC	Virginia State Corporation Commission

iv

FORWARD-LOOKING STATEMENTS

Some of the statements contained in this Annual Report on Form 10-K with respect to Pepco Holdings, Inc. (PHI or Pepco Holdings), Potomac Electric Power Company (Pepco), Delmarva Power & Light Company (DPL) and Atlantic City Electric Company (ACE), including each of their respective subsidiaries, are forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended (the Exchange Act), and Section 27A of the Securities Act of 1933, as amended, and are subject to the safe harbor created thereby under the Private Securities Litigation Reform Act of 1995. These statements include declarations regarding the intents, beliefs, estimates and current expectations of one or more of PHI, Pepco, DPL or ACE (each, a Reporting Company) or their subsidiaries. In some cases, you can identify forward-looking statements by terminology such as “may,” “might,” “will,” “should,” “could,” “expects,” “intends,” “assumes,” “seeks to,” “plans,” “anticipates,” “believes,” “projects,” “estimates,” “predicts,” “potential,” “future,” “goal,” “objective,” or “continue” or the negative of such terms or other variations thereof or comparable terminology, or by discussions of strategy that involve risks and uncertainties. Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may cause one or more Reporting Companies’ or their subsidiaries’ actual results, levels of activity, performance or achievements to be materially different from any future results, levels of activity, performance or achievements expressed or implied by such forward-looking statements. Therefore, forward-looking statements are not guarantees or assurances of future performance, and actual results could differ materially from those indicated by the forward-looking statements.

The forward-looking statements contained herein are qualified in their entirety by reference to the following important factors, which are difficult to predict, contain uncertainties, are beyond each Reporting Company’s or its subsidiaries’ control and may cause actual results to differ materially from those contained in forward-looking statements:

• Certain risks and uncertainties associated with the proposed merger (the Merger) of an indirect, wholly owned subsidiary of Exelon Corporation, a Pennsylvania corporation (Exelon), with and into Pepco Holdings, including, without limitation:

• The inability of Pepco Holdings or Exelon to obtain regulatory approvals required for the completion of the Merger;

• Delays caused by the reconsideration process in the District of Columbia, and the review and approval of the Merger on the terms set forth in the settlement agreement among PHI, Exelon, the District of Columbia government and other parties, which may delay the Merger or cause the companies to abandon the Merger;

• The inability of Pepco Holdings or Exelon to satisfy conditions to the closing of the Merger;

• Unexpected costs, liabilities or delays that may arise from the Merger, including as a result of stockholder or other litigation; and

• Negative impacts on the businesses of Pepco Holdings and its utility subsidiaries as a result of uncertainty surrounding the Merger, including continuing delays in filing rate cases due to the restrictions contained in the Merger Agreement.

• Future regulatory or legislative actions impacting the industries in which Pepco Holdings and its subsidiaries operate, which actions could adversely affect Pepco Holdings and its utility subsidiaries.

• Changes in governmental policies and regulatory actions affecting the energy industry or one or more of the Reporting Companies specifically, including allowed rates of return, industry and rate structure, acquisition and disposal of assets and facilities, operation and construction of transmission and distribution facilities and the recovery of purchased power expenses;

1

• The outcome of pending and future rate cases and other regulatory proceedings, including (i) challenges to the base return on equity (ROE) and the application of the formula rate process previously established by the Federal Energy Regulatory Commission (FERC) for transmission services provided by Pepco, DPL and ACE; and (ii) other possible disallowances related to recovery of costs (including capital costs and advanced metering infrastructure (AMI) costs) and expenses or delays in the recovery of such costs;

• The expenditures necessary to comply with regulatory requirements, including regulatory orders, and to implement reliability enhancement, emergency response and customer service improvement programs;

• Possible fines, penalties or other sanctions assessed by regulatory authorities against a Reporting Company or its subsidiaries;

• The impact of adverse publicity and media exposure which could render one or more Reporting Companies or their subsidiaries vulnerable to negative customer perception and could lead to increased regulatory oversight or other sanctions;

• Weather conditions affecting usage and emergency restoration costs;

• Population growth rates and changes in demographic patterns;

• Changes in customer energy demand due to, among other things, conservation measures and the use of renewable energy and other energy-efficient products, as well as the impact of net metering and other issues associated with the deployment of distributed generation and other new technologies;

• General economic conditions, including the impact on energy use caused by an economic downturn or recession, or by changes in the level of commercial activity in a particular region or service territory, or affecting a particular business or industry located therein;

• Changes in and compliance with environmental and safety laws and policies;

• Changes in tax rates or policies;

• Changes in rates of inflation;

• Changes in accounting standards or practices;

• Unanticipated changes in operating expenses and capital expenditures;

• Rules and regulations imposed by, and decisions of, federal and/or state regulatory commissions, PJM Interconnection, LLC (PJM), the North American Electric Reliability Corporation (NERC) and other applicable electric reliability organizations;

• Legal and administrative proceedings (whether civil or criminal) and settlements that affect a Reporting Company’s or its subsidiaries’ business and profitability;

• Pace of entry into new markets;

• Interest rate fluctuations and the impact of credit and capital market conditions on the ability to obtain funding on favorable terms; and

• Effects of geopolitical and other events, including the threat of physical or cyber attacks.

These forward-looking statements are also qualified by, and should be read together with, the risk factors included in Part I, Item 1A. “Risk Factors” and other statements in this Annual Report on Form 10-K, and investors should refer to such risk factors and other statements in evaluating the forward-looking statements contained in this Annual Report on Form 10-K.

2

Any forward-looking statements speak only as to the date this Annual Report on Form 10-K for each Reporting Company was filed with the Securities and Exchange Commission (SEC) and none of the Reporting Companies undertakes an obligation to update any forward-looking statements to reflect events or circumstances after the date on which such statements are made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for a Reporting Company to predict all such factors. Furthermore, it may not be possible to assess the impact of any such factor on such Reporting Company’s or its subsidiaries’ business (viewed independently or together with the business or businesses of some or all of the other Reporting Companies or their subsidiaries), or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement. The foregoing factors should not be construed as exhaustive.

3

Part I

Item 1. BUSINESS

Overview

Pepco Holdings is a holding company that was incorporated in Delaware in 2001. Through its regulated public utility subsidiaries, PHI is engaged primarily in the transmission, distribution and default supply of electricity, and, to a lesser extent, the distribution and supply of natural gas. The principal executive offices of PHI are located at 701 Ninth Street, N.W., Washington, D.C. 20068.

PHI’s public utility subsidiaries are:

Name of Utility	State and Year of Incorporation	Business	Service Territories	Address of Principal Executive Offices
Potomac Electric Power Company	District of Columbia (1896) Virginia (1949)	Transmission, distribution and default supply of electricity	District of Columbia Major portions of Montgomery and Prince George’s Counties, Maryland	701 Ninth Street, N.W., Washington, D.C. 20068
Delmarva Power & Light Company	Delaware (1909) Virginia (1979)	Transmission, distribution and default supply of electricity Distribution and supply of natural gas	Portions of Delaware and Maryland (electricity) Portions of New Castle County, Delaware (natural gas)	500 North Wakefield Drive, Newark, Delaware 19702
Atlantic City Electric Company	New Jersey (1924)	Transmission, distribution and default supply of electricity	Portions of Southern New Jersey	500 North Wakefield Drive, Newark, Delaware 19702

4

The service territories of each of Pepco Holdings’ utilities are depicted in the map below:

PHI’s three utility subsidiaries comprise a single operating segment for accounting purposes, which is referred to herein as “Power Delivery.”

In addition to its regulated utility operations, Pepco Holdings, through Pepco Energy Services, Inc. and its subsidiaries (collectively, Pepco Energy Services), is engaged in an energy savings performance contracting business, an underground transmission and distribution construction business and a thermal business.

The operations of Pepco Energy Services collectively comprise a separate, second operating segment for accounting purposes. During 2013, Pepco Energy Services completed the wind-down of its retail electric and natural gas supply businesses, and, as a result, these businesses have been accounted for as discontinued operations, as described below under “Discontinued Operations.”

Through its wholly owned subsidiary, Potomac Capital Investment Corporation (PCI), PHI previously held a portfolio of cross-border energy lease investments. During 2013, Pepco Holdings completed the termination of its interests in its cross-border energy lease investments, and as a result, these investments have been accounted for as discontinued operations, as described below under “Discontinued Operations.”

5

The following table shows PHI’s consolidated operating revenue and net income from continuing operations derived from the Power Delivery and Pepco Energy Services segments over the three preceding fiscal years.

	2015		2014			2013
	(millions of dollars)
Operating Revenue
Power Delivery	$	4,805	$	4,607		$	4,472
Pepco Energy Services		223		278			203
Net Income (Loss) from Continuing Operations
Power Delivery	$	302	$	320		$	289
Pepco Energy Services		4		(39	)		3

For additional financial information with respect to PHI’s segments, see Note (5), “Segment Information,” to the consolidated financial statements of PHI.

PHI Service Company, a wholly owned subsidiary of PHI, provides a variety of support services, including legal, accounting, treasury, tax, purchasing and information technology services, to PHI and its operating subsidiaries. These services are provided pursuant to service agreements among PHI, PHI Service Company and the participating operating subsidiaries. The expenses of PHI Service Company are charged to PHI and the participating operating subsidiaries in accordance with cost allocation methodologies set forth in the service agreements.

Agreement and Plan of Merger with Exelon Corporation

PHI entered into an Agreement and Plan of Merger, dated April 29, 2014, as amended and restated on July 18, 2014 (the Merger Agreement), with Exelon Corporation, a Pennsylvania corporation (Exelon), and Purple Acquisition Corp., a Delaware corporation and an indirect, wholly owned subsidiary of Exelon (Merger Sub), providing for the merger of Merger Sub with and into PHI (the Merger), with PHI surviving the Merger as an indirect, wholly owned subsidiary of Exelon. Pursuant to the Merger Agreement, at the effective time of the Merger, each outstanding share of common stock, par value $0.01 per share, of PHI (other than (i) shares owned by Exelon, Merger Sub or any other direct or indirect wholly owned subsidiary of Exelon and shares owned by PHI or any direct or indirect wholly owned subsidiary of PHI, and in each case not held on behalf of third parties (but not including shares held by PHI in any rabbi trust or similar arrangement in respect of any compensation plan or arrangement) and (ii) shares that are owned by stockholders who have perfected and not withdrawn a demand for appraisal rights pursuant to Delaware law), will be canceled and converted into the right to receive $27.25 in cash, without interest.

In connection with entering into the Merger Agreement, PHI entered into a Subscription Agreement, dated April 29, 2014 (the Subscription Agreement), with Exelon, pursuant to which on April 30, 2014, PHI issued to Exelon 9,000 originally issued shares of non-voting, non-convertible and non-transferable Series A preferred stock, par value $0.01 per share (the Preferred Stock), for a purchase price of $90 million. Exelon also committed pursuant to the Subscription Agreement to purchase 1,800 originally issued shares of Preferred Stock for a purchase price of $18 million at the end of each 90-day period following the date of the Subscription Agreement until the Merger closes or is terminated, up to a maximum of 18,000 shares of Preferred Stock for a maximum aggregate consideration of $180 million. In accordance with the Subscription Agreement, on each of July 29, 2014, October 27, 2014, January 26, 2015, April 27, 2015 and July 24, 2015, an additional 1,800 shares of Preferred Stock were issued by PHI to Exelon for an aggregate purchase price of $90 million. The holders of the Preferred Stock will be entitled to receive a cumulative, non-participating cash dividend of 0.1% per annum, payable quarterly, when, as and if declared by PHI’s board of directors. The proceeds from the issuance of the Preferred Stock are not subject to restrictions and are intended to serve as a prepayment of any applicable reverse termination fee payable from Exelon to PHI. The Preferred Stock will be redeemable on the terms and in the circumstances set forth in the Merger Agreement and the Subscription Agreement.

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The Merger Agreement provides for certain termination rights for each of PHI and Exelon, and further provides that, upon termination of the Merger Agreement under certain specified circumstances, PHI will be required to pay Exelon a termination fee of $259 million or reimburse Exelon for its expenses up to $40 million (which reimbursement of expenses shall reduce on a dollar for dollar basis any termination fee subsequently payable by PHI), provided, however, that if the Merger Agreement is terminated in connection with an acquisition proposal made under certain circumstances by a person who made an acquisition proposal between April 1, 2014 and the date of the Merger Agreement, the termination fee will be $293 million plus reimbursement of Exelon for its expenses up to $40 million (not subject to offset). In addition, if the Merger Agreement is terminated under certain circumstances due to the failure to obtain required regulatory approvals with respect to the Merger or the breach by Exelon of its obligations in respect of obtaining such regulatory approvals (a Regulatory Termination), PHI will be able to redeem any issued and outstanding Preferred Stock at par value, and in that case, Exelon will be required to pay all documented out-of-pocket expenses incurred by PHI in connection with the Merger Agreement or the transactions contemplated thereby, up to $40 million. If the Merger Agreement is terminated, other than for a Regulatory Termination, PHI will be required to redeem the Preferred Stock at the purchase price of $10,000 per share, plus any unpaid accrued and accumulated dividends thereupon.

Consummation of the Merger is subject to the satisfaction or waiver of specified closing conditions, including (i) the approval of the Merger by the holders of a majority of the outstanding shares of common stock of PHI; (ii) the receipt of regulatory approvals required to consummate the Merger, including approvals from FERC, the Federal Communications Commission (FCC), the Delaware Public Service Commission (DPSC), the District of Columbia Public Service Commission (DCPSC), the Maryland Public Service Commission (MPSC), the New Jersey Board of Public Utilities (NJBPU) and the Virginia State Corporation Commission (VSCC); (iii) the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (the HSR Act); and (iv) other customary closing conditions, including (a) the accuracy of each party’s representations and warranties (subject to customary materiality qualifiers) and (b) each party’s compliance with its obligations and covenants contained in the Merger Agreement (including covenants that may limit, restrict or prohibit PHI and its subsidiaries from taking specified actions during the period between the date of the Merger Agreement and the closing of the Merger or the termination of the Merger Agreement). In addition, the obligations of Exelon and Merger Sub to consummate the Merger are subject to the required regulatory approvals not imposing terms, conditions, obligations or commitments, individually or in the aggregate, that constitute a burdensome condition (as defined in the Merger Agreement).

On September 23, 2014, the stockholders of PHI approved the Merger, on October 7, 2014, the VSCC approved the Merger, and on November 20, 2014, FERC approved the Merger. In addition, the transfer of control of certain communications licenses held by certain of PHI’s subsidiaries has been approved by the FCC. The NJBPU approved the Merger on February 11, 2015 and, on October 15, 2015, voted to extend the effectiveness of its approval until June 30, 2016. The DPSC approved the Merger on May 19, 2015.

The waiting period under the HSR Act expired on December 2, 2015, which allows for the closing of the Merger at any time on or before December 1, 2016.

On May 15, 2015, the MPSC approved the Merger, with conditions, including conditions that modify and supplement those originally proposed. On May 18, 2015, PHI and Exelon announced that they had committed to fulfill the modified, more stringent conditions and package of customer benefits imposed by the MPSC. In connection with these proceedings, the Maryland Office of People’s Counsel and several other parties to the Merger proceedings filed motions in the Circuit Court for Queen Anne’s County,

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Maryland, requesting a stay of the MPSC order. On August 7, 2015, the Circuit Court for Queen Anne’s County denied the motions for stay. On January 8, 2016, the Circuit Court affirmed the MPSC’s order in all respects. On January 20 and 22, 2016, respectively, the Maryland Office of People’s Counsel and environmental groups filed notices of appeal of the Circuit Court’s order to the Maryland Court of Special Appeals. Unless a motion to stay is filed and then granted by the court, the MPSC order will remain in effect during the appeals process.

On August 27, 2015, the DCPSC issued a written order denying the application seeking approval of the Merger. On September 28, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, filed an application for reconsideration with the DCPSC requesting reconsideration of the DCPSC order related to the Merger.

On October 6, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, entered into a Nonunanimous Full Settlement Agreement and Stipulation (the DC Settlement Agreement) with the District of Columbia Government, the Office of the People’s Counsel and other parties, which DC Settlement Agreement contains commitments from Exelon and PHI above those contained in their original merger application.

Also on October 6, 2015, PHI, Exelon and Merger Sub entered into a Letter Agreement (the Letter Agreement), setting forth the terms and conditions under which the parties will file with the DCPSC (a) a Motion of Joint Applicants to Reopen the Record in Formal Case No. 1119 to Allow for Consideration of the DC Settlement Agreement (the Motion to Reopen), or (b) if the Motion to Reopen is not granted, a new merger application, requesting approval of the Merger on the terms and commitments agreed to in the DC Settlement Agreement. Pursuant to the Letter Agreement, PHI and Exelon each agrees, among other things, that neither party will exercise the termination rights each may have under the Merger Agreement on or after October 29, 2015, unless: (i) the DCPSC does not, by November 20, 2015 set a procedural schedule which allows for a final order for approval of the Merger by March 4, 2016, (ii) the DCPSC sets a schedule for action which does not allow for a final order for approval of the Merger by March 4, 2016, (iii) the DCPSC fails to issue a final order approving the Merger and the DC Settlement Agreement as filed without condition or modification by March 4, 2016, (iv) the DCPSC issues a final order denying approval of the Merger or the DC Settlement Agreement or adds conditions or makes modifications to the DC Settlement Agreement, (v) the DC Settlement Agreement is terminated for any reason, or (vi) after March 4, 2016 a condition to closing of the Merger has not been satisfied or waived (other than those conditions that by their nature are to be satisfied at the closing). The Letter Agreement also provides that, subject to certain conditions, Exelon may, following receipt of all regulatory approvals consistent with the DC Settlement Agreement, delay closing of the Merger for up to 30 days to engage in capital markets transactions to raise additional funds required to consummate the Merger.

On October 6, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, filed with the DCPSC the Motion to Reopen requesting consideration of the DC Settlement Agreement and approval of the Merger on such terms and conditions set forth in the DC Settlement Agreement, without condition or modification, and to stay further proceedings on the application for reconsideration filed by the parties on September 28, 2015 and suspend the time period for reconsideration pending the DCPSC’s consideration of the DC Settlement Agreement.

On October 28, 2015, the DCPSC approved the Motion to Reopen and set a procedural schedule for its review of this matter. Upon completion of the public input and evidentiary hearings, the record was closed as of December 23, 2015. Although District of Columbia law does not impose any time limit on the DCPSC’s review of the Merger, the parties requested a decision by March 4, 2016.

The settlements reached and commission orders received to date in Delaware, Maryland and New Jersey, and as proposed in the DC Settlement Agreement, provide for public benefits of, among other things, customer rate credits, funding for energy efficiency and sustainability programs, and other commitments following consummation of the Merger.

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The terms of the Delaware, Maryland and New Jersey settlements and orders also incorporate a “most favored nation” provision which, generally speaking, requires allocation of financial merger benefits determined on an equivalent basis in each jurisdiction based on customer count. Following consummation of the Merger, Exelon and PHI will apply the most favored nation provision to the final settlement terms and other conditions established in the merger approvals to determine the amounts of direct financial benefits that will be provided to customers of Pepco, DPL and ACE and to the jurisdictions. PHI anticipates that Exelon will make capital contributions to the PHI utilities to reimburse the PHI utilities for any such direct benefits that will be charged to earnings of the PHI utilities, net of tax effects, no later than the time such direct benefits are charged to earnings of the PHI utilities. The settlements and commission orders also provide for certain charitable contributions commitments which are required to be paid over a period of 10 years. PHI anticipates that the amounts of such commitments will be charged to earnings of the PHI utilities, net of tax effects, at the time of the merger close. Commitments to develop renewable generation, which are expected to be primarily capital in nature, will be recognized by Exelon as incurred. Upon completion of the merger, the actual nature, amount, timing and financial reporting treatment for these benefits and commitments may be materially different from the current projection.

Business Strategy

PHI’s business objective is to be a top-performing, regulated power delivery company that delivers safe and reliable electric and natural gas service to its customers and through its regulatory proceedings, earns a just and reasonable rate of return on, and receives timely recovery of, its utility investments.

In seeking to achieve this objective, Pepco Holdings’ business strategy is guided by its core values of safety, integrity, and diversity and its mission of environmental stewardship, and is focused on the following initiatives:

• investing in its utilities’ transmission and distribution infrastructure; and

• building a smarter grid and implementing other technological enhancements designed to:

• automate power delivery system functions and improve the reliability of the power distribution system;

• enable its utilities to restore power more quickly and efficiently;

• offer customers detailed information about, and options to help customers better manage, their energy usage; and

• enhance the customer experience and PHI’s communications with customers.

In addition, through Pepco Energy Services, PHI is focused on providing comprehensive energy management solutions and developing, installing and operating renewable energy solutions.

In furtherance of its business strategy, PHI entered into the Merger Agreement with Exelon Corporation. For a discussion of the Merger Agreement, see “– Agreement and Plan of Merger with Exelon Corporation.” Further, PHI may dispose of existing businesses consistent with the terms of the Merger Agreement. PHI also may from time to time refine components of its business strategy as it deems necessary or appropriate in response to business factors and other conditions consistent with the terms of the Merger Agreement and subject to regulatory requirements.

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Overview of the Power Delivery Business

Distribution and Default Supply of Electricity

Each of PHI’s utility subsidiaries owns and operates a network of wires, substations and other equipment that are classified as transmission facilities, distribution facilities or common facilities (which are used for both transmission and distribution). Transmission facilities carry wholesale electricity into, out of and across the utilities’ service territories. Distribution facilities carry electricity from the transmission facilities to the customers located in the utilities’ service territories.

Each utility subsidiary is responsible for the distribution of electricity to customers within its service territory or territories and for which it is paid tariff rates established by the applicable public service commissions. While the transmission and distribution of electricity is regulated, the law of each of these service territories allows for competition in the supply of electricity, which enables distribution customers to contract to purchase their electricity from a supplier approved by the applicable public service commission. PHI’s utility subsidiaries supply electricity at regulated rates to customers who do not elect to purchase their electricity from a competitive supplier. These “default” supply services are referred to generally in this Form 10-K as Default Electricity Supply. The regulatory term for Default Electricity Supply is Standard Offer Service (SOS) in Delaware, the District of Columbia and Maryland, and Basic Generation Service (BGS) in New Jersey. The results of operations of PHI’s utility subsidiaries are only minimally impacted when customers choose to obtain their electricity through competitive suppliers because the utilities earn their approved rates of return by providing distribution service, and not by supplying the electricity.

Transmission of Electricity and Relationship With PJM

Each of PHI’s utility subsidiaries provides transmission services within the jurisdictions that encompass its electricity distribution service territory. In the aggregate, PHI owns approximately 4,600 circuit miles of interconnected transmission lines with voltages ranging from 69 kilovolts (kV) to 500 kV. Under the Open Access Transmission Tariff adopted by FERC, each owner of transmission services is required to provide transmission customers with non-discriminatory access to its transmission facilities at tariff rates approved by FERC.

The transmission facilities owned by Pepco, DPL and ACE are interconnected with the transmission facilities of contiguous utilities and are part of an interstate power transmission grid over which electricity is transmitted throughout a region encompassing the mid-Atlantic portion of the United States and parts of the Midwest. PJM is the FERC-approved independent operator of this transmission grid and manages the wholesale electricity market within its region. Pepco, DPL and ACE each are members of the PJM Regional Transmission Organization (PJM RTO), the regional transmission organization designated by FERC to coordinate the movement of wholesale electricity in PJM’s region.

In accordance with FERC-approved rules, Pepco, DPL, ACE and the other transmission-owning utilities in the PJM region make their transmission facilities available to PJM, and PJM directs and controls the operation of these transmission facilities. Each transmission owner is compensated at transmission rates approved by FERC for the use of its transmission facilities. PJM provides billing and settlement services, collects transmission service revenue from transmission service customers and distributes the revenue to the transmission owners.

PJM also directs the regional transmission planning process within its region. The Board of Managers of PJM reviews and approves all transmission expansion plans within the PJM region, including the construction of new transmission facilities by PJM members. Changes in the current policies for building new transmission lines ordered by FERC and implemented by PJM could result in additional competition to build transmission lines in the PJM region, including in the service territories of PHI’s utility subsidiaries, and could allow PHI’s utility subsidiaries the opportunity to construct transmission facilities in other service territories.

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For a discussion of the regulation of transmission rates, see Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Regulatory and Other Matters – Rate Proceedings – Transmission” and for a discussion of pending FERC transmission rate proceedings, see Note (7), “Regulatory Matters – Rate Proceedings – FERC Transmission ROE Challenges,” to the consolidated financial statements of PHI.

Distribution and Supply of Natural Gas

DPL owns pipelines and other equipment for the distribution and supply of natural gas. DPL uses its natural gas distribution facilities to deliver natural gas to retail customers in its service territory and provides transportation-only services to customers that purchase natural gas from another supplier. Intrastate transportation customers pay DPL distribution service rates approved by the DPSC. Rates for the interstate transportation and sale of wholesale natural gas are regulated by FERC. DPL purchases natural gas supplies for resale to its retail service customers from marketers and producers through a combination of long-term agreements and next-day distribution arrangements.

PHI’s Utility Subsidiaries

Potomac Electric Power Company

Pepco’s electric distribution service territory consists of the District of Columbia and major portions of Prince George’s County and Montgomery County in Maryland. The service territory covers approximately 640 square miles and, as of December 31, 2015, had a population of approximately 2.3 million. This region includes the following key industries that contribute to the regional economic base:

• Federal and municipal government services;

• Professional, scientific, educational and technical services;

• Leisure, hospitality and transportation services; and

• Healthcare and social services.

The following table shows the number of Pepco distribution customers in each of its service territories as of the end of each of the preceding three years.

	2015		2014		2013
	(in thousands)
District of Columbia		282		271		264
Maryland		560		544		537
Total		842		815		801

Pepco distributed a total of 25,988,000, 25,751,000 and 25,801,000 megawatt (MW) hours (MWh) of electricity in 2015, 2014 and 2013, respectively. The following table shows the allocation by percentage among customer types of the total MWh of electricity delivered by Pepco in each of its service territories during each of the preceding three fiscal years:

	2015			2014			2013
District of Columbia:
Residential		9	%		8	%		8	%
Commercial, industrial and other		34	%		35	%		35	%
Total		43	%		43	%		43	%
Maryland:
Residential		23	%		22	%		22	%
Commercial, industrial and other		34	%		35	%		35	%
Total		57	%		57	%		57	%

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Pepco has been designated as the default electricity supplier to residential and commercial customers in its District of Columbia service territory under relevant rules and orders issued by the DCPSC and in its Maryland service territory under relevant Maryland statute and rules and orders issued by the MPSC. Pepco will continue to be the default electricity supplier in its service territories until the relevant DCPSC and MPSC rules and orders (or the Maryland statute) are modified. Pepco purchases the electricity required to satisfy its SOS obligations from wholesale suppliers primarily under contracts entered into in accordance with competitive procurement processes approved and supervised by each of the DCPSC and the MPSC. For commercial customers in the District of Columbia and large commercial customers in Maryland that do not purchase their electricity from a competitive supplier, Pepco is obligated to provide Hourly Priced Service (HPS), a form of SOS service for which Pepco purchases the electricity in the next-day and other short-term PJM RTO markets. As contracts expire, Pepco rebids residential and small commercial contracts annually in the District of Columbia and semi-annually in Maryland through the approved competitive procurement processes. Pepco is paid tariff rates for the transmission and distribution of electricity over its transmission and distribution facilities to all electricity customers in its service territory, whether the customer receives SOS or HPS, or purchases electricity from a competitive supplier, and is entitled to recover from its SOS and HPS customers the costs of acquiring the electricity, plus an administrative charge that is intended to allow it to recover its administrative costs, plus a shareholder return, which varies depending on the customer class.

The following table shows for Pepco customers in the District of Columbia and Maryland the percentage of distribution sales (measured by MWh) over the past three fiscal years to SOS customers.

	2015			2014			2013
District of Columbia		29	%		27	%		25	%
Maryland		40	%		41	%		41	%

In the District of Columbia, under various acts of Congress, pursuant to Pepco’s corporate charter, and subject to the supervision of the DCPSC, Pepco has the non-exclusive authority to install and maintain overhead and underground transmission and distribution lines and other related facilities for the furnishing of electricity. Pepco’s right to occupy public space for utility purposes is by permit from the District of Columbia and the federal government. Pepco is the only public utility that distributes electricity for sale to the public in the District of Columbia.

In Maryland, Pepco operates pursuant to state-wide franchises granted by Maryland’s General Assembly that are unlimited in duration. These franchises were granted to Pepco or to predecessor companies acquired by Pepco, and confer, among other things, the ability to construct electric transmission and distribution lines. Pursuant to statute, public service companies in Maryland may exercise a franchise to the extent authorized by the MPSC. The service territories for Pepco, as well as for other electric utilities in the state, were precisely delineated in 1966 by the MPSC and have been modified in minor ways over the years.

Delmarva Power & Light Company

DPL is engaged in the transmission, distribution and default supply of electricity in portions of Delaware and Maryland. In northern Delaware, DPL also supplies and delivers natural gas to retail customers and provides transportation-only services to retail customers that purchase natural gas from another supplier.

In Maryland, DPL operates pursuant to state-wide franchises that are substantially similar in nature to those described above with respect to Pepco’s Maryland operations. DPL’s exclusive and continuing authority to distribute electricity and natural gas in its non-municipal service territories in Delaware is derived from legislation, through which the DPSC has established exclusive service territories. With respect to municipalities that it serves, DPL provides service under various franchises granted to DPL and predecessor companies, which franchises are generally either unlimited as to time or renew automatically.

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Distribution and Supply of Electricity

DPL’s electric distribution service territory consists of portions of the state of Delaware, and Caroline, Cecil, Dorchester, Harford, Kent, Queen Anne’s, Somerset, Talbot, Wicomico and Worcester counties in Maryland. This territory covers approximately 5,000 square miles and, as of December 31, 2015, had a population of approximately 1.4 million. This region is economically diverse and includes the following key industries that contribute to the regional economic base:

• Commercial activities in the region include banking, government, educational and health services, transportation and tourism.

• Industrial activities in the region include chemical, pharmaceutical, food processing and oil refining.

The following table shows the number of DPL electricity distribution customers in each of its service territories as of the end of each of the preceding three fiscal years.

	2015		2014		2013
	(in thousands)
Delaware		312		308		305
Maryland		203		202		201
Total		515		510		506

DPL distributed a total of 12,474,000, 12,413,000 and 12,465,000 MWh of electricity in 2015, 2014 and 2013, respectively. The following table shows the allocation by percentage among customer types of the total MWh of electricity delivered by DPL in each of its service territories during each of the preceding three fiscal years:

	2015			2014			2013
Delaware:
Residential		25	%		24	%		24	%
Commercial and industrial		40	%		41	%		42	%
Total		65	%		65	%		66	%
Maryland:
Residential		18	%		18	%		17	%
Commercial and industrial		17	%		17	%		17	%
Total		35	%		35	%		34	%

DPL has been designated as the default electricity supplier to residential and commercial and industrial customers in its Delaware service territory under relevant rules and orders issued by the DPSC and in its Maryland service territory under relevant Maryland statute and rules and orders issued by the MPSC. DPL will continue to be the default electricity supplier in its service territories until the relevant DPSC and MPSC rules and orders (or the Maryland statute) are modified. DPL purchases the electricity required to satisfy its SOS obligations from wholesale suppliers primarily under contracts entered into in accordance with competitive procurement processes approved and supervised by each of the DPSC and the MPSC. DPL also has an obligation to provide HPS for its largest customers in Delaware and its large customers in Maryland. DPL acquires power to supply its HPS customers in the next-day and other short-term PJM RTO markets. As contracts expire, DPL rebids Maryland residential and small commercial contracts semi-annually, Maryland medium sized commercial contracts quarterly and all Delaware customers annually through the approved competitive procurement processes. In Delaware and Maryland, DPL is paid tariff rates for the transmission and distribution of electricity over its transmission and distribution facilities to all electricity customers in its service territories, whether the customer receives SOS or HPS, or purchases electricity from a competitive supplier. In Delaware, DPL is also entitled to recover from its SOS and HPS customers the associated costs of acquiring the electricity (including transmission, capacity and ancillary services costs and costs to satisfy renewable energy requirements), plus an amount referred to as a Reasonable Allowance for Retail Margin. In Maryland, DPL is entitled to recover from its SOS and HPS customers the costs of acquiring the electricity, plus an administrative charge that is intended to allow it to recover its administrative costs, plus a shareholder return, which varies depending on the customer class.

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The following table shows for DPL customers in Delaware and Maryland the percentage of distribution sales (measured in MWh) over the past three fiscal years to SOS customers.

	2015			2014			2013
Delaware		47	%		44	%		44	%
Maryland		53	%		51	%		51	%

Distribution and Supply of Natural Gas

DPL provides regulated natural gas supply and distribution service to customers in a service territory consisting of a major portion of New Castle County in Delaware. This service territory covers approximately 275 square miles and, as of December 31, 2015, had a population of approximately 600,000.

Large volume commercial, institutional, and industrial natural gas customers may purchase natural gas from DPL. Alternatively, a customer receiving a “transportation-only” service from DPL will purchase natural gas from a competitive supplier and have the natural gas delivered through DPL’s distribution facilities. The following table provides certain information regarding DPL’s natural gas distribution business for each of the last three fiscal years.

	2015			2014			2013
	(in thousands, except percentages)
Number of natural gas customers		130			128			126
Thousand cubic feet (Mcf) of natural gas delivered		20,009			21,031			19,796
Percentage of natural gas supplied and delivered by DPL		69	%		69	%		64	%

The following table shows on a percentage basis the allocation among customer types of the Mcf of natural gas delivered by DPL in Delaware in each of the preceding three fiscal years.

	2015			2014			2013
Residential		40	%		41	%		40	%
Commercial and industrial		29	%		29	%		25	%
Transportation and other		31	%		30	%		35	%

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Atlantic City Electric Company

Electricity Distribution and Supply

ACE’s electric distribution service territory consists of Gloucester, Camden, Burlington, Ocean, Atlantic, Cape May, Cumberland and Salem counties in southern New Jersey. The service territory covers approximately 2,700 square miles and had, as of December 31, 2015, a population of approximately 1.1 million. This region is economically diverse and includes the following key industries that contribute to the regional economic base:

• Commercial activities in the region include professional services, government, educational and health services, casinos and tourism.

• Industrial activities in the region include chemical, glass, food processing and oil refining.

The following table provides certain information regarding ACE’s electric distribution business for each of the last three fiscal years.

	2015		2014		2013
	(in thousands)
Number of electric distribution customers		547		546		545
MWh of electricity delivered		9,249		9,051		9,231

The following table shows the allocation by percentage among customer types of the total MWh of electricity delivered by ACE during each of the preceding three fiscal years.

	2015			2014			2013
Residential		47	%		45	%		46	%
Commercial and industrial		53	%		55	%		54	%

ACE has been designated as the default electricity supplier in its service territory by the NJBPU. In New Jersey, each of the state’s electric distribution companies, including ACE, jointly obtains the electricity to meet such companies’ collective BGS obligations from competitive suppliers selected through auctions authorized by the NJBPU for the supply of New Jersey’s total BGS requirements. Each winning bidder is required to supply its committed portion of the BGS customer load with full requirements service, consisting of power supply and transmission service. The following tables show the BGS peak load and percentage of ACE’s total BGS load by customer type during each of the three preceding fiscal years.

	2015			2014			2013
				(megawatts)
Residential and small commercial		1,477			1,511			1,429
Commercial and industrial		81			54			42
	2015			2014			2013
				(% of BGS Load)
Residential and small commercial		95	%		97	%		97	%
Commercial and industrial		5	%		3	%		3	%

ACE is paid tariff supply rates established by the NJBPU that compensate it for the cost of obtaining the BGS supply. These rates are set such that ACE does not make any profit or incur any loss with respect to

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the supply component of its BGS obligations. ACE is also paid tariff rates for the transmission and distribution of electricity over its transmission and distribution facilities to all electricity customers in its service territory, whether the customer receives BGS or purchases electricity from a competitive supplier.

For the year ended December 31, 2015, 55% of ACE’s total distribution sales (measured in MWh) were to BGS customers, as compared to 49% and 48% in 2014 and 2013, respectively.

ACE operates under non-exclusive franchises that have been granted by the NJBPU and under certain non-exclusive consents from municipalities in which ACE provides service. While most of the municipal consents were granted in perpetuity, two of the municipal consents require renewal on a periodic basis in accordance with their terms, and are subject to the ultimate review and approval of the NJBPU. All of the franchises and consents are currently in full force and effect.

Atlantic City Electric Transition Funding LLC

In 2001, ACE established Atlantic City Electric Transition Funding LLC (ACE Funding) solely for the purpose of securitizing authorized portions of ACE’s recoverable stranded costs through the issuance and sale of bonds (Transition Bonds). The proceeds of the sale of each series of Transition Bonds were transferred to ACE in exchange for the transfer by ACE to ACE Funding of the right to collect a non-bypassable transition bond charge (Transition Bond Charge) from ACE customers pursuant to bondable stranded costs rate orders issued by the NJBPU in an amount sufficient to fund the principal and interest payments on the Transition Bonds and related taxes, expenses and fees (Bondable Transition Property). The assets of ACE Funding, including the Bondable Transition Property, and the Transition Bond Charges (representing revenue ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds and related taxes, expenses and fees) collected from ACE’s customers, are not available to creditors of ACE. The holders of Transition Bonds have recourse only to the assets of ACE Funding.

Smart Grid Initiatives

PHI’s utility subsidiaries are engaged in transforming the power grid that they own and operate into a “smart grid,” a network of automated digital devices capable of collecting and communicating large amounts of real-time data. The smart grid benefits PHI utility customers by:

• improving service reliability of the energy distribution system;

• automating specific distribution system functions;

• enabling PHI utilities to restore energy to customers more quickly and efficiently;

• facilitating more efficient use of energy to meet the challenges of rising energy costs and governmental energy reduction goals;

• permitting PHI utilities to obtain and communicate to their customers timely and accurate information regarding energy usage and outages; and

• enhancing communications with utility customers and the overall customer experience.

A central component of the smart grid is AMI, a system that collects, measures and analyzes energy usage data from advanced digital meters, known as “smart meters.” Also critical to the operation of the smart grid is distribution automation technology, which is comprised of automated devices that have internal intelligence and can be controlled remotely to better manage power flow and restore service quickly and more safely. Both the AMI system and distribution automation are enabled by advanced technology that communicates with devices installed on the energy delivery system and transmits energy usage data to the host utility. The implementation of the AMI system and distribution automation involves an integration of technologies provided by multiple vendors.

As of December 31, 2015, Pepco and DPL have completed the installation and activation of smart meters in the District of Columbia, Maryland and Delaware service territories. ACE has yet to receive approval from the NJBPU to proceed with the installation of AMI smart meters.

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The DCPSC, the MPSC and the DPSC approved the creation by PHI’s utility subsidiaries of regulatory assets to defer AMI costs between rate cases and to defer carrying charges on the deferred costs. AMI costs for Pepco in the District of Columbia and DPL in Delaware are being recovered through base rates. For AMI costs incurred by Pepco and DPL in Maryland, pursuant to an MPSC order, recovery will be allowed when the Companies demonstrate that their respective AMI systems are cost-effective. The MPSC’s July 2013 order in Pepco’s November 2012 electric distribution base rate application excluded the cost of AMI meters from Pepco’s rate base until such time as Pepco demonstrates the cost effectiveness of the AMI system. As a result, costs for AMI meters incurred by Pepco and by DPL in Maryland will be treated as other incremental AMI costs incurred in conjunction with the deployment of the AMI system that are deferred and on which a carrying charge is deferred.

Utility Capital Expenditures

PHI’s utility subsidiaries allocate a substantial portion of their total capital expenditures to improving the reliability of their electrical transmission and distribution systems and replacing aging infrastructure throughout their service territories. These activities include:

• Identifying and upgrading under-performing feeder lines;

• Adding new facilities to support load;

• Installing distribution automation systems on both the overhead and underground network systems;

• Rejuvenating and replacing underground residential cables; and

• Replacing equipment at the end of its useful life.

In addition, PHI’s utility subsidiaries allocate capital expenditures to increasing transmission and distribution system capacity, providing resiliency against major storm events, providing operating and system flexibility and installing and upgrading facilities for new and existing customers. For a discussion of PHI’s consolidated capital expenditure plan for 2016 through 2020, see Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity – Capital Requirements – Capital Expenditures.”

District of Columbia Power Line Undergrounding Initiative

In May 2014, the Council of the District of Columbia enacted the Electric Company Infrastructure Improvement Financing Act of 2014 (the Improvement Financing Act), which provides enabling legislation for the District of Columbia Power Line Undergrounding (DC PLUG) initiative. This $1 billion initiative seeks to selectively place underground some of the District of Columbia’s most outage-prone power lines, which lines and surrounding conduit would be owned and maintained by Pepco. A more detailed discussion of the Improvement Financing Act is provided in Note (7), “Regulatory Matters – District of Columbia Power Line Undergrounding Initiative,” to the consolidated financial statements of PHI.

Energy Efficiency Initiatives

Dynamic Pricing

Dynamic pricing provides customers with incentives to reward them for decreasing their energy use during peak energy demand periods, when energy demand and consequently, the cost of supplying electricity, are higher. PHI’s dynamic pricing rate structures, implemented in tandem with PHI’s smart grid, provide customers with billing credits when they reduce their power usage in response to their utility’s request. Dynamic pricing programs include variable peak pricing and critical peak rebate programs.

Dynamic pricing has been approved by the respective public service commissions and is in place for Pepco customers in Maryland and DPL customers in Maryland and Delaware. As of December 31, 2015, approximately 493,000 Pepco customers in Maryland, 168,000 DPL customers in Maryland and 264,000 DPL customers in Delaware have participated in dynamic pricing programs.

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In 2014, the DCPSC rejected Pepco’s proposal for dynamic pricing in the District of Columbia, but expressed interest in exploring dynamic pricing rate structures in future proceedings. Dynamic pricing has not been approved by the NJBPU for ACE’s customers in New Jersey.

Utility Energy Efficiency Programs

Each of Pepco, DPL and ACE has implemented the Energy Wise Rewards™ program, which allows participating customers to reduce energy usage and costs by authorizing the utility to cycle their air conditioner compressors off and on during high energy demand periods. Customers participating in this program in Maryland and the District of Columbia are eligible to receive a credit on their bill while Delaware customers receive compensation through the Peak Energy Savers Program and ACE customers receive a sign up bonus. Pepco and DPL have also implemented a portfolio of energy efficiency programs designed to reduce energy consumption in Maryland, including appliance rebate and recycling, home energy check-ups, rebates on the purchase of energy efficiency equipment and services and discounts on energy efficient light bulbs and lighting fixtures. The MPSC has approved a customer surcharge through 2016 to recover Pepco’s and DPL’s costs associated with these energy efficiency programs.

Pepco Energy Services

Pepco Energy Services is engaged in the following:

• Energy savings performance contracting business: designing, constructing and operating energy efficiency projects and distributed generation equipment, including combined heat and power plants, principally for federal, state and local government customers;

• Underground transmission and distribution business: providing underground transmission and distribution construction and maintenance services for electric utilities in North America; and

• Thermal business: providing steam and chilled water under long-term contracts through systems owned and operated by Pepco Energy Services, primarily to hotel casinos in Atlantic City, New Jersey.

The energy savings performance contracting business is highly competitive, and Pepco Energy Services competes with other energy services companies primarily with respect to contracts with federal, state and local governments and independent agencies. Many of these energy services companies are subsidiaries of larger building controls and equipment providers or utility holding companies. Competitive offerings include a wide range of electrical and thermal system upgrades, improved controls, and generation equipment such as combined heat and power units. Among the factors as to which companies in this business compete are the amount and duration of the guarantees provided in energy savings performance contracts and the quality and value of service provided to customers. In connection with many of Pepco Energy Services’ energy savings performance contracts, Pepco Energy Services provides performance guarantees, including guarantees of a certain level of energy savings. This business is affected by new entrants into the market, the financial strength of customers, governmental directives regarding energy efficiency, energy prices, and general economic conditions. Pepco Energy Services’ backlog of construction contracts in this business decreased to $28 million at December 31, 2015 from $41 million at December 31, 2014. Pepco Energy Services estimates that it will complete the construction of $26 million of the contracts in its 2015 backlog during 2016 and $2 million in 2017.

Most of Pepco Energy Services’ energy savings performance contracts with federal, state and local governments, as well as those with independent agencies, such as housing and water authorities, contain provisions authorizing the governmental authority or independent agency to terminate the contract at any time. Those provisions include explicit mechanisms which, if exercised, would require the other party to pay Pepco Energy Services for work performed through the date of termination and for additional costs incurred as a result of the termination.

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Through its wholly owned subsidiary, W.A. Chester, L.L.C., and its subsidiaries, Pepco Energy Services constructs and maintains underground transmission and distribution projects for electric utilities in North America. W.A. Chester is one of the two largest North American contractors that specializes in the installation and maintenance of pipe-type cable systems, a technology that W.A. Chester believes currently accounts for the majority of existing underground transmission circuit miles in North America. W.A. Chester’s primary competitor in the pipe-type cable system market is UTEC Constructors Corporation, and there are other contractors beginning to enter this market. W.A. Chester also competes in the market for the installation and maintenance of solid dielectric cable, which is a relatively newer technology compared to pipe-type cable systems. The solid dielectric cable installation and maintenance market is highly competitive and composed of numerous different competitors, and the barriers to entry in this market are relatively low. The principal factors for competition in both of these markets are price, experience, customer service and ability to handle a wide range of utility applications. W.A. Chester believes its competitive strengths in both of these markets are the breadth of its experience in working with both technologies in various utility applications (including new installations, modifications, upgrades and maintenance of existing systems), its in-depth knowledge of the U.S. and Canadian utility industries and utility customers’ needs, and its ability to manage successfully all phases of these projects for the customer. W.A. Chester’s backlog of construction contracts decreased to $63 million at December 31, 2015 from $104 million at December 31, 2014. W.A. Chester estimates that it will complete $60 million of the construction contracts in its backlog in 2016 and $3 million in 2017.

Revenues associated with Pepco Energy Services’ combined heat and power thermal generating facilities and operations in Atlantic City are derived from long-term contracts with a few major customers in the Atlantic City hotel and casino industry. The carrying amount of Pepco Energy Services’ long-lived assets in Atlantic City at December 31, 2015 totaled $2 million, after impairment losses aggregating $81 million that were recorded during the third and fourth quarters of 2014. In September 2014, two significant customers of these thermal operations declared Chapter 11 bankruptcy. One of the customers closed operations in September 2014 and Pepco Energy Services continues to provide steam and chilled water service under a contract with lower rates which began April 1, 2015. The second customer terminated its contract with Pepco Energy Services on March 31, 2015. Two other significant customers of the thermal operations declared Chapter 11 bankruptcy in January 2015 and Pepco Energy Services continues to provide service to those customers under existing contracts. Future developments with respect to these and other customers in Atlantic City may require Pepco Energy Services to perform additional impairment analyses of the thermal operations and certain related assets. If these assets are determined to be further impaired, Pepco Energy Services would reduce the carrying value of these assets by the amount of the impairment and record a corresponding non-cash charge to earnings. Moreover, the contract changes and termination referred to above are expected to reduce Pepco Energy Services’ future earnings and cash flows associated with its thermal operations in Atlantic City.

PHI guarantees the obligations of Pepco Energy Services under certain contracts in its energy savings performance contracting business and underground transmission and distribution construction business. At December 31, 2015, PHI’s guarantees of Pepco Energy Services’ obligations under these contracts totaled $269 million. PHI also guarantees the obligations of Pepco Energy Services under surety bonds obtained by Pepco Energy Services for construction projects. These guarantees totaled $177 million at December 31, 2015.

In addition, Atlantic City, New Jersey, while not a customer of Pepco Energy Services, is also facing financial difficulties that could impact Pepco Energy Services customers. Legislation was introduced in the State of New Jersey that would cede control over the city’s finances to the State of New Jersey or the city could declare bankruptcy. It is uncertain at this time as to how this matter will ultimately be resolved or to determine the ramifications of the financial difficulties of Atlantic City on Pepco Energy Services’ customers.

During 2012, Pepco Energy Services deactivated its Buzzard Point and Benning Road oil-fired generation facilities. Pepco Energy Services completed demolition of the Benning Road generation facility in July 2015 and recognized the scrap metal salvage value of the facility as a reduction in its demolition expenses over the life of the project.

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At December 31, 2015, Pepco Energy Services owned five renewable energy generating facilities, with an aggregate generating capacity of 17,400 KW. See Part I, Item 2. “Properties – Generating Facilities” for more information about these facilities.

Discontinued Operations

Through its wholly owned subsidiary PCI, prior to the third quarter of 2013 PHI maintained a portfolio of cross-border energy lease investments. During the third quarter of 2013, PHI completed the termination of its interests in its cross-border energy lease investments. These activities, which previously comprised substantially all of the operations of the Other Non-Regulated segment, have been accounted for as discontinued operations. The remaining operations of the Other Non-Regulated segment, which no longer meet the definition of a separate segment for financial reporting purposes, are included in Corporate and Other. Substantially all of the information in the notes to the consolidated financial statements of PHI with respect to the cross-border energy lease investments has been consolidated in Note (20), “Discontinued Operations – Cross-Border Energy Lease Investments.”

In 2013, Pepco Energy Services completed a previously announced wind-down of its retail electric and retail natural gas supply businesses. These operations are being accounted for as discontinued operations and are no longer a part of the Pepco Energy Services segment for financial reporting purposes. Substantially all of the information in the notes to the consolidated financial statements of PHI with respect to Pepco Energy Services’ retail electric and retail natural gas supply businesses has been consolidated in Note (20), “Discontinued Operations – Retail Electric and Natural Gas Supply Businesses of Pepco Energy Services.”

Global Tax Settlement

On November 18, 2015, PHI entered into a settlement with the Internal Revenue Service (IRS) and the Department of Justice (DOJ) (the Global Tax Settlement) to provide for the resolution of the tax treatment of its previously held cross-border energy lease investments involving public utility assets located outside of the United States structured as sale-in, lease-out, or SILO, transactions. The Global Tax Settlement followed the acceptance by PHI on October 29, 2015 of IRS revenue agent reports covering adjustments incorporated in the terms of the Global Tax Settlement, as well as adjustments for all other tax matters in dispute with the IRS. Also, on November 18, 2015, the DOJ accepted PHI’s offer letter for the settlement of litigation related to the SILO transactions discussed further in Note (16), “Commitments and Contingencies – PHI’s Cross-Border Energy Lease Investments” to the consolidated financial statements of PHI. The Global Tax Settlement and the revenue agent reports, together, effectively close all years open to examination of federal income tax liabilities for PHI through 2011, and all matters associated with the cross-border energy lease investments through 2013.

The Global Tax Settlement, which resolves tax matters related to the cross-border energy lease investments and avoids the costs associated with continued litigation, provides that all depreciation and interest deductions in excess of rental income related to the cross-border energy lease investments were disallowed. The Global Tax Settlement also required PHI to recognize original issue discount income for tax purposes associated with the recharacterization of each of the leases as a loan transaction. Pursuant to the Global Tax Settlement, interest will be assessed with respect to tax underpayments in the relevant years; however, no penalties were assessed against PHI. The Global Tax Settlement provides for the same treatment of the cross-border energy lease investments for the tax years 2012 and 2013 as described above. The last of PHI’s cross-border energy lease investments was terminated in 2013. As a result of the Global Tax Settlement, PHI and the DOJ filed stipulations of dismissal regarding the litigation in the U.S. Court of Federal Claims. The Court dismissed the complaint on November 20, 2015. The Global Tax Settlement is further discussed in Note (11), “Income Taxes” to the consolidated financial statements of PHI.

Seasonality

Power Delivery

The operating results of Power Delivery historically have been directly related to the volume of electricity delivered to its customers, producing higher revenues and net income during periods when customers consumed higher amounts of electricity (usually during periods of extreme temperatures) and lower revenues and net income during periods when customers consumed lower amounts of electricity (usually during periods of mild temperatures). This has been due in part to the longstanding practice of tying the distribution charges paid by customers to kilowatt-hours of electricity used. Because most of the costs associated with the distribution of electricity do not vary with the volume of electricity delivered, this pricing mechanism also contributed to seasonal variations in net income.

As a result of the implementation of a bill stabilization adjustment (BSA) for retail customers of Pepco and DPL in Maryland and for customers of Pepco in the District of Columbia, distribution revenues from utility customers in these jurisdictions have been decoupled from the amount of electricity delivered. Under the BSA, utility customers pay an approved distribution charge for their electric service which does not vary by electricity usage. This change has had the effect of aligning annual distribution revenues more closely with annual distribution costs. In addition, the change has had the effect of eliminating changes in customer electricity usage, whether due to weather conditions or for any other reason, as a factor having an impact on annual distribution revenue and net income in those jurisdictions. The BSA also eliminates what otherwise might be a disincentive for the utility to aggressively develop and promote efficiency programs. A comparable revenue decoupling mechanism proposed for DPL electricity and natural gas

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customers in Delaware is under consideration by the DPSC although there was little activity in this matter in 2015. Distribution revenues are not decoupled for the distribution of electricity by ACE in New Jersey, and thus are subject to variability due to changes in customer consumption.

In contrast to electricity distribution costs, the cost of the electricity supplied, which is the largest component of a customer’s bill, does vary directly in relation to the volume of electricity used by a customer. Accordingly, whether or not a BSA is in effect for the jurisdiction, the revenues of Pepco, DPL and ACE from the supply of electricity and natural gas vary based on consumption and on this basis are seasonal. Because the revenues received by each of the utility subsidiaries for the default supply of electricity and natural gas closely approximate the supply costs, the impact on net income is immaterial, and therefore is not seasonal.

Pepco Energy Services

The energy services business of Pepco Energy Services is not seasonal, except with respect to its thermal operations. The thermal operations of Pepco Energy Services provide steam and chilled water to customers year-round. Steam usage peaks during months with colder temperatures and chilled water usage peaks during months with warmer temperatures. The rates charged customers adjust quarterly for the cost of natural gas used to produce steam and electricity used to produce chilled water. Pepco Energy Services’ revenues and gross profit from its thermal operations will fluctuate based on the volumes of steam and chilled water delivered to customers.

Regulation

The operations of PHI’s utility subsidiaries, including the rates and tariffs they are permitted to charge customers for the transmission and distribution of electricity, and, in the case of DPL, the distribution and transportation of natural gas, are subject to regulation by governmental agencies in the jurisdictions in which the subsidiaries provide utility service as described above in “– PHI’s Utility Subsidiaries.” Rates and tariffs are established by these regulatory commissions.

As further described in Note (1), “Organization,” to the consolidated financial statements of PHI, on April 29, 2014, PHI entered into the Merger Agreement with Exelon and Merger Sub. Subject to certain exceptions, prior to the Merger or the termination of the Merger Agreement, PHI and its subsidiaries may not, without the consent of Exelon, initiate, file or pursue any rate cases, other than pursuing the conclusion of certain proceedings, as described in Note (7), “Regulatory Matters – Rate Proceedings,” to the consolidated financial statements of PHI. To date, PHI has not requested such consent from Exelon and has not filed any new distribution base rate cases since entering into the Merger Agreement.

In addition to the other regulatory matters described elsewhere in this section and in Note (7), “Regulatory Matters,” to the consolidated financial statements of PHI, provided below are summary descriptions of certain regulatory matters involving PHI’s utility subsidiaries.

Mitigation of Regulatory Lag

An important factor in the ability of PHI’s utility subsidiaries to earn their authorized ROE is the willingness of applicable public service commissions to adequately address the shortfall in revenues in a utility’s rate structure due to the delay in time or “lag” between when costs are incurred and when they are reflected in rates. This delay is commonly known as “regulatory lag.” Pepco, DPL and ACE are currently experiencing significant regulatory lag because investments in rate base and operating expenses are increasing more rapidly than their revenue growth.

In an effort to minimize the effects of regulatory lag, prior to the initial execution of the Merger Agreement in April 2014, PHI’s utility subsidiaries had been filing electric distribution base rate cases every nine to twelve months in each of their jurisdictions, pursuing alternative ratemaking mechanisms, evaluating potential reductions in planned capital expenditures, and discussing with the regulatory community and other stakeholders the changing regulatory model economics that are causing regulatory lag.

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As further described in Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations – General Overview – Agreement and Plan of Merger with Exelon Corporation,” PHI entered into the Merger Agreement with Exelon and Merger Sub in April 2014. Subject to certain exceptions, prior to the Merger or the termination of the Merger Agreement, PHI and its subsidiaries may not, without the consent of Exelon, initiate, file or pursue any rate cases, other than concluding pending filings. To date, PHI has not requested such consent from Exelon and has not filed any new distribution base rate cases since entering into the Merger Agreement. Accordingly, PHI’s efforts to mitigate regulatory lag have been delayed pending the closing of the Merger or the termination of the Merger Agreement.

MPSC New Generation Contract Requirement

For information about the MPSC new generation contract requirement, please refer to Note (7), “Regulatory Matters – MPSC New Generation Contract Requirement,” to the consolidated financial statements of PHI.

ACE Standard Offer Capacity Agreements

For information about the ACE Standard Offer Capacity Agreements, please refer to Note (7), “Regulatory Matters – ACE Standard Offer Capacity Agreements,” to the consolidated financial statements of PHI.

Environmental Matters

PHI, through its subsidiaries, is subject to regulation by various federal, regional, state, and local authorities with respect to the environmental effects of its operations, including air and water quality control, solid and hazardous waste disposal, greenhouse gas emissions, and limitations on land use. In addition, federal and state statutes authorize governmental agencies to compel responsible parties to clean up certain abandoned or unremediated hazardous waste sites. PHI’s subsidiaries may incur costs to clean up currently or formerly owned facilities or sites found to be contaminated, as well as other facilities or sites that may have been contaminated due to past disposal practices. PHI’s subsidiaries may also be responsible for ongoing environmental remediation costs associated with facilities or operations that have been sold to third parties as further described in Note (16), “Commitments and Contingencies – Environmental Matters – Conectiv Energy Wholesale Power Generation Sites,” to the consolidated financial statements of PHI.

PHI’s subsidiaries’ currently projected capital expenditures for the replacement of existing or installation of new environmental control facilities that are necessary for compliance with environmental laws, rules or agency orders are approximately $8 million in 2016, $5 million in 2017 and $2 million in 2018. No such expenditures are currently expected in 2019 and beyond. The projections for these capital expenditures could change depending on the outcome of the matters addressed below or as a result of the imposition of additional environmental requirements or new or different interpretations of existing environmental laws, rules and agency orders. In view of the sale of PHI’s competitive wholesale power generation business in 2010 and the deactivation in 2012 of two generating facilities located in the District of Columbia owned by Pepco Energy Services, PHI is no longer significantly affected by air quality and other environmental regulations applicable to electricity generating facilities.

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Air Quality Regulation

The generating facilities owned by Pepco Energy Services were subject to federal, state and local laws and regulations, including the Federal Clean Air Act (CAA), which limit emissions of air pollutants, require permits for operation of facilities and impose recordkeeping and reporting requirements. Following the June 2012 deactivation of Pepco Energy Services’ Buzzard Point and Benning Road oil-fired generating facilities, both of which were considered major sources under the CAA, Pepco Energy Services received authorization in 2013 from the District of Columbia Department of Energy and Environment (DOEE) to terminate the Buzzard Point CAA Title V operating permit and to exclude the Benning Road generating facility from the Benning Road CAA Title V operating permits. At that time, DOEE also agreed to transfer the Benning Road CAA Title V operating permit covering the remaining minor sources (e.g., Pepco-operated emergency generators) to Pepco. After issuing minor source permits for the emergency generators, DOEE terminated the Pepco Energy Services’ Title V permit effective February 27, 2015.

Greenhouse Gas Emissions Reporting

In October 2009, the U.S. Environmental Protection Agency (EPA) adopted regulations requiring sources that emit designated greenhouse gases – specifically, carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons, and other fluorinated gases (e.g., nitrogen trifluoride and hydrofluorinated ethers) – in excess of specified thresholds to file annual reports with EPA disclosing the amount of such emissions. Under these regulations:

• By April 1 of each year, DPL is required to report with respect to its gas distribution operations CO₂ emissions that would result assuming the complete combustion or oxidation of the annual volume of natural gas it distributed to its customers during the previous calendar year. In addition, DPL is required to report fugitive CO₂ and methane emissions for its gas distribution operations for the previous calendar year. DPL’s liquefied natural gas storage facility does not meet the reporting threshold (25,000 metric tons) for fugitive emissions.

• By April 1 of each year, Pepco, DPL and ACE are required to report sulfur hexafluoride emissions from electrical equipment for the previous calendar year.

Water Quality Regulation

Benning NPDES Permit

Provisions of the federal Water Pollution Control Act, also known as the Clean Water Act (CWA), establish the basic legal structure for regulating the discharge of pollutants from point sources (generally confined, discrete conveyances such as pipes) to surface waters of the United States. Among other things, the Clean Water Act requires that any person wishing to discharge pollutants from a point source obtain a National Pollutant Discharge Elimination System (NPDES) permit issued by EPA or by a state agency under a federally authorized state program.

Pepco holds a NPDES permit issued by EPA with a July 19, 2009 effective date, which authorizes discharges from the Benning Road site, including the Pepco Energy Services generating facility previously located on the site that was deactivated in 2012 and has been demolished. The 2009 permit for the first time imposed numerical limits on the allowable concentration of certain metals in storm water discharged from the site into the Anacostia River as determined by EPA to be necessary to meet the applicable District of Columbia surface water quality standards. The permit contemplated that Pepco would meet these limits over time through the use of best management practices (BMPs). As of December 2012, Pepco completed the implementation of the first two phases of BMPs identified in a plan approved by EPA (consisting principally of installing metal absorbing filters to capture contaminants at storm water inlets, removing stored equipment from areas exposed to the weather, covering and painting exposed metal pipes, and covering and cleaning dumpsters). These measures were effective in reducing

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metal concentrations in storm water discharges, but were not sufficient to meet all of the numerical limits for metals. Most of the quarterly monitoring results since the issuance of the permit have shown exceedances of the limits for copper and zinc, as well as occasional exceedances for iron and lead.

The NPDES permit was due to expire on June 19, 2014. Pepco submitted a permit renewal application on December 17, 2013. In November 2014, EPA advised Pepco that it will not renew the permit until the Benning Road site has come into compliance with the existing permit limits. The current permit remains in effect pending EPA’s action on the renewal application. In December 2014, Pepco submitted a plan to EPA to implement the third phase of BMPs recommended in the original permit compliance plan with the objective of achieving full compliance with the permit limits for metals by the end of 2015 and Pepco immediately began to implement the additional BMPs in accordance with the plan. On September 1, 2015, Pepco submitted a report to EPA on the status of implementation of the third phase of BMPs. As of that date, Pepco had fully implemented most of the elements of the Phase 3 plan, including installation of upgraded storm water inlet controls (filters and booms), enhanced inspection and maintenance of inlets, removal of materials and equipment from exposure to storm water, and removal of accumulated sediments from the underground storm drains. The sampling results from the third quarter of 2015 showed compliance with all of the permit limits. The sampling results from the fourth quarter of 2015 showed compliance with all but a single permit limit for metals; where the concentration of copper was below the daily maximum limit but exceeded the monthly average limit. As confirmed by this latest sampling, because the permit limits are low and site conditions are subject to variation, Pepco has concluded that some form of storm water treatment prior to discharge will be necessary to ensure ongoing compliance with all permit limits and has begun the process of evaluating treatment options. The nature and scope of the necessary treatment system, and the amount of the associated capital expenditures, will not be known until Pepco has completed the evaluation and design process.

Pepco has been engaged in discussions with representatives from EPA and the DOJ regarding permit compliance. On October 30, 2015, EPA filed a Clean Water Act civil enforcement action against Pepco in federal district court. Pepco expects that this enforcement action will be resolved through a consent decree that will (i) establish further requirements to achieve compliance with the permit limits, including the design and installation of an appropriate storm water treatment system, as noted above, and (ii) include civil penalties for past noncompliance. Although the amount of such penalties is not known or estimable at this time, Pepco does not expect the amount of such penalties to have a material adverse effect on PHI’s consolidated financial condition, results of operations or cash flows.

Pepco and EPA are currently in discussions regarding the terms of the contemplated consent decree, and it is anticipated that the parties will finalize the consent decree during the first half of 2016. In response to a joint motion by the parties, the court has extended the deadline for Pepco to answer the complaint to May 16, 2016, to give the parties time to work towards agreement on the terms of a consent decree. The parties contemplate seeking a further extension if necessary to complete their negotiations. Once executed by the parties, the consent decree will be filed with the court for review and approval following a period for public comment.

EPA Oil Pollution Prevention Regulations

Facilities that, because of their location, store or use oil and could reasonably be expected to discharge oil into water bodies or adjacent shorelines in quantities that may be harmful to the environment are subject to EPA’s oil pollution prevention regulations. These regulations require entities to prepare and implement Spill Prevention, Control, and Countermeasure (SPCC) plans and specify site-specific measures to prevent and respond to an oil discharge. The SPCC regulations generally require the use of containment and/or diversionary structures to prevent the discharge of oil in the event of a leak or release of oil at the facility. As an alternative to the containment/diversionary structure requirement, owners of certain oil-filled operational equipment, such as electric system transformers, may comply with EPA’s regulations by implementing an inspection and monitoring program, developing an oil spill contingency plan, and providing a written commitment of resources to control and remove any discharge of oil. Pepco, DPL and ACE are complying with the SPCC regulations by employing containment/diversionary structures and by

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means of inspection and monitoring measures, in each case where such measures have been determined to be appropriate. Total costs of complying with these regulations in 2015 for Pepco, DPL and ACE collectively were approximately $7 million. PHI projects total expenditures of approximately $15 million over the next three years for its subsidiaries to comply with these regulations, as shown in the capital expenditure projection set forth in “Environmental Matters” above, all of which are to install additional containment facilities and to replace certain oil-filled breakers with gas-filled breakers to eliminate the possibility of an oil release from such equipment.

EPA Coal Combustion Residuals Regulations

In April 2015, EPA published new regulations regarding coal combustion residuals, commonly known as coal ash, from coal-fired power plants. These regulations set operational performance standards and establish monitoring, recordkeeping and reporting requirements for coal ash disposal facilities. The regulations also support the responsible recycling of coal ash by distinguishing safe and beneficial uses from disposal.

The regulations do not apply to inactive ash landfills that cease receiving coal ash prior to the October 19, 2015 effective date of the regulations. Accordingly, the new regulations will not apply to PHI’s Edge Moor coal ash landfill site, which was retained in the sale of the wholesale power generation business of Conectiv Energy Holdings, Inc. and substantially all of its subsidiaries (Conectiv Energy) to Calpine Corporation in 2010. PHI also does not expect that these regulations will necessitate any changes to Pepco’s technical closure plan for the right-of-way that traverses the Brandywine fly ash disposal site in Brandywine, Prince George’s County, Maryland, because the technical closure plan is designed to comply with the more stringent Maryland landfill closure requirements and because the right-of-way ceased receiving coal ash prior to the regulations’ effective date.

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Hazardous Substance Regulation

The Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA) authorizes EPA, and comparable state laws authorize state environmental authorities, to issue orders and bring enforcement actions to compel responsible parties to investigate and take remedial actions at any site that is determined to present an actual or potential threat to human health or the environment because of an actual or threatened release of one or more hazardous substances. Parties that generated or transported hazardous substances to such sites, as well as the owners and operators of such sites, may be deemed liable under CERCLA or comparable state laws. Each of Pepco, DPL and ACE has been named by EPA or a state environmental agency as a potentially responsible party in pending proceedings involving certain contaminated sites. For additional information on these matters, see Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity – Capital Requirements – Environmental Remediation Obligations,” and Note (16), “Commitments and Contingencies – Environmental Matters,” to the consolidated financial statements of PHI.

Employees

At December 31, 2015, PHI had the following employees:

			In Collective Bargaining Agreements
	Non- union		International Brotherhood of Electrical Workers		International Union of Operating Engineers		Other		Total
Pepco		401		1,105		—		—		1,506
DPL		249		649		—		—		898
ACE		199		361		—		—		560
Pepco Energy Services		160		218		28		34		440
PHI Service Company and Other		1,445		335		—		—		1,780
Total PHI Employees		2,454		2,668		28		34		5,184

PHI’s utility subsidiaries are parties to five collective bargaining agreements with four local unions. Collective bargaining agreements are generally renegotiated every three to five years. All of these collective bargaining agreements were renegotiated in 2014 and were extended through various dates ranging from October 2018 through June 2020.

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Executive Officers of PHI

The names of the executive officers of PHI, their ages and the positions they held as of February 18, 2016, are set forth in the following table. The business experience of each executive officer during at least the past five years is set forth adjacent to his or her name under the heading “Office and Length of Service” in the following table and in the applicable footnote.

Name	Age	Office and Length of Service
Joseph M. Rigby	59	Chairman of the Board 5/09 - Present, President 3/08 - Present, and Chief Executive Officer 3/09 - Present (1)
David M. Velazquez	56	Executive Vice President 3/09 - Present (2)
Kevin C. Fitzgerald	53	Executive Vice President and General Counsel 9/12 - Present (3)
Frederick J. Boyle	58	Senior Vice President and Chief Financial Officer 4/12 - Present (4)
Kenneth J. Parker	53	Senior Vice President, Government Affairs and Corporate Citizenship 9/12 - Present (5)
Thomas H. Graham	55	Vice President 8/13 - Present (6)
Ronald K. Clark	60	Vice President and Controller 8/05 - Present
Laura L. Monica	59	Vice President 8/11 - Present (7)
Hallie M. Reese	52	Vice President, PHI Service Company 5/05 - Present
John U. Huffman	56	President 6/06 - Present, and Chief Executive Officer, Pepco Energy Services, Inc. 3/09 - Present (8)

⁽¹⁾  Mr. Rigby was Chief Operating Officer of PHI from September 2007 until February 28, 2009 and Executive Vice President of PHI from September 2007 until March 2008, Senior Vice President of PHI from August 2002 until September 2007 and Chief Financial Officer of PHI from May 2004 until September 2007. Mr. Rigby was President and Chief Executive Officer of Pepco, DPL and ACE from September 1, 2007 to February 28, 2009. Mr. Rigby has been Chairman of Pepco, DPL and ACE since March 1, 2009. Since October 10, 2014, Mr. Rigby has served as a director of Dominion Midstream GP, LLC, the general partner of Dominion Midstream Partners, LP (NYSE: DM), a publicly-traded limited partnership. On April 29, 2014, PHI entered into that certain Employment Extension Agreement with Mr. Rigby, which extended the term of his employment as PHI’s President and Chief Executive Officer for a period beginning on January 1, 2015 and ending on the first to occur of (1) April 29, 2016, (2) the closing date of the Merger or (3) the date that is six months after the Merger Agreement is terminated.

⁽²⁾  Mr. Velazquez served as President of Conectiv Energy Holding Company, formerly an affiliate of PHI, from June 2006 to February 28, 2009, Chief Executive Officer of Conectiv Energy Holding Company from January 2007 to February 28, 2009 and Chief Operating Officer of Conectiv Energy Holding Company from June 2006 to December 2006.

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⁽³⁾  Mr. Fitzgerald joined PHI in September 2012 as Executive Vice President and General Counsel. From 1997 to 2012, he was a partner with the law firm of Troutman Sanders, LLP in Washington, D.C. Mr. Fitzgerald was Managing Partner of that firm’s Washington, D.C. office from 1999 until 2010 and Executive Partner for Client Development Strategic Planning from 2010 to September 2012.

⁽⁴⁾  Mr. Boyle joined PHI in April 2012 as Senior Vice President and Chief Financial Officer. Prior to such time, he served as Senior Vice President and Chief Financial Officer of DPL Inc. and its wholly owned utility subsidiary, The Dayton Power and Light Company, from December 2010 until its acquisition in 2011. He served as Senior Vice President, Chief Financial Officer and Treasurer of both companies from May 2009 to December 2010, Senior Vice President, Chief Financial Officer, Treasurer and Controller of both companies from December 2008 to May 2009, Vice President, Finance, Chief Accounting Officer and Controller of both companies from June 2008 to November 2008, Vice President, Chief Accounting Officer and Controller of both companies from July 2007 to June 2008, and Vice President and Chief Accounting Officer of both companies from June 2006 to July 2007.

⁽⁵⁾  Mr. Parker became Senior Vice President, Government Affairs and Corporate Citizenship in September 2012. From June 2009 to September 2012, he served as Vice President of Public Policy of PHI. From March 2005 to June 2009, he served as the ACE Region President.

⁽⁶⁾  Mr. Graham became Vice President, People Strategy and Human Resources, in August 2013. From March 2005 to August 2013, he served as the Pepco Region President.

⁽⁷⁾  Ms. Monica joined PHI in August 2011 as Vice President, Corporate Communications. From October 2006 to October 2010, Ms. Monica was Senior Vice President, Corporate Communications at American Water Works Company, Inc. (NYSE: AWK), and from September 1991 to October 2006, Ms. Monica was President of High Point Communications, a strategic communications firm. Ms. Monica rejoined High Point Communications as President from October 2010 to August 2011.

⁽⁸⁾  Mr. Huffman has been employed by Pepco Energy Services since June 2003. He was Chief Operating Officer from April 2006 to February 28, 2009, Senior Vice President from February 2005 to March 2006 and Vice President from June 2003 to February 2005.

Each PHI executive officer is elected annually and serves until his or her respective successor has been elected and qualified or his or her earlier resignation or removal.

Investor Information

Each Reporting Company maintains an Internet web site, at the Internet address listed below:

Reporting Company	Internet Address
PHI	http://www.pepcoholdings.com
Pepco	http://www.pepco.com
DPL	http://www.delmarva.com
ACE	http://www.atlanticcityelectric.com

Each Reporting Company files reports with the SEC under the Exchange Act. Copies of the Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and all amendments to those reports, of each Reporting Company are routinely made available free of charge on PHI’s Internet Web site (http://www.pepcoholdings.com/investors) as soon as reasonably practicable after such documents are electronically filed with or furnished to the SEC. PHI recognizes its website as a key channel of distribution to reach public investors and as a means of disclosing material non-public information to comply with each Reporting Company’s disclosure obligations under SEC Regulation FD. The information contained on the web sites listed above shall not be deemed incorporated into, or to be part of, this Annual Report on Form 10-K, and any web site references included herein are not intended to be made through active hyperlinks.

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Item 1A. RISK FACTORS

The businesses of each Reporting Company are subject to numerous risks and uncertainties, including the events or conditions identified below. The occurrence of one or more of these events or conditions could have an adverse effect on the business of any one or more of the Reporting Companies, including, depending on the circumstances, its financial condition, results of operations and cash flow. Unless otherwise noted, each risk factor set forth below applies to each Reporting Company.

PHI’s utility subsidiaries are subject to comprehensive regulation which significantly affects their operations. PHI’s utility subsidiaries may be subject to fines, penalties and other sanctions for the inability to meet these requirements.

The regulated utilities that comprise Power Delivery are subject to extensive regulation by various federal, state and local regulatory agencies. Each of Pepco, DPL and ACE is regulated by the state agencies for each service territory in which it operates, with respect to, among other things, the manner in which utility service is provided to customers, as well as rates it can charge customers for the distribution and supply of electricity (and, additionally for DPL, the distribution and supply of natural gas). NERC has also established, and FERC has approved, reliability standards with regard to the bulk power system that impose certain operating, planning and cyber security requirements on Pepco, DPL, ACE and Pepco Energy Services. Further, FERC regulates the electricity transmission facilities of Pepco, DPL and ACE.

Approval of these regulators is required in connection with changes in rates and other aspects of the utilities’ operations. These regulatory authorities, and NERC with respect to electric reliability, are empowered to impose financial penalties, fines and other sanctions including setting rates at a level that may be inadequate to permit recovery of costs against the utilities for non-compliance with certain rules and regulations. In this regard, in December 2011, the MPSC sanctioned Pepco related to its reliability in connection with major storm events that occurred in July and August 2010. These sanctions included imposing a fine on Pepco and requiring Pepco to file a work plan detailing, among other things, its reliability improvement objectives and progress in meeting those objectives, while raising the possibility of additional fines or cost recovery disallowances for failing to meet those objectives.

NERC’s eight regional oversight entities, including ReliabilityFirst (RF), of which Pepco, DPL, ACE and Pepco Energy Services are members, and the Northeast Power Coordinating Council (NPCC), of which Pepco Energy Services is a member, are charged with the day-to-day implementation and enforcement of NERC’s standards. RF and NPCC perform compliance audits on entities registered with NERC based on reliability standards and criteria established by NERC. NERC, RF and NPCC also conduct compliance investigations in response to a system disturbance, complaint, or possible violation of a reliability standard identified by other means. Pepco, DPL, ACE and Pepco Energy Services are subject to routine audits and monitoring with respect to compliance with applicable NERC reliability standards, including standards requested by FERC to increase the number of assets (including cyber security assets) subject to NERC cyber security standards that are designated as “critical assets.” From time to time, Pepco, DPL and ACE have entered into settlement agreements with RF resolving alleged violations and resulting in fines. There can be no assurance that additional settlements resolving issues related to RF or NPCC requirements will not occur in the future. The imposition of additional sanctions and civil fines by these enforcement entities could have a material adverse effect on a Reporting Company’s results of operations, cash flow and financial condition.

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PHI’s utility subsidiaries, as well as Pepco Energy Services, are also required to have numerous permits, approvals and certificates from governmental agencies that regulate their businesses. Although PHI believes that each of its subsidiaries has, and each of Pepco, DPL and ACE believes it has, obtained or sought renewal of the material permits, approvals and certificates necessary for its existing operations and that its business is conducted in accordance with applicable laws, PHI is unable to predict the impact that future regulatory activities or changes may have on its business. Changes in or reinterpretations of existing laws or regulations, or the imposition of new laws or regulations, may require any one or more of PHI’s subsidiaries to incur additional expenses or significant capital expenditures or to change the way it conducts its operations.

PHI’s profitability is largely dependent on its ability to recover costs of providing utility services to its customers and to earn an adequate return on its capital investments. The failure of PHI’s utility subsidiaries to obtain timely recognition of costs and earn an adequate return on its capital investments in rates may have a negative effect on PHI’s results of operations and financial condition.

The regulatory authorities that regulate PHI’s utility subsidiaries establish utility rates and tariffs intended to provide each utility the opportunity to obtain revenues sufficient to recover its prudently incurred costs, together with a reasonable return on investor supplied capital. These regulatory authorities also determine how Pepco, DPL and ACE recover from their customers purchased power and natural gas and other operating costs, including transmission and other costs. The utilities cannot change their rates without approval by the applicable regulatory authority. There can be no assurance that the regulatory authorities will consider all costs to have been prudently incurred, nor can there be any assurance that the regulatory process by which rates are determined will always result in rates that achieve full and timely recovery of costs or a just and reasonable rate of return on investments. In addition, if the costs incurred by any of the utilities in operating its business exceed the amounts on which its approved rates are based, the financial results of that utility, and correspondingly PHI, may be adversely affected.

For example, PHI’s utility subsidiaries are exposed to “regulatory lag,” which refers to a shortfall in revenues in a utility’s rate structure due to the delay in time or “lag” between when costs are incurred and when they are reflected in rates. All of PHI’s utilities are currently experiencing significant regulatory lag because their investments in rate base and operating expenses are increasing more rapidly than their revenue growth. PHI anticipates that this trend will continue for the foreseeable future.

Prior to PHI’s April 2014 entry into the Merger Agreement with Exelon, PHI’s utility subsidiaries, in an effort to minimize the effects of regulatory lag, had been filing electric distribution base rate cases every nine to twelve months in each of their jurisdictions, pursuing alternative ratemaking mechanisms, evaluating potential reductions in planned capital expenditures, and discussing with the regulatory community and other stakeholders the changing regulatory model economics that are causing regulatory lag. Any inability of PHI’s utility subsidiaries to mitigate regulatory lag could have a material adverse effect on PHI’s and each utility subsidiary’s business, results of operations, cash flow and financial condition. While the Merger has been pending, none of PHI’s utility subsidiaries has filed any new distribution base rate cases, which is prohibited under the terms of the Merger Agreement without the consent of Exelon; to date, PHI has not requested such consent from Exelon. The absence of the filing of new distribution base rate cases since the entry of into the Merger Agreement in April 2014 and the maintenance of pre-Merger Agreement levels of infrastructure spending has increased the impact of regulatory lag on PHI’s utility subsidiaries.

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Failure to complete the Merger with Exelon could have a material adverse effect on the business, operations, financial condition, results of operations and prospects of PHI and each of its utility subsidiaries, and on the market price of PHI’s common stock.

In August 2015, the DCPSC issued an order denying the merger application as originally filed by PHI and Exelon in the District of Columbia. Following subsequent negotiations with the District of Columbia Government and other interested parties, PHI, Exelon, Pepco and certain of their respective affiliates entered into the DC Settlement Agreement with the District of Columbia Government, the Office of the People’s Counsel and other parties in which Exelon agreed to additional or modified undertakings, conditions and commitments related to the Merger. There can be no assurance, however, that the DCPSC will approve the Merger on the terms set forth in the DC Settlement Agreement or on any other terms.

Under the terms of the Merger Agreement, as amended, either Exelon or Pepco has the right to terminate the Merger Agreement if the DCPSC does not approve the Merger, fails to act on the Merger in accordance with the timetable set forth in the DC Settlement Agreement, approves the Merger subject to conditions that are inconsistent with the terms of the DC Settlement Agreement, or one or more conditions to the closing of the Merger, as set forth in the Merger Agreement, as amended, has not been satisfied or waived on or before March 4, 2016 (the 151st day following the filing of the DC Settlement Agreement with the DCPSC). The termination of the Merger Agreement would likely have a negative impact on the trading price of PHI’s common stock.

The termination of the Merger Agreement could also have a material adverse effect on the business, operations, financial condition, results of operations and prospects of PHI and each of its utility subsidiaries. Since the execution of the Merger Agreement in April 2014, each of PHI’s utility subsidiaries has not filed any new distribution base rate cases, thereby foregoing rate increases that they might otherwise have sought, and has maintained its pre-Merger Agreement level of infrastructure spending in its service territory. As a consequence, if the Merger is not completed, PHI and each of its utility subsidiaries expect that they will be required to undertake certain actions to address their ongoing results of operations and financial condition. These actions are likely to include, but may not be limited to, a decrease in capital and operational and maintenance expenditures, and a reevaluation of PHI’s common stock dividend policy.

The operating results of Power Delivery fluctuate on a seasonal basis and can be adversely affected by changes in weather.

The Power Delivery business historically has been seasonal and, as a result, weather has had a material impact on its operating performance. Demand for electricity is generally higher in the summer months associated with cooling and demand for electricity and natural gas is generally higher in the winter months associated with heating as compared to other times of the year. Accordingly, each of PHI, Pepco, DPL and ACE historically has generated less revenue and income when temperatures are warmer in the winter and cooler in the summer. In addition, severe weather conditions can produce storms that cause extensive damage to the transmission and distribution systems, as well as related facilities, that can require the utilities to incur additional operation and maintenance expense, as well as capital expenditures. These additional costs can be significant and the rates charged to customers may not always be timely or adequately adjusted to reflect these higher costs.

In the District of Columbia and Maryland, Pepco and DPL are subject to a bill stabilization adjustment mechanism applicable to retail customers, which decouples distribution revenue for a given reporting period from the amount of power delivered during the period. The bill stabilization mechanism has the effect in those jurisdictions of reducing the impact of changes in the use of electricity by retail customers due to weather conditions or for other reasons on reported distribution revenue and income. A comparable revenue decoupling mechanism for DPL electricity and natural gas customers in Delaware is under consideration by the DPSC. In those jurisdictions that have not adopted a bill stabilization adjustment or similar mechanism, operating results continue to be affected by weather conditions.

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Facilities and related systems may not operate as planned or may require significant capital or operation and maintenance expenditures, which could decrease revenues or increase expenses.

Operation of the Pepco, DPL and ACE transmission and distribution facilities and related systems involves many risks, including: the breakdown or failure of equipment; accidents; labor disputes; theft of copper wire or pipe; failure of computer systems, software or hardware; and performance below expected levels. Older facilities, systems and equipment, even if maintained in accordance with sound engineering practices, may require significant capital expenditures for additions or upgrades to provide reliable operations or to comply with changing environmental requirements. Thefts of copper wire or pipe increase the likelihood of poor system voltage control, electricity and streetlight outages, damage to equipment and property, and injury or death, as well as increasing the likelihood of damage to fuel lines, which can create an unsafe and potentially explosive condition. Natural disasters and weather, including tornadoes, hurricanes and snow and ice storms, also can disrupt transmission and distribution systems. Disruption of the operation of transmission or distribution facilities and related systems can reduce revenues and result in the incurrence of additional expenses that may not be recoverable from customers or through insurance.

Upgrades and improvements to computer systems and networks may require substantial amounts of management’s time and financial resources to complete, and may also result in system or network defects or operational errors due to employees’ inexperience of using a new or upgraded system. In January 2015, PHI’s utility subsidiaries implemented an integrated customer billing and information management system to replace separate existing legacy customer billing and information systems. There can be no assurance that this new system will not cause disruptions to the utility subsidiaries’ operations, which disruptions, if not anticipated and appropriately mitigated, could harm their business (individually or collectively) and have a material adverse effect on their results of operations, financial condition and cash flows.

Energy companies are subject to adverse publicity and reputational risks, which make them vulnerable to negative customer perception and could lead to increased regulatory oversight or other sanctions.

Utility companies, including PHI’s utility subsidiaries, have a large consumer customer base and as a result have been the subject of public criticism focused on the reliability of their distribution services and the speed with which they are able to respond to outages caused by storm damage or other unanticipated events. Adverse publicity of this nature may render legislatures and other governing bodies, public service commissions and other regulatory authorities, and government officials less likely to view energy companies such as PHI and its subsidiaries in a favorable light, and may cause PHI and its subsidiaries to be susceptible to less favorable legislative and regulatory outcomes, as well as increased regulatory oversight and more stringent regulatory requirements. Unfavorable regulatory outcomes can include the enactment of more stringent laws and regulations governing PHI’s operations, such as reliability and customer service quality standards or vegetation management requirements, as well as fines, penalties or other sanctions or requirements. The imposition of any of the foregoing could have a material negative impact on PHI’s and each utility subsidiary’s business, results of operations, cash flow and financial condition.

Unfavorable regulatory developments and compliance with new or more rigorous regulatory requirements may subject PHI’s utility subsidiaries to higher operating costs.

PHI’s utility subsidiaries are subject to and will continue to be subject to changing regulatory requirements, including those related to reliability and customer service, in the various jurisdictions in which they operate. For example, in 2012, the MPSC adopted rules establishing reliability and customer service requirements. In April 2015, both Pepco and DPL filed corrective action plans with the MPSC to address noncompliance in 2014 with certain of these reliability requirements. Both Pepco and DPL expect to file annual reports in April 2016 indicating that it has not complied with certain of these requirements for 2015. In addition, in July 2011, the DCPSC adopted regulations that establish specific maximum outage frequency and outage duration levels beginning in 2013 and continuing through 2020 and

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thereafter and are intended to require Pepco to achieve a reliability level in the first quartile of all utilities in the nation by 2020. The reliability standards permit Pepco to petition the DCPSC to reevaluate these standards for the period from 2016 to 2020 to address feasibility and cost issues.

Each of Pepco and DPL may incur significant operating and maintenance and capital expenses to comply with these requirements. Furthermore, each of Pepco and DPL could be subject to civil penalties or other sanctions if it does not meet the required performance or reliability standards. Other jurisdictions in which PHI’s utility subsidiaries have operations have already adopted or may in the future adopt reliability and customer service quality standards, the violation of which could also result in the imposition of penalties, fines and other sanctions. Compliance, and any failure to comply, with current, proposed or future regulatory requirements may have a material adverse effect on PHI and each utility subsidiary’s business, results of operations, cash flow and financial condition.

Power Delivery’s transmission facilities are interconnected with the facilities of other transmission facility owners. Failures of neighboring transmission systems could have a negative impact on Power Delivery’s operations.

The electricity transmission facilities of Pepco, DPL and ACE are interconnected with the transmission facilities of neighboring utilities and are part of the interstate power transmission grid. Pepco, DPL and ACE are members of the PJM RTO, a regional transmission organization that operates the portion of the interstate transmission grid that includes the PHI transmission facilities. Although PJM’s systems and operations are designed to ensure the reliable operation of the transmission grid and prevent the operations of one utility from having an adverse impact on the operations of the other utilities, there can be no assurance that service interruptions originating at other utilities will not cause interruptions in the Pepco, DPL or ACE service territories. Thus, due to the interconnected nature of the interstate power transmission grid, an outage in a neighboring utility could trigger a system outage in either Pepco, DPL or ACE. If Pepco, DPL or ACE were to suffer such a service interruption, it could have a negative impact on its and PHI’s business, results of operations, cash flow and financial condition.

Changes in technology, distributed generation and conservation measures may adversely affect Power Delivery.

Increased conservation and end-user generation made possible through current or future advances in technology, such as through fuel and solar (photovoltaic) cells, wind power and microturbines, could reduce demand for the transmission and distribution facilities of Power Delivery and adversely affect the results of operations of PHI and one or more of its utility subsidiaries. Alternative technologies that produce electricity, the development of which has expanded due to climate change and other environmental concerns, could ultimately provide alternative sources of electricity and permit current customers to adopt distributed generation systems which would allow them to generate electricity for their own use. As these and other technologies are created, developed and improved, the quantity and frequency of electricity usage by customers could decline, which could have a negative impact on the business, results of operations, cash flow and financial condition of PHI or its utility subsidiaries.

The cost of compliance with environmental laws is significant and implementation of new and existing environmental laws may increase operating costs.

The operations of PHI’s subsidiaries are subject to extensive federal, state and local environmental laws and regulations relating to air quality, water quality, spill prevention, waste management, natural resource protection, site remediation, greenhouse gas emissions and health and safety. These laws and regulations may require significant capital and other expenditures to, among other things, meet emissions and effluent standards, conduct site remediation, complete environmental studies and perform environmental monitoring. If a company fails to comply with applicable environmental laws and regulations, even if caused by factors beyond its control, such failure could result in the assessment of civil or criminal penalties and liabilities and the need to expend significant sums to achieve compliance.

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In addition, PHI’s subsidiaries are required to obtain and comply with a variety of environmental permits, licenses, inspections and other approvals. If there is a delay in obtaining any required environmental regulatory approval, or if there is a failure to obtain, maintain or comply with any such approval, operations at affected facilities could be halted or subjected to additional costs.

Changes in tax laws or their application, as well as the difficulty in quantifying potential tax effects of business decisions, could negatively impact a Reporting Company’s liquidity, financial condition, or results of operations.

Each Reporting Company is required to make judgments regarding the potential tax effects of its business operations and the financial and other transactions in which it engages in order to estimate its associated federal, state and local tax obligations. Such tax obligations include income, real estate, sales and use taxes and employment-related taxes. These judgments may be subject to challenge by the IRS or other taxing authorities. While each of the Reporting Companies is required to establish reserves to account for uncertain tax positions, the determination of the amount of such reserves also requires an exercise of judgment, and the amount of the reserve may be insufficient to cover the taxes that ultimately are determined to be due. Adverse tax authority rulings or unfavorable settlements with tax authorities involving matters for which an insufficient reserve has been established or involving other tax matters could have a material adverse effect on a Reporting Company’s liquidity, financial condition, and results of operations.

Changes in local, state, or federal tax laws or rates also could have adverse impacts on a Reporting Company’s liquidity, financial condition, and results of operations.

Failure to retain and attract key skilled and properly motivated professional and technical employees could have an adverse effect on operations.

PHI and its subsidiaries operate in a highly regulated industry that requires the continued operation of sophisticated systems and technology. One of the challenges they face in implementing their business strategy is to attract, motivate and retain a skilled, efficient and cost-effective workforce while recruiting new talent to replace losses in knowledge and skills due to retirements, particularly in light of the delays experienced in connection with the Merger approval process. Over the course of the next three years, PHI estimates that approximately one-third of this skilled workforce will reach retirement age. Competition for skilled employees in some areas is high and the inability to attract and retain these employees, especially as existing skilled workers retire in the near future, could adversely affect the business, operations and financial condition of PHI or the affected company.

PHI’s subsidiaries are subject to collective bargaining agreements that could impact their business and operations.

As of December 31, 2015, 53% of employees of PHI and its subsidiaries, collectively, were represented by various labor unions. PHI’s utility subsidiaries are parties to five collective bargaining agreements with four local unions that represent these employees. Collective bargaining agreements are generally renegotiated every three to five years, and the risk exists that there could be a work stoppage after expiration of an agreement until a new collective bargaining agreement has been reached. Labor negotiations typically involve bargaining over wages, benefits and working conditions, including management rights. Although PHI believes that protracted work stoppages are unlikely, such an event could result in a disruption of the operations of the affected utility, which could, in turn, have a material adverse effect upon the business, results of operations, cash flow and financial condition of the affected utility and PHI.

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Pepco Energy Services’ thermal business in Atlantic City, New Jersey is dependent upon a few large customers and the loss of one or more of its significant customers would have a material adverse effect on Pepco Energy Services’ results of operations and cash flow. (PHI only)

Revenues associated with Pepco Energy Services’ combined heat and power thermal generating facilities and operations in Atlantic City are derived from long-term contracts with a few major customers in the Atlantic City hotel and casino industry. The carrying amount of Pepco Energy Services’ long-lived assets in Atlantic City at December 31, 2015 totaled $2 million, after impairment losses aggregating $81 million that were recorded during the third and fourth quarters of 2014. In September 2014, two significant customers of these thermal operations declared Chapter 11 bankruptcy. One of the customers closed operations in September 2014 and Pepco Energy Services continues to provide steam and chilled water service under a contract with lower rates which began April 1, 2015. The second customer terminated its contract with Pepco Energy Services on March 31, 2015. Two other significant customers of the thermal operations declared Chapter 11 bankruptcy in January 2015 and Pepco Energy Services continues to provide service to those customers under existing contracts. Future developments with respect to these and other customers in Atlantic City may require Pepco Energy Services to perform additional impairment analyses of the thermal operations and certain related assets. If these assets are determined to be further impaired, Pepco Energy Services would reduce the carrying value of these assets by the amount of the impairment and record a corresponding non-cash charge to earnings. Moreover, the contract changes and termination referred to above are expected to reduce Pepco Energy Services’ future earnings and cash flows associated with its thermal operations in Atlantic City.

Under its energy savings performance contracts, Pepco Energy Services is responsible for maintaining, repairing and replacing energy equipment, which obligations may require Pepco Energy Services to incur significant costs many years after an installation of a project is completed. (PHI only)

Pepco Energy Services owns energy equipment and is also responsible for operating and maintaining additional energy equipment that it does not own. In addition, it is generally Pepco Energy Services’ responsibility to repair or replace this energy equipment in the event of a failure. These equipment maintenance, repair and replacement obligations could be material and could adversely affect PHI’s results of operations, cash flow and financial condition.

Pepco Energy Services’ obligations in connection with its combined heat and power and underground transmission construction projects, energy savings construction projects and energy savings performance contracts may have a material adverse effect on PHI. (PHI only)

Pepco Energy Services has undertaken projects which include design, construction, startup and testing activities related to combined heat and power, underground transmission and energy savings construction projects, pursuant to guaranteed maximum price or fixed-price contracts. Pepco Energy Services will generally secure commitments from subcontractors and vendors to perform within contract pricing commitments, equipment-performance standards, jobsite safety requirements, and other key parameters. Under a number of these projects, the customer of Pepco Energy Services has required Pepco Energy Services to obtain surety bonds securing the performance of Pepco Energy Services, or its subcontractors or vendors. PHI has been required to guarantee the performance of Pepco Energy Services under the surety bonds and certain of these construction contracts. PHI also guarantees the obligations of Pepco Energy Services under certain of its energy savings performance contracts. At December 31, 2015, PHI’s guarantees of Pepco Energy Services’ obligations under its energy savings performance, combined heat and power, and construction contracts totaled $269 million, and PHI’s guarantees of Pepco Energy Services’ obligations under surety bonds for construction projects totaled $177 million.

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As a result, PHI may bear responsibility in the event of unexcused failures by Pepco Energy Services or its subcontractors or vendors to perform in accordance with the terms of these contracts, or if the customer does not realize the energy savings provided for in a performance contract. When such events occur, Pepco Energy Services and PHI may experience reputational harm and claims for money damages and other relief that may be sought in connection with such contracts, guarantees and surety bonds, which could, depending upon the nature of the claim and the amount of damages or other relief sought, have a material adverse effect upon Pepco Energy Services’ and PHI’s business, results of operations, cash flow and financial condition.

If PHI is not successful in mitigating the risks inherent in its business, its operations could be adversely affected.

PHI and its subsidiaries are faced with a number of different types of risk. PHI confronts legislative, regulatory policy, compliance and other risks, including:

• PHI’s inability to timely recover capital and operating costs, which may result in a shortfall in revenues;

• resource planning and other long-term planning risks, including resource acquisition risks, which may hinder PHI’s ability to maintain adequate resources;

• financial risks, including credit, interest rate and capital market risks, which could increase the cost of capital or make raising capital more difficult; and

• macroeconomic risks, and risks related to economic conditions and changes in demand for electricity and natural gas in the service territories of PHI’s utility subsidiaries (including changes due to or in connection with the loss of one or more commercial customers of a utility subsidiary), as well as with respect to Pepco Energy Services’ business, which could negatively impact the operations of the affected business.

PHI management seeks to mitigate the risks inherent in the implementation of PHI’s business strategy through its established risk mitigation process, which includes adherence to PHI’s business policies and other compliance policies, operation of formal risk management structures and groups, and overall business management. PHI management is responsible for identifying, assessing and managing risks, and developing risk-management strategies, while the Board of Directors and its various committees oversee the assessment, management and mitigation of risk. However, there can be no assurance these risk mitigation efforts will adequately address all such risks or that such efforts will be successful, and a failure to successfully identify, assess, manage or mitigate such risks may have a material adverse effect on the business, results of operations, cash flow or financial condition of one or more of the Reporting Companies.

PHI and its subsidiaries are exposed to contractual and credit risks associated with certain of their operations.

PHI and its subsidiaries are subject to a number of contractual and credit risks associated with certain of their operations. To mitigate contractual or credit risk, PHI or a subsidiary may give to or receive from the counterparty collateral or other types of performance assurance, which may be in the form of cash, letters of credit or parent guarantees, to protect against performance and credit risk. Even where collateral is provided, capital market disruptions, the lowered rating or insolvency of the issuer or guarantor, changes in the power supply other market prices and other events may prevent a party from being able to meet its obligations or may degrade the value of collateral, letters of credit and guarantees, and the collateral, guarantee or other performance assurance provided may prove insufficient to protect against all losses that a party may ultimately suffer. In the event of a bankruptcy of a counterparty to any contract to which PHI or any of its subsidiaries is a party, bankruptcy law, in some circumstances, could require the surrender of collateral or other guarantees held or payments received.

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Business operations could be adversely affected by physical and cyber attacks.

The threat of, or actual acts of, physical or cyber attacks may affect the operations of PHI and its subsidiaries in unpredictable ways and may cause changes in the insurance markets, force an increase in security measures and cause electrical disruptions or disruptions of fuel supplies and markets, including natural gas. Utility industry operations require the continued deployment and utilization of sophisticated information technology systems and network infrastructure. While PHI has implemented protective measures designed to mitigate its vulnerability to physical and cyber threats and attacks, such protective measures, and technology systems generally, are vulnerable to disability or failure due to cyber attack, acts of war or terrorism, and other causes. As a result, there can be no assurance that such protective measures will be completely effective in protecting PHI’s infrastructure or assets from a physical or cyber attack or the effects thereof. If any of the infrastructure facilities of PHI’s subsidiaries, including their transmission or distribution facilities, were to be a direct target, or an indirect casualty, of an act of terrorism or a cyber attack, the operations of PHI, Pepco, DPL or ACE could be adversely affected. Furthermore, any threats or actions that negatively impact the physical security of the facilities of PHI or its subsidiaries, or the integrity or security of their computer networks and systems (and any programs or data stored thereon or therein), could adversely affect the ability of PHI or its subsidiaries to manage these facilities, networks, systems, programs and data efficiently or effectively, which in turn could have a material adverse effect on PHI’s or its subsidiaries’ results of operations and financial condition. In addition, any theft, loss or fraudulent use of customer, stockholder, employee or proprietary data as a result of a cyber attack or otherwise could subject PHI or its subsidiaries to significant litigation, liability and costs, as well as adversely impact PHI’s or its utility subsidiaries’ reputation with customers, stockholders and regulators, among others. Corresponding instability in the financial markets as a result of threats or acts of terrorism or threatened or actual cyber attacks also could adversely affect the ability of PHI or its subsidiaries to raise needed capital.

New accounting standards or changes to existing accounting standards could materially impact how a Reporting Company reports its results of operations, cash flow and financial condition.

Each Reporting Company’s financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). The SEC, the Public Company Accounting Oversight Board, the Financial Accounting Standards Board (FASB) or other authoritative bodies or governmental entities may issue new pronouncements or new interpretations of existing accounting standards that may require the Reporting Companies to change their accounting policies. These changes are beyond the control of the Reporting Companies, can be difficult to predict and could materially impact how they report their results of operations, cash flow and financial condition. Each Reporting Company could be required to apply a new or revised standard retroactively, which could adversely affect its results of operations, cash flow and financial condition.

Undetected errors in internal controls and information reporting could result in the disallowance of cost recovery and noncompliant disclosure.

Each Reporting Company’s internal controls, accounting policies and practices and internal information systems are designed to enable the Reporting Company to capture and process transactions and information in a timely and accurate manner in compliance with GAAP, taxation requirements, federal securities laws and regulations and other laws and regulations (including pursuant to federal and state administrative grant programs) applicable to it. Such compliance permits each Reporting Company to, among other things, disclose and report financial and other information in connection with the recovery of its costs and with the reporting requirements for each Reporting Company under federal securities, tax and other laws and regulations.

Each Reporting Company has implemented corporate governance, internal control and accounting policies and procedures in connection with the Sarbanes-Oxley Act of 2002 (the Sarbanes-Oxley Act) and relevant SEC rules, as well as other applicable regulations. Such internal controls and policies have been and continue to be closely monitored by each Reporting Company’s management and PHI’s Board of

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Directors to ensure continued compliance with these laws, rules and regulations. Management is also responsible for establishing and maintaining internal control over financial reporting and is required to assess annually the effectiveness of these controls. While PHI believes these controls, policies, practices and systems are adequate to verify data integrity, unanticipated and unauthorized actions of employees or temporary lapses in internal controls due to shortfalls in oversight or resource constraints could lead to undetected errors that could result in the disallowance of cost recovery and noncompliant disclosure and reporting. The consequences of these events could have a negative impact on the results of operations and financial condition of the affected Reporting Company. The inability of management to certify as to the effectiveness of these controls due to the identification of one or more material weaknesses in these controls could also increase financing costs or could also adversely affect the ability of a Reporting Company to access the capital markets.

Insurance coverage may not be sufficient to cover all casualty, property or other losses that PHI and its subsidiaries might incur.

PHI and its subsidiaries, including Pepco, DPL and ACE, as well as Pepco Energy Services, currently have insurance coverage for their facilities and operations in amounts and with deductibles that they consider appropriate. However, there is no assurance that such insurance coverage will be available in the future on commercially reasonable terms or at all. In addition, some risks and losses, such as weather related casualties, may not be insurable, and, where a risk has been insured, a risk or loss may be deemed to be excluded from coverage or coverage may otherwise be denied in whole or in part. PHI has also obtained insurance to provide coverage for a portion of the losses and damages that may result from a security breach of its or its utility subsidiaries’ information technology systems. In the case of loss or damage to property, plant, equipment, data or other assets, there is no assurance that the insurance proceeds received, if any, will be sufficient to cover the entire loss, including costs of replacement or repair.

PHI and its subsidiaries are dependent on obtaining access to the capital markets and bank financing to satisfy their capital and liquidity requirements. The inability to obtain required financing when needed would have an adverse effect on their respective businesses.

PHI and its subsidiaries, including Pepco, DPL and ACE, have significant capital requirements, including the funding of construction expenditures and the refinancing of maturing debt. Each of the Reporting Companies relies primarily on cash flow from operations, access to the capital markets and medium- and long-term bank financing, to meet these long-term financing needs. The operating activities of PHI and its subsidiaries also require continued access to short-term sources of liquidity, including issuances by a Reporting Company of commercial paper and access to money markets and short-term bank financing, to provide for short-term liquidity needs that are not met by cash flows from their operations. Adverse business developments or market disruptions could increase the cost of financing or prevent PHI or any of its subsidiaries from accessing these sources of short-term and long-term capital. Events that could cause or contribute to a disruption of the financial markets include, but are not limited to:

• a recession or an economic slowdown;

• the bankruptcy of one or more energy companies or financial institutions;

• a significant change in energy prices;

• a physical or cyber attack or threatened attacks;

• the outbreak of a pandemic or other similar event; or

• a significant electricity or natural gas transmission disruption.

Any reductions in or other actions with respect to the credit ratings of PHI or any of its subsidiaries could increase its financing costs and the cost of maintaining certain contractual relationships.

Nationally recognized rating agencies currently rate each Reporting Company and debt securities issued by each Reporting Company. Ratings are not recommendations to buy or sell securities. PHI or its

38

subsidiaries may, in the future, incur new indebtedness with interest rates that may be affected by changes in or other actions associated with these credit ratings. Each of the rating agencies reviews its ratings periodically, and previous ratings may not be maintained in the future. Rating agencies may also place a Reporting Company under review for potential downgrade in certain circumstances or if any of them seek to take certain actions that it believes would otherwise be in its best interests. A downgrade of these debt ratings or other negative action, such as a review for a potential downgrade, could affect the market price of existing indebtedness and the ability to raise additional debt without incurring increases in the cost of capital. In addition, a downgrade of these ratings, or other negative action, could make it more difficult to raise capital to refinance any maturing debt obligations, to support business growth and to maintain or improve the current financial strength of PHI’s business and operations.

The agreements that govern PHI’s primary credit facility contain a consolidated indebtedness covenant that may limit discretion of each borrower to incur indebtedness or reduce its equity.

Under the terms of PHI’s primary credit facility, of which each Reporting Company is a borrower, the consolidated indebtedness of a borrower cannot exceed 65% of its consolidated capitalization. If a borrower’s equity were to decline or its debt were to increase to a level that caused its debt to exceed this limit, lenders under the credit facility would be entitled to refuse any further extension of credit and to declare all of the outstanding debt under the credit facility immediately due and payable. To avoid such a default, a waiver or renegotiation of this covenant would be required, which would likely increase funding costs and could result in additional covenants that would restrict each Reporting Company’s operational and financing flexibility.

Each borrower’s ability to comply with this covenant is subject to various risks and uncertainties, including events beyond the borrower’s control. For example, events that could cause a reduction in PHI’s equity include, without limitation, potential IRS taxes, interest and penalties associated with PHI’s former cross-border energy lease investments or a significant write-down of PHI’s goodwill. Even if each borrower is able to comply with this covenant, the limitations on its operational and financial flexibility could harm its and PHI’s business by, among other things, limiting the borrower’s ability to incur indebtedness or reduce equity in connection with financings or other corporate opportunities that it may believe would be in its best interests or the interests of PHI’s stockholders to complete.

PHI’s cash flow, ability to pay dividends and ability to satisfy debt obligations depend on the performance of its regulated and competitive operating subsidiaries, access to the capital markets and other sources of liquidity. PHI’s unsecured obligations are effectively subordinated to the liabilities of its subsidiaries. (PHI only)

PHI is a holding company that conducts its operations entirely through its regulated and competitive subsidiaries, and all of PHI’s consolidated operating assets are held by its subsidiaries. Accordingly, PHI’s cash flow, its ability to satisfy its obligations to creditors and its ability to pay dividends on its common stock are dependent upon the earnings of its subsidiaries, each Reporting Company’s access to the capital markets and all sources of cash flow and liquidity that may be available to PHI. PHI’s subsidiaries are separate legal entities and have no obligation to pay any amounts due on any debt or dividends on equity securities issued by PHI or to make any funds available for such payments. The ability of PHI’s subsidiaries to pay dividends and make other payments to PHI may be restricted by, among other things, applicable corporate, tax and other laws and regulations and agreements made by PHI and its subsidiaries, including under the terms of indebtedness, and PHI’s financial objective of maintaining a common equity ratio at its utility subsidiaries of between 49% and 50%. Because the claims of the creditors of PHI’s subsidiaries are superior to PHI’s entitlement to dividends, the unsecured debt and obligations of PHI are effectively subordinated to all existing and future liabilities of its subsidiaries, including trade creditors. In addition, claims of creditors, including trade creditors, of PHI’s subsidiaries will generally have priority with respect to the assets and earnings of such subsidiaries over the claims of PHI’s creditors.

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PHI has a significant goodwill balance related to its Power Delivery business. A determination that goodwill is impaired could result in a significant non-cash charge to earnings.

PHI had a goodwill balance at December 31, 2015, of approximately $1.4 billion, primarily attributable to Pepco’s acquisition of Conectiv (now Conectiv, LLC, to be referred to herein as Conectiv) in 2002. An impairment charge must be recorded under GAAP to the extent that the implied fair value of goodwill is less than the carrying value of goodwill, as shown on the consolidated balance sheet. PHI is required to test goodwill for impairment at least annually and whenever events or changes in circumstances indicate that the carrying value may not be recoverable. Factors that may result in an interim impairment test include, but are not limited to: an adverse change in business conditions; a protracted decline in stock price causing market capitalization to fall significantly below book value; an adverse regulatory action; impairment of long-lived assets in the reporting unit; or a change in identified reporting units. If PHI were to determine that its goodwill is impaired, PHI would be required to reduce its goodwill balance by the amount of the impairment and record a corresponding non-cash charge to earnings. Depending on the amount of the impairment, an impairment determination could have a material adverse effect on PHI’s financial condition, results of operations and cash flow.

The funding of future defined benefit pension plan and post-retirement benefit plan obligations is based on assumptions regarding the valuation of future benefit obligations and the projected performance of plan assets. If market performance decreases plan assets or changes in assumptions regarding the valuation of benefit obligations increase plan liabilities, any of the Reporting Companies may be required to make significant cash contributions to fund these plans.

PHI holds assets in trust to meet its obligations under PHI’s defined benefit pension plan and its post-retirement benefit plan. The amounts that PHI is required to contribute (including the amounts for which Pepco, DPL and ACE are responsible) to fund the trusts are determined based on assumptions made as to the valuation of future benefit obligations, and the projected investment performance of the plan assets. Accordingly, the performance of the capital markets will affect the value of plan assets. A decline in the market value of plan assets as well as a decline in the rate of return on plan assets may increase the plan funding requirements to meet the future benefit obligations. In addition, changes in interest rates affect the valuation of the liabilities of the plans. As interest rates decrease, the present value of the liabilities increase, potentially requiring additional funding. Demographic changes, such as a change in the expected timing of retirements or changes in life expectancy assumptions, also may increase the funding requirements of the plans. A need for significant additional funding of the plans could have a material adverse effect on the cash flows of any of the Reporting Companies. Future increases in pension plan and other post-retirement benefit plan costs, to the extent they are not recoverable in the base rates of PHI’s utility subsidiaries, could have a material adverse effect on the results of operations, cash flow and financial condition of any of the Reporting Companies.

Provisions of the Delaware General Corporation Law and in PHI’s constituent documents may discourage an acquisition of PHI. (PHI only)

PHI is governed by the provisions of Section 203 of the Delaware General Corporation Law, which prohibit a public Delaware corporation from engaging in a business combination with an interested stockholder (as defined in Section 203) for a period commencing three years from the date in which the person became an interested stockholder, unless:

• the board of directors approved the transaction which resulted in the stockholder becoming an interested stockholder;

• upon consummation of the transaction which resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of the voting stock of the corporation (excluding shares owned by officers, directors, or certain employee stock purchase plans); or

• at or subsequent to the time the transaction is approved by the board of directors, there is an affirmative vote of at least 66 2/3% of the outstanding voting stock not owned by the interested stockholder approving the transaction.

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Section 203 could prohibit or delay mergers or other takeover attempts against PHI, and accordingly, may discourage or prevent attempts to acquire or control PHI through a tender offer, proxy contest or otherwise. Section 203 does not apply to the Merger.

In addition, and notwithstanding the proposed Merger with Exelon, PHI’s restated certificate of incorporation and amended and restated bylaws contain provisions that may discourage, delay or prevent a third party from acquiring PHI, even if doing so would be beneficial to its stockholders. For example, under PHI’s restated certificate of incorporation, only its board of directors may call special meetings of stockholders. Further, stockholder actions may only be taken at a duly called annual or special meeting of stockholders and not by written consent. Moreover, directors of PHI may be removed by stockholders only for cause and only by the effective vote of at least a majority of the outstanding shares of capital stock of PHI entitled to vote generally in the election of directors (voting together as a single class) at a meeting of stockholders called for that purpose. In addition, under PHI’s amended and restated bylaws, stockholders must comply with advance notice requirements for nominating candidates for election to PHI’s board of directors or for proposing matters that can be acted upon by stockholders at stockholder meetings, and this provision may be amended or repealed by stockholders only upon the affirmative vote of the holders of two-thirds of the outstanding shares of PHI capital stock entitled to vote generally in the election of directors, voting together as a single class.

Issuances of additional series of PHI preferred stock could adversely affect holders of PHI’s common stock. (PHI only)

PHI’s board of directors is authorized to issue shares of PHI preferred stock in series without any action on the part of PHI stockholders. PHI’s board of directors also has the power, without stockholder approval, to set the terms of any such series of preferred stock, including with respect to dividend rights, redemption rights and sinking fund provisions, conversion rights, voting rights, and other preferential rights, limitations and restrictions. As of December 31, 2015, there were 18,000 shares of PHI Preferred Stock issued and outstanding. See Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – General Overview – Agreement and Plan of Merger with Exelon Corporation,” for information regarding the outstanding Preferred Stock.

If PHI issues preferred stock in the future that has a preference over PHI’s common stock with respect to the payment of dividends or upon its liquidation, dissolution or winding up, or if preferred stock is issued with voting rights that dilute the voting power of the common stock, the rights of holders of PHI’s common stock or the market price of such common stock could be adversely affected. Furthermore, issuances of preferred stock can be used to discourage, delay or prevent a third party from acquiring PHI where the acquisition might be perceived as being beneficial to stockholders.

Because Pepco, DPL and ACE are direct or indirect wholly owned subsidiaries of PHI and have directors and executive officers who are also officers of PHI, PHI can effectively exercise control over their dividend policies and significant business and financial transactions. (Pepco, DPL and ACE only)

All of the members of each of Pepco’s, DPL’s and ACE’s board of directors, as well as many of their respective executive officers, are officers of PHI, and Pepco, DPL and ACE are direct or indirect wholly owned subsidiaries of PHI. Among other decisions, each of Pepco’s, DPL’s and ACE’s board of directors is responsible for decisions regarding payment of dividends, financing and capital raising activities and acquisition and disposition of assets. Within the limitations of applicable law, and subject to the financial covenants under each company’s respective outstanding debt instruments, each of Pepco’s, DPL’s and

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ACE’s board of directors will base its decisions concerning the amount and timing of dividends, and other business decisions, on its capital structure, which is based in part on earnings and cash flow, and also may take into account the business plans and financial requirements of PHI and its other subsidiaries.

In the event that the Merger Agreement is terminated by PHI in connection with an alternative acquisition proposal prior to the completion of the Merger, PHI could incur significant transaction costs that could materially impact its financial performance and results.

PHI will incur significant transaction costs, including legal, accounting, financial advisory, filing, printing and other costs, relating to the Merger. If PHI terminates the Merger Agreement in connection with an alternative acquisition proposal made under certain circumstances, PHI will be required to pay Exelon a termination fee of $259 million plus reimbursement of Exelon for its expenses up to $40 million (which reimbursement shall reduce on a dollar for dollar basis any termination fee subsequently payable by PHI); if such acquisition proposal is made by a person who made an acquisition proposal between April 1, 2014 and the date of the Merger Agreement, PHI will be required to pay Exelon a termination fee of $293 million plus reimbursement of Exelon for its expenses up to $40 million (not subject to offset). The occurrence of either of these events could have a material adverse effect on PHI’s financial results.

PHI and its subsidiaries will be subject to business uncertainties and contractual restrictions while the Merger is pending that could adversely affect PHI’s financial results.

Uncertainty about the effect of the Merger on employees or vendors and others may have an adverse effect on PHI. Although PHI has taken steps designed to reduce any adverse effects, these uncertainties may impair PHI’s and its subsidiaries’ ability to attract, retain and motivate key personnel while the Merger is pending, and could cause vendors and others that deal with PHI to seek to change existing business relationships. Employee retention and recruitment has been particularly challenging given the delays in the receipt of regulatory approvals for completion of the Merger, as current employees and prospective employees continue to experience uncertainty about their future roles with the combined company. If, despite PHI’s retention and recruiting efforts, key employees depart or fail to accept new employment with PHI or its subsidiaries due to the uncertainty and difficulty of integration or a desire not to remain with the combined company, PHI’s business operations and financial results could be adversely affected.

PHI expects that matters relating to the Merger and integration-related issues will continue to place a significant burden on management, employees and internal resources, which could otherwise have been devoted to other business opportunities. The diversion of management time on merger-related issues could affect PHI’s financial results. In addition, the Merger Agreement restricts PHI and its subsidiaries, without Exelon’s consent, from taking specified actions until the Merger occurs or the Merger Agreement is terminated, including, without limitation: (i) making certain acquisitions and dispositions of assets or property; (ii) exceeding certain capital spending limits; (iii) incurring indebtedness; and (iv) issuing equity or equity equivalents. These restrictions may prevent PHI from pursuing otherwise attractive business opportunities and making other changes to its business prior to consummation of the Merger or termination of the Merger Agreement.

Pending or potential future litigation against PHI and its directors challenging the proposed Merger may prevent the Merger from being completed within the anticipated timeframe.

PHI and its directors have been named as defendants in a purported consolidated state class action lawsuit and a substantially similar purported federal class action lawsuit filed on behalf of public stockholders

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challenging the proposed Merger and seeking, among other things, to enjoin the defendants from consummating the Merger on the agreed-upon terms. If a plaintiff in these lawsuits or any other litigation that may be filed in the future is successful in obtaining an injunction prohibiting the parties from completing the Merger on the terms contemplated by the Merger Agreement, the injunction may prevent the completion of the Merger in the expected timeframe or altogether.

While PHI believes that these lawsuits are without merit, to avoid the risk of litigation delaying or adversely affecting the Merger and to minimize the expense of defending such litigation, on September 12, 2014, PHI entered into a memorandum of understanding with the plaintiffs to document the agreement in principle for the settlement of the state court lawsuit. There can be no assurance that the parties will ultimately enter into a stipulation of settlement or that the state court will approve the settlement even if the parties were to enter into such stipulation. In such event, the proposed settlement as contemplated by the memorandum of understanding may be terminated, which would create additional uncertainty relating to the consummation of the Merger.

Item 1B. UNRESOLVED STAFF COMMENTS

Pepco Holdings

None.

Pepco

None.

DPL

None.

ACE

None.

Item 2. PROPERTIES

Transmission and Distribution Systems

On a combined basis, the electric transmission and distribution systems owned by Pepco, DPL and ACE at December 31, 2015, consisted of approximately 4,000 transmission circuit miles of overhead lines, 600 transmission circuit miles of underground cables, 18,200 distribution circuit miles of overhead lines, and 15,900 distribution circuit miles of underground cables, primarily in their respective service territories. DPL and ACE own and operate distribution system control centers in New Castle, Delaware and Mays Landing, New Jersey, respectively. Pepco also operates a distribution system control center in Bethesda, Maryland. The computer equipment and systems contained in Pepco’s control center are financed through a sale and leaseback transaction.

DPL owns a liquefied natural gas facility located in Wilmington, Delaware, with a storage capacity of approximately three million gallons and an emergency sendout capability of 25,000 Mcf per day. DPL owns ten natural gas city gate stations at various locations in New Castle County, Delaware. These stations have a total primary delivery point contractual entitlement of 224,744 Mcf per day. DPL also owns approximately 104 pipeline miles of natural gas transmission mains, 1,874 pipeline miles of natural gas distribution mains, and 1,340 pipeline miles of natural gas service lines. In addition, DPL has a 10%

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undivided interest in approximately seven miles of natural gas transmission mains, which are used by DPL for its natural gas operations and by the 90% owner for distribution of natural gas to its electric generating facilities.

Substantially all of the transmission and distribution property, plant and equipment owned by each of Pepco, DPL and ACE is subject to the liens of the respective mortgages under which the companies issue First Mortgage Bonds. See Note (10), “Debt” to the consolidated financial statements of PHI.

Generating Facilities

The following table identifies the electric generating facilities owned by PHI’s subsidiaries at December 31, 2015.

Electric Generating Facilities	Location	Owner	Generating Capacity (kilowatts)
Landfill Gas-Fired Units
Fauquier Landfill Project (a)	Fauquier County, VA	Pepco Energy Services		2,000
Eastern Landfill Project	Baltimore County, MD	Pepco Energy Services		3,000
Bethlehem Landfill Project	Northampton, PA	Pepco Energy Services		5,000
				10,000
Solar Photovoltaic
Atlantic City Convention Center	Atlantic City, NJ	Pepco Energy Services		2,000
Combined Heat and Power Generating
Mid Town Plant	Atlantic City, NJ	Pepco Energy Services		5,400
Total Electric Generating Capacity				17,400

(a) Generating facility is scheduled for closure and demolition in 2016.

The preceding table sets forth the net summer electric generating capacity of each electric generating facility owned. Although the generating capacity may be higher during the winter months, the facilities are used to meet summer peak loads that are generally higher than winter peak loads. Accordingly, the summer generating capacity more accurately reflects the operational capability of the facilities.

Item 3. LEGAL PROCEEDINGS

Pepco Holdings

Other than litigation incidental to PHI and its subsidiaries’ business, PHI is not a party to, and PHI and its subsidiaries’ property is not subject to, any material pending legal proceedings except as described in Note (16), “Commitments and Contingencies,” to the consolidated financial statements of PHI.

Pepco

Other than litigation incidental to its business, Pepco is not a party to, and its property is not subject to, any material pending legal proceedings except as described in Note (12), “Commitments and Contingencies,” to the financial statements of Pepco.

DPL

Other than litigation incidental to its business, DPL is not a party to, and its property is not subject to, any material pending legal proceedings except as described in Note (14), “Commitments and Contingencies,” to the financial statements of DPL.

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ACE

Other than litigation incidental to its business, ACE is not a party to, and its property is not subject to, any material pending legal proceedings except as described in Note (13), “Commitments and Contingencies,” to the consolidated financial statements of ACE.

Item 4. MINE SAFETY DISCLOSURES

Not applicable.

Part II

Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

The New York Stock Exchange is the principal market on which Pepco Holdings common stock is traded. The following table presents the dividends declared per share on the Pepco Holdings common stock and the high and low sales prices for the common stock based on composite trading as reported by the New York Stock Exchange during each quarter in the last two years.

	Dividends Per Share		Price Range
			High		Low
2015:
First Quarter	$	0.27	$	27.50	$	26.75
Second Quarter		0.27		27.30		24.00
Third Quarter		0.27		27.34		21.61
Fourth Quarter		0.27		26.97		24.13
	$	1.08
2014:
First Quarter	$	0.27	$	20.93	$	18.53
Second Quarter		0.27		27.90		20.09
Third Quarter		0.27		27.92		26.76
Fourth Quarter		0.27		27.65		26.35
	$	1.08

At February 1, 2016, there were 41,460 holders of record of Pepco Holdings common stock.

Dividends

See Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity – Capital Requirements – Dividends,” and Note (12), “Stock-Based Compensation, Dividend Restrictions, and Calculations of Earnings Per Share of Common Stock – Dividend Restrictions,” of the consolidated financial statements of PHI for information regarding restrictions on the ability of PHI and its subsidiaries to pay dividends.

PHI Subsidiaries

One of PHI’s financial objectives is to maintain an equity ratio of 49%-50% in each of its operating utilities. Each quarter, PHI may contribute equity to its utility subsidiaries or the utility subsidiaries may make a dividend payment to PHI in order to maintain an equity ratio of 49%-50% in each of the utility

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subsidiaries. During 2015, PHI made capital contributions of $112 million, $75 million and $95 million to Pepco, DPL and ACE, respectively, and in 2014, PHI made capital contributions of $80 million and $130 million to Pepco and DPL, respectively.

All of Pepco’s common stock is held by Pepco Holdings, and all of DPL’s and ACE’s common stock is held by Conectiv, which in turn is wholly owned by Pepco Holdings. The table below presents the aggregate amount of common stock dividends paid by Pepco to PHI, and by DPL and ACE to Conectiv, during each quarter in the last two years. Dividends received by PHI in 2015 and 2014 from Pepco were used to support the payment of its common stock dividend. Dividends paid by ACE and DPL in 2015 and 2014 were used by Conectiv to pay down its short-term debt owed to PHI.

	Pepco		DPL		ACE
2015:
First Quarter	$	—	$	62,000,000	$	12,000,000
Second Quarter		31,000,000		—		—
Third Quarter		60,000,000		18,000,000		—
Fourth Quarter		55,000,000		12,000,000		—
	$	146,000,000	$	92,000,000	$	12,000,000
2014:
First Quarter	$	—	$	20,000,000	$	26,000,000
Second Quarter		46,000,000		—		—
Third Quarter		—		—		—
Fourth Quarter		40,000,000		80,000,000		—
	$	86,000,000	$	100,000,000	$	26,000,000

Recent Sales of Unregistered Equity Securities

Pepco Holdings

None.

Pepco

None.

DPL

None.

ACE

None.

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Purchases of Equity Securities by the Issuer and Affiliated Purchasers

Pepco Holdings

The following table includes shares of common stock accepted by Pepco Holdings during the quarter ended December 31, 2015 from certain employees in accordance with the provisions of the Pepco Holdings 2012 Long-Term Incentive Plan (2012 LTIP) to satisfy the employees’ minimum statutory tax withholding obligations related to awards of restricted stock under the 2012 LTIP that were granted in December 2015. Pepco Holdings does not currently have any publicly announced plans or programs to repurchase its common stock.

Period	Total Number of Shares Accepted (a)		Average Price Per Share
October 1 – October 31, 2015		—		—
November 1 – November 30, 2015		—		—
December 1 – December 31, 2015		23,630	$	26.095	(b)
Total		23,630	$	26.095

(a) Represents shares of Pepco Holdings’ common stock accepted from certain employees under the 2012 LTIP to satisfy the employees’ minimum statutory tax withholding obligations related to awards of restricted stock, which shares of common stock were then held in treasury.

(b) Represents the average of the high and low trading prices of a share of common stock on the New York Stock Exchange (NYSE) on the date of grant of the shares of restricted stock.

Pepco

None.

DPL

None.

ACE

None.

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Item 6. SELECTED FINANCIAL DATA

The following table sets forth selected historical consolidated data for PHI as of and for each of the years ended December 31, 2015, 2014, 2013, 2012 and 2011, derived from PHI’s audited consolidated financial statements.

PEPCO HOLDINGS CONSOLIDATED FINANCIAL HIGHLIGHTS

	2015			2014			2013			2012			2011
	(in millions, except per share data)
Consolidated Operating Results
Total Operating Revenue	$	5,023		$	4,878		$	4,666		$	4,625		$	4,964
Net Income from Continuing Operations		318	(a)		242	(b)		110	(e)		218			222
Net Income (Loss)		327			242			(212	)		285			257
Common Stock Information
Basic Earnings Per Share of Common Stock from Continuing Operations	$	1.25		$	0.96		$	0.45		$	0.95		$	0.98
Basic Earnings (Loss) Per Share of Common Stock		1.29			0.96			(0.86	)		1.25			1.14
Weighted Average Shares Outstanding - Basic		253			251			246			229			226
Cash Dividends Per Share of Common Stock		1.08			1.08			1.08			1.08			1.08
Year-End Stock Price		26.01			26.93			19.13			19.61			20.30
Net Book Value Per Common Share		17.35			17.10			17.23			19.19			18.92
Other Information
Total Assets	$	16,326		$	15,589	(c)	$	14,778	(c)	$	15,740	(c)	$	14,923	(c)
Capitalization
Short-Term Debt	$	1,063		$	729		$	565		$	965		$	732
Long-Term Debt		4,656			4,397	(d)		4,016	(d)		3,617	(d)		3,765	(d)
Current Portion of Long-Term Debt and Project Funding		341			431			446			569			112
Transition Bonds issued by ACE Funding		124			170	(d)		212	(d)		254	(d)		293	(d)
Capital Lease Obligations Due Within One Year		11			10			9			8			8
Capital Lease Obligations		39			50			60			70			78
Long-Term Project Funding		4			8			10			12			13
Series A Preferred Stock		183			129			—			—			—
Common Shareholders’ Equity		4,413			4,322			4,315			4,414			4,304
Total Capitalization	$	10,834		$	10,246		$	9,633		$	9,909		$	9,305

(a) Includes $12 million ($12 million after-tax) of incremental merger-related transaction costs, $15 million ($10 million after-tax) increase in fair value of preferred stock derivative, $46 million ($27 million after-tax) related to gains on sales of land and an income tax benefit of $47 million associated with the Global Tax Settlement.

(b) Includes impairment losses of $81 million ($48 million after-tax) associated with Pepco Energy Services’ combined heat and power thermal generating facilities and operations in Atlantic City and $25 million ($23 million after-tax) of incremental merger-related transaction costs.

(c) Amounts reflect the retrospective application of newly adopted accounting standards associated with the balance sheet classification of debt issuance costs and deferred taxes.

(d) Amounts reflect the retrospective application of a newly adopted accounting standard associated with the balance sheet classification of debt issuance costs.

(e) Includes a charge of $101 million to establish valuation allowances related to certain PCI deferred tax assets and a charge of $66 million to reflect the anticipated additional interest expense on estimated federal and state income tax obligations resulting from the change in assessment of the tax benefits associated with the cross-border energy lease investments.

INFORMATION FOR THIS ITEM IS NOT REQUIRED FOR PEPCO, DPL, AND ACE AS THEY MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS I(1)(a) AND (b) OF FORM 10-K AND THEREFORE ARE FILING THIS FORM WITH THE REDUCED FILING FORMAT.

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Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The information required by this item is contained herein, as follows:

Registrants	Page No.
Pepco Holdings		50
Pepco		101
DPL		112
ACE		123

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Pepco Holdings, Inc.

General Overview

PHI, a Delaware corporation incorporated in 2001, is a holding company that, through its regulated public utility subsidiaries, is engaged primarily in the transmission, distribution and default supply of electricity, and, to a lesser extent, the distribution and supply of natural gas (Power Delivery). Through Pepco Energy Services, PHI provides energy savings performance contracting services, underground transmission and distribution construction and maintenance services and steam and chilled water under long-term contracts. For additional discussion, see “Pepco Energy Services” below.

Each of Power Delivery and Pepco Energy Services constitutes a separate segment for financial reporting purposes. Through its subsidiary PCI, PHI maintained a portfolio of cross-border energy lease investments. PHI completed the termination of its interests in its cross-border energy lease investments during 2013. As a result, the cross-border energy lease investments, which comprised substantially all of the operations of the former Other Non-Regulated segment, have been accounted for as discontinued operations. Corporate and Other includes the remaining operations of the former Other Non-Regulated segment, certain parent company transactions (including interest expense on parent company debt and incremental external merger-related costs) and inter-company eliminations.

The following table sets forth the percentage contributions to consolidated operating revenue and operating income from continuing operations attributable to PHI segments for each of the preceding three years:

	2015			2014			2013
Percentage of Consolidated Operating Revenue
Power Delivery		96	%		94	%		96	%
Pepco Energy Services		4	%		6	%		4	%
Corporate and Other		—			—			—
Percentage of Consolidated Operating Income
Power Delivery		101	%		114	%		97	%
Pepco Energy Services		—			(13	)%		—
Corporate and Other		(1	)%		(1	)%		3	%
Percentage of Consolidated Operating Revenue - Power Delivery
Power Delivery Electric		97	%		96	%		96	%
Power Delivery Gas		3	%		4	%		4	%

Agreement and Plan of Merger with Exelon Corporation

PHI entered into the Merger Agreement, with Exelon and Merger Sub, providing for the Merger, with PHI surviving the Merger as an indirect, wholly owned subsidiary of Exelon. Pursuant to the Merger Agreement, at the effective time of the Merger, each outstanding share of common stock of PHI (other than (i) shares owned by Exelon, Merger Sub or any other direct or indirect wholly owned subsidiary of Exelon and shares owned by PHI or any direct or indirect wholly owned subsidiary of PHI, and in each case not held on behalf of third parties (but not including shares held by PHI in any rabbi trust or similar arrangement in respect of any compensation plan or arrangement) and (ii) shares that are owned by stockholders who have perfected and not withdrawn a demand for appraisal rights pursuant to Delaware law), will be canceled and converted into the right to receive $27.25 in cash, without interest.

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In connection with entering into the Merger Agreement, PHI entered into the Subscription Agreement with Exelon, pursuant to which on April 30, 2014, PHI issued to Exelon 9,000 originally issued shares of non-voting, non-convertible and non-transferable Series A preferred stock, par value $0.01 per share (the Preferred Stock), for a purchase price of $90 million. Exelon also committed pursuant to the Subscription Agreement to purchase 1,800 originally issued shares of Preferred Stock for a purchase price of $18 million at the end of each 90-day period following the date of the Subscription Agreement until the Merger closes or is terminated, up to a maximum of 18,000 shares of Preferred Stock for a maximum aggregate consideration of $180 million. In accordance with the Subscription Agreement, on each of July 29, 2014, October 27, 2014, January 26, 2015, April 27, 2015 and July 24, 2015, an additional 1,800 shares of Preferred Stock were issued by PHI to Exelon for an aggregate purchase price of $90 million. The holders of the Preferred Stock will be entitled to receive a cumulative, non-participating cash dividend of 0.1% per annum, payable quarterly, when, as and if declared by PHI’s board of directors. The proceeds from the issuance of the Preferred Stock are not subject to restrictions and are intended to serve as a prepayment of any applicable reverse termination fee payable from Exelon to PHI. The Preferred Stock will be redeemable on the terms and in the circumstances set forth in the Merger Agreement and the Subscription Agreement.

The Merger Agreement provides for certain termination rights for each of PHI and Exelon, and further provides that, upon termination of the Merger Agreement under certain specified circumstances, PHI will be required to pay Exelon a termination fee of $259 million or reimburse Exelon for its expenses up to $40 million (which reimbursement of expenses shall reduce on a dollar for dollar basis any termination fee subsequently payable by PHI), provided, however, that if the Merger Agreement is terminated in connection with an acquisition proposal made under certain circumstances by a person who made an acquisition proposal between April 1, 2014 and the date of the Merger Agreement, the termination fee will be $293 million plus reimbursement of Exelon for its expenses up to $40 million (not subject to offset). In addition, if there is a Regulatory Termination, PHI will be able to redeem any issued and outstanding Preferred Stock at par value, and in that case, Exelon will be required to pay all documented out-of-pocket expenses incurred by PHI in connection with the Merger Agreement or the transactions contemplated thereby, up to $40 million. If the Merger Agreement is terminated, other than for a Regulatory Termination, PHI will be required to redeem the Preferred Stock at the purchase price of $10,000 per share, plus any unpaid accrued and accumulated dividends thereupon.

Consummation of the Merger is subject to the satisfaction or waiver of specified closing conditions, including (i) the approval of the Merger by the holders of a majority of the outstanding shares of common stock of PHI; (ii) the receipt of regulatory approvals required to consummate the Merger, including approvals from FERC, the FCC, the DPSC, the DCPSC, the MPSC, the NJBPU and the VSCC; (iii) the expiration or termination of the applicable waiting period under the HSR Act; and (iv) other customary closing conditions, including (a) the accuracy of each party’s representations and warranties (subject to customary materiality qualifiers) and (b) each party’s compliance with its obligations and covenants contained in the Merger Agreement (including covenants that may limit, restrict or prohibit PHI and its subsidiaries from taking specified actions during the period between the date of the Merger Agreement and the closing of the Merger or the termination of the Merger Agreement). In addition, the obligations of Exelon and Merger Sub to consummate the Merger are subject to the required regulatory approvals not imposing terms, conditions, obligations or commitments, individually or in the aggregate, that constitute a burdensome condition (as defined in the Merger Agreement).

On September 23, 2014, the stockholders of PHI approved the Merger, on October 7, 2014, the VSCC approved the Merger, and on November 20, 2014, FERC approved the Merger. In addition, the transfer of control of certain communications licenses held by certain of PHI’s subsidiaries has been approved by the FCC. The NJBPU approved the Merger on February 11, 2015 and, on October 15, 2015, voted to extend the effectiveness of its approval until June 30, 2016. The DPSC approved the Merger on May 19, 2015.

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The waiting period under the HSR Act expired on December 2, 2015, which allows for the closing of the Merger at any time on or before December 1, 2016.

On May 15, 2015, the MPSC approved the Merger, with conditions, including conditions that modify and supplement those originally proposed. On May 18, 2015, PHI and Exelon announced that they had committed to fulfill the modified, more stringent conditions and package of customer benefits imposed by the MPSC. In connection with these proceedings, the Maryland Office of People’s Counsel and several other parties to the Merger proceedings filed motions in the Circuit Court for Queen Anne’s County, Maryland, requesting a stay of the MPSC order. On August 7, 2015, the Circuit Court for Queen Anne’s County denied the motions for stay. On January 8, 2016, the Circuit Court affirmed the MPSC’s order in all respects. On January 20 and 22, 2016, respectively, the Maryland Office of People’s Counsel and environmental groups filed notices of appeal of the Circuit Court’s order to the Maryland Court of Special Appeals. Unless a motion to stay is filed and then granted by the court, the MPSC order will remain in effect during the appeals process.

On August 27, 2015, the DCPSC issued a written order denying the application seeking approval of the Merger. On September 28, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, filed an application for reconsideration with the DCPSC requesting reconsideration of the DCPSC order related to the Merger.

On October 6, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, entered into the DC Settlement Agreement with the District of Columbia Government, the Office of the People’s Counsel and other parties, which DC Settlement Agreement contains commitments from Exelon and PHI above those contained in their original merger application.

Also on October 6, 2015, PHI, Exelon and Merger Sub entered into a Letter Agreement (the Letter Agreement), setting forth the terms and conditions under which the parties will file with the DCPSC (a) the Motion to Reopen, or (b) if the Motion to Reopen is not granted, a new merger application, requesting approval of the Merger on the terms and commitments agreed to in the DC Settlement Agreement. Pursuant to the Letter Agreement, PHI and Exelon each agrees, among other things, that neither party will exercise the termination rights each may have under the Merger Agreement on or after October 29, 2015, unless: (i) the DCPSC does not, by November 20, 2015, set a procedural schedule which allows for a final order for approval of the Merger by March 4, 2016, (ii) the DCPSC sets a schedule for action which does not allow for a final order for approval of the Merger by March 4, 2016, (iii) the DCPSC fails to issue a final order approving the Merger and the DC Settlement Agreement as filed without condition or modification by March 4, 2016, (iv) the DCPSC issues a final order denying approval of the Merger or the DC Settlement Agreement or adds conditions or makes modifications to the DC Settlement Agreement, (v) the DC Settlement Agreement is terminated for any reason, or (vi) after March 4, 2016 a condition to closing of the Merger has not been satisfied or waived (other than those conditions that by their nature are to be satisfied at the closing). The Letter Agreement also provides that, subject to certain conditions, Exelon may, following receipt of all regulatory approvals consistent with the DC Settlement Agreement, delay closing of the Merger for up to 30 days to engage in capital markets transactions to raise additional funds required to consummate the Merger.

On October 6, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, filed with the DCPSC the Motion to Reopen requesting consideration of the DC Settlement Agreement and approval of the Merger on such terms and conditions set forth in the DC Settlement Agreement, without condition or modification, and to stay further proceedings on the application for reconsideration filed by the parties on September 28, 2015 and suspend the time period for reconsideration pending the DCPSC’s consideration of the DC Settlement Agreement.

On October 28, 2015, the DCPSC approved the Motion to Reopen and set a procedural schedule for its review of this matter. Upon completion of the public input and evidentiary hearings, the record was closed as of December 23, 2015. Although District of Columbia law does not impose any time limit on the DCPSC’s review of the Merger, the parties requested a decision by March 4, 2016.

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The settlements reached and commission orders received to date in Delaware, Maryland and New Jersey, and as proposed in the DC Settlement Agreement, provide for public benefits of, among other things, customer rate credits, funding for energy efficiency and sustainability programs, and other commitments following consummation of the Merger. The terms of the Delaware, Maryland and New Jersey settlements and orders also incorporate a “most favored nation” provision which, generally speaking, requires allocation of financial merger benefits determined on an equivalent basis in each jurisdiction based on customer count. Exelon and PHI will apply the most favored nation provision to the final settlement terms and other conditions established in the merger approvals to determine the amounts of financial direct benefits that will be provided to customers of Pepco, DPL and ACE and to the jurisdictions. PHI anticipates that Exelon will make capital contributions to the PHI utilities to reimburse the PHI utilities for any such direct benefits that will be charged to earnings of the PHI utilities, net of tax effects, no later than the time such direct benefits are charged to earnings of the PHI utilities. The settlements and commission orders also provide for certain charitable contributions commitments which are required to be paid over a period of 10 years. PHI anticipates that the amounts of such commitments will be charged to earnings of the PHI utilities, net of tax effects, at the time of the merger close. Commitments to develop renewable generation, which are expected to be primarily capital in nature, will be recognized by Exelon as incurred. Upon completion of the merger, the actual nature, amount, timing and financial reporting treatment for these benefits and commitments may be materially different from the current projection.

While the Merger has been pending, PHI’s utility subsidiaries, in accordance with the terms of the Merger Agreement, have not filed any new distribution base rate cases, thereby foregoing rate increases that they might otherwise have sought. At the same time, each of the utility subsidiaries generally has maintained its pre-Merger Agreement level of infrastructure spending in its service territory. If the Merger is terminated as described above, PHI and each of its utility subsidiaries would commence filing distribution base rate cases in each of the jurisdictions and would expect that they will be required to undertake certain actions to address their ongoing results of operations and financial condition. Such actions are likely to include, but may not be limited to, reductions in capital and operation and maintenance expenditures, and the reevaluation of PHI’s common stock dividend policy. For further discussion, please refer to Part I, Item 1A. “Risk Factors” of this report.

Global Tax Settlement

On November 18, 2015, PHI entered into a settlement with the Internal Revenue Service (IRS) and the Department of Justice (DOJ) (the Global Tax Settlement) to provide for the resolution of the tax treatment of its previously held cross-border energy lease investments involving public utility assets located outside of the United States structured as sale-in, lease-out, or SILO, transactions. The Global Tax Settlement followed the acceptance by PHI on October 29, 2015 of IRS revenue agent reports covering adjustments incorporated in the terms of the Global Tax Settlement, as well as adjustments for all other tax matters in dispute with the IRS. Also, on November 18, 2015, the DOJ accepted PHI’s offer letter for the settlement of litigation related to the SILO transactions discussed further in Note (16), “Commitments and Contingencies – PHI’s Cross-Border Energy Lease Investments” to the consolidated financial statements of PHI. The Global Tax Settlement and the revenue agent reports, together, effectively close all years open to examination of federal income tax liabilities for PHI through 2011, and all matters associated with the cross-border energy lease investments through 2013.

The Global Tax Settlement, which resolves tax matters related to the cross-border energy lease investments and avoids the costs associated with continued litigation, provides that all depreciation and interest deductions in excess of rental income related to the cross-border energy lease investments were disallowed. The Global Tax Settlement also required PHI to recognize original issue discount income for tax purposes associated with the recharacterization of each of the leases as a loan transaction. Pursuant to the Global Tax Settlement, interest will be assessed with respect to tax underpayments in the relevant years; however, no penalties were assessed against PHI. The Global Tax Settlement provides for the same treatment of the cross-border energy lease investments for the tax years 2012 and 2013 as described above. The last of PHI’s cross-border energy lease investments was terminated in 2013. As a result of the Global Tax Settlement, PHI and the DOJ filed stipulations of dismissal regarding the litigation in the U.S. Court of Federal Claims. The Court dismissed the complaint on November 20, 2015. The Global Tax Settlement is further discussed in Note (11), “Income Taxes” to the consolidated financial statements of PHI.

Power Delivery

Power Delivery Electric consists primarily of the transmission, distribution and default supply of electricity, and Power Delivery Gas consists of the delivery and supply of natural gas.

The Pepco, DPL and ACE service territories are located within a corridor extending from the District of Columbia to southern New Jersey. These service territories are economically diverse and include key industries that contribute to the regional economic base:

• Commercial activities in the region include federal and municipal government services, professional, scientific and technical services, educational and health services, banking, casinos, tourism and transportation.

• Industrial activities in the region include chemical, glass, pharmaceutical, food processing and oil refining.

Each utility comprising Power Delivery is a regulated public utility in the jurisdictions that comprise its service territory. Each utility is responsible for the distribution of electricity and, in the case of DPL, the distribution and supply of natural gas, in its service territory, for which it is paid tariff rates established by the applicable local public service commission in each jurisdiction. Each utility also supplies electricity at regulated rates to retail customers in its service territory who do not elect to purchase electricity from a competitive energy supplier. The regulatory term for this supply service is Standard Offer Service in Delaware, the District of Columbia and Maryland, and Basic Generation Service in New Jersey. These supply service obligations are referred to generally as Default Electricity Supply.

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Each of Pepco, DPL and ACE is responsible for the transmission of wholesale electricity into and across its service territory. The rates each utility is permitted to charge for the wholesale transmission of electricity are regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.

The profitability of Power Delivery depends on its ability to recover costs and earn a reasonable return on its capital investments through the rates it is permitted to charge. Operating results also can be affected by economic conditions generally, the level of commercial activity affecting a region, industry or business sector within a service territory, energy prices, the impact of energy efficiency measures on customer usage of electricity and weather.

Power Delivery’s results historically have been seasonal, generally producing higher revenue and income in the warmest and coldest periods of the year. For retail customers of Pepco and DPL in Maryland and of Pepco in the District of Columbia, revenue is not affected by unseasonably warmer or colder weather because a BSA was implemented that provides for a fixed distribution charge per customer rather than a charge based upon energy usage. The BSA, pursuant to which customer distribution rates are subject to adjustment (through a credit or surcharge mechanism), depending on whether actual distribution revenue per customer exceeds or falls short of the revenue-per-customer amount approved by the applicable public service commission, has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during the period. As a result, the only factors that will cause distribution revenue from retail customers in Maryland and the District of Columbia to fluctuate from period to period are changes in the number of customers and changes in the approved distribution charge per customer. A comparable revenue decoupling mechanism for DPL electricity and natural gas customers in Delaware is under consideration by the DPSC.

In accounting for the BSA in Maryland and the District of Columbia, a Revenue Decoupling Adjustment (an adjustment equal to the amount by which revenue from distribution sales differs from the revenue that Pepco and DPL are entitled to earn based on the approved distribution charge per customer) is recorded representing either (i) a positive adjustment equal to the amount by which revenue from retail distribution sales falls short of the revenue that Pepco and DPL are entitled to earn based on the approved distribution charge per customer or (ii) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that Pepco and DPL are entitled to earn based on the approved distribution charge per customer.

PHI’s utility subsidiaries allocate a substantial portion of their total capital expenditures to improving the reliability of their electrical transmission and distribution systems and replacing aging infrastructure throughout their service territories. These activities include:

• Identifying and upgrading under-performing feeder lines;

• Adding new facilities to support load;

• Installing distribution automation systems on both the overhead and underground network systems;

• Rejuvenating and replacing underground residential cables; and

• Replacing equipment at the end of its useful life.

PHI’s capital expenditures for continuing reliability enhancement efforts are included in the table of projected capital expenditures within “– Capital Resources and Liquidity – Capital Requirements – Capital Expenditures.”

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Power Delivery Initiatives and Activities

District of Columbia Power Line Undergrounding Initiative

For information about the District of Columbia Power Line Undergrounding Initiative, please refer to Note (7), “Regulatory Matters – District of Columbia Power Line Undergrounding Initiative,” to the consolidated financial statements of PHI.

MPSC New Generation Contract Requirement

For information about the MPSC New Generation Contract Requirement, please refer to Note (7), “Regulatory Matters – MPSC New Generation Contract Requirement,” to the consolidated financial statements of PHI.

Smart Grid Initiatives

PHI’s utility subsidiaries are engaged in transforming the power grid that they own and operate into a “smart grid,” a network of automated digital devices capable of collecting and communicating large amounts of real-time data.

A central component of the smart grid is AMI, a system that collects, measures and analyzes energy usage data from advanced digital meters, known as “smart meters.” Also critical to the operation of the smart grid is distribution automation technology, which is comprised of automated devices that have internal intelligence and can be controlled remotely to better manage power flow and restore service quickly and more safely. Both the AMI system and distribution automation are enabled by advanced technology that communicates with devices installed on the energy delivery system and transmits energy usage data to the host utility. The implementation of the AMI system and distribution automation involves an integration of technologies provided by multiple vendors.

As of December 31, 2015, Pepco and DPL have completed the installation and activation of smart meters in the District of Columbia, Maryland and Delaware service territories. ACE has yet to receive approval from the NJBPU to proceed with the installation of AMI smart meters.

The DCPSC, the MPSC and the DPSC approved the creation by PHI’s utility subsidiaries of regulatory assets to defer AMI costs between rate cases and to defer carrying charges on the deferred costs. AMI costs for Pepco in the District of Columbia and DPL in Delaware are being recovered through base rates. For AMI costs incurred by Pepco and DPL in Maryland, pursuant to an MPSC order, recovery will be allowed when the Companies demonstrate that their respective AMI systems are cost-effective. The MPSC’s July 2013 order in Pepco’s November 2012 electric distribution base rate application excluded the cost of AMI meters from Pepco’s rate base until such time as Pepco demonstrates the cost effectiveness of the AMI system. As a result, costs for AMI meters incurred by Pepco and by DPL in Maryland will be treated as other incremental AMI costs incurred in conjunction with the deployment of the AMI system that are deferred and on which a carrying charge is deferred.

Mitigation of Regulatory Lag

An important factor in the ability of PHI’s utility subsidiaries to earn their authorized ROE is the willingness of applicable public service commissions to adequately address the shortfall in revenues in a utility’s rate structure due to the delay in time or “lag” between when costs are incurred and when they are reflected in rates. This delay is commonly known as “regulatory lag.” Pepco, DPL and ACE are currently experiencing significant regulatory lag because investments in rate base and operating expenses are increasing more rapidly than their revenue growth.

In an effort to minimize the effects of regulatory lag, prior to the initial execution of the Merger Agreement in April 2014, PHI’s utility subsidiaries had been filing electric distribution base rate cases every nine to twelve months in each of their jurisdictions, pursuing alternative ratemaking mechanisms,

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evaluating potential reductions in planned capital expenditures, and discussing with the regulatory community and other stakeholders the changing regulatory model economics that are causing regulatory lag.

As further described in “– General Overview – Agreement and Plan of Merger with Exelon Corporation,” PHI entered into the Merger Agreement with Exelon and Merger Sub in April 2014. Subject to certain exceptions, prior to the Merger or the termination of the Merger Agreement, PHI and its subsidiaries may not, without the consent of Exelon, initiate, file or pursue any rate cases, other than concluding pending filings. To date, PHI has not requested such consent from Exelon and has not filed any new distribution base rate cases since entering into the Merger Agreement. Accordingly, PHI’s efforts to mitigate regulatory lag have been delayed pending the closing of the Merger or the termination of the Merger Agreement.

FERC Transmission ROE Challenges

For information about the challenges to the utility subsidiaries’ base ROE and the application of the formula rate process, each associated with the transmission services they provide, please refer to Note (7), “Regulatory Matters – Rate Proceedings – FERC Transmission ROE Challenges,” to the consolidated financial statements of PHI.

Pepco Energy Services

Pepco Energy Services is focused on growing its energy savings business and its underground transmission and distribution construction business while managing its thermal assets in Atlantic City. The energy savings business focuses on developing, building and operating energy savings performance solutions primarily for federal, state and local government customers. Pepco Energy Services’ underground transmission and distribution construction business focuses on providing construction and maintenance services for electric power utilities in North America.

PHI guarantees the obligations of Pepco Energy Services under certain contracts in its energy savings performance contracting business and underground transmission and distribution construction business. At December 31, 2015, PHI’s guarantees of Pepco Energy Services’ obligations under these contracts totaled $269 million. PHI also guarantees the obligations of Pepco Energy Services under surety bonds obtained by Pepco Energy Services for construction projects. These guarantees totaled $177 million at December 31, 2015.

During 2012, Pepco Energy Services deactivated its Buzzard Point and Benning Road oil-fired generation facilities. Pepco Energy Services completed demolition of the Benning Road generation facility in July 2015 and recognized the scrap metal salvage value of the facility as a reduction in its demolition expenses over the life of the project.

Revenues associated with Pepco Energy Services’ combined heat and power thermal generating facilities and operations in Atlantic City are derived from long-term contracts with a few major customers in the Atlantic City hotel and casino industry. The carrying amount of Pepco Energy Services’ long-lived assets in Atlantic City at December 31, 2015 totaled $2 million, after impairment losses aggregating $81 million that were recorded during the third and fourth quarters of 2014. In September 2014, two significant customers of these thermal operations declared Chapter 11 bankruptcy. One of the customers closed operations in September 2014 and Pepco Energy Services continues to provide this customer with steam and chilled water service under a contract with lower rates which began April 1, 2015. The second customer terminated its contract with Pepco Energy Services on March 31, 2015. Two other significant customers of the thermal operations declared Chapter 11 bankruptcy in January 2015 and Pepco Energy Services continues to provide service to those customers under existing contracts. Future developments with respect to these and other customers in Atlantic City may require Pepco Energy Services to perform additional impairment analyses of the thermal operations and certain related assets. If these assets are determined to be further impaired, Pepco Energy Services would reduce

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the carrying value of these assets by the amount of the impairment and record a corresponding non-cash charge to earnings. Moreover, the contract changes and termination referred to above are expected to reduce Pepco Energy Services’ future earnings and cash flows associated with its thermal operations in Atlantic City.

In addition, Atlantic City, New Jersey, while not a customer of Pepco Energy Services, is also facing financial difficulties that could impact Pepco Energy Services customers. Legislation was introduced in the State of New Jersey that would cede control over the city’s finances to the State of New Jersey or the city could declare bankruptcy. It is uncertain at this time as to how this matter will ultimately be resolved or to determine the ramifications of the financial difficulties of Atlantic City on Pepco Energy services’ customers.

Corporate and Other

Corporate and other includes the remaining operations of the former Other Non-Regulated segment, certain parent company transactions (including interest expense on parent company debt and incremental external merger-related costs) and inter-company eliminations.

Between 1990 and 1999, PCI entered into certain transactions involving investments in aircraft and aircraft equipment, railcars and other assets, which comprise substantially all of the remaining operations of the former Other Non-Regulated segment. In connection with these transactions, PCI recorded deferred tax assets in prior years of $101 million in the aggregate. After evaluating events that took place during the first quarter of 2013, PCI established valuation allowances against these deferred tax assets totaling $101 million in the first quarter of 2013. Further, during the fourth quarter of 2013, in light of additional court decisions in favor of the IRS involving other taxpayers, and after consideration of all relevant factors, management determined that it would abandon the further pursuit of these deferred tax assets, and these assets totaling $101 million were charged off against the previously established valuation allowances.

Discontinued Operations

In this Management’s Discussion and Analysis of Financial Condition and Results of Operations, all references to PHI’s segments and continuing operations exclude the following discontinued operations.

Cross-Border Energy Lease Investments

Through its subsidiary PCI, PHI held a portfolio of cross-border energy lease investments. During 2013, PHI completed the termination of its interest in its cross-border energy lease investments and, as a result, these investments are being accounted for as discontinued operations.

As discussed in Note (16), “Commitments and Contingencies – PHI’s Cross-Border Energy Lease Investments,” to the consolidated financial statements of PHI, PHI was involved in litigation with the IRS concerning certain benefits associated with previously held investments in cross-border energy leases. On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States (to which PHI is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. As a result of the court’s ruling in this case, PHI determined in the first quarter of 2013 that its tax position with respect to the benefits associated with its cross-border energy leases no longer met the more-likely-than-not standard of recognition for accounting purposes, and PHI recorded non-cash after-tax charges of $323 million (after-tax) in the first quarter of 2013 and $6 million (after-tax) in the second quarter of 2013, consisting of the following components:

• A non-cash pre-tax charge of $373 million ($313 million after-tax) to reduce the carrying value of these cross-border energy lease investments under FASB guidance on leases (Accounting Standards Codification (ASC) 840). This pre-tax charge was originally recorded in the consolidated statements of income (loss) as a reduction in operating revenue and is now reflected in loss from discontinued operations, net of income taxes.

• A non-cash charge of $16 million after-tax to reflect the anticipated additional net interest expense under FASB guidance for income taxes (ASC 740), related to estimated federal and state income tax obligations for the period over which the tax benefits may be disallowed. This after-tax charge was originally recorded in the consolidated statements of income (loss) as an increase in income tax expense and is now reflected in loss from discontinued operations, net of income taxes. The after-tax interest charge for PHI on a consolidated basis was $70 million and this amount was allocated to each member of PHI’s consolidated group as if each member was a separate taxpayer, resulting in the recognition of a $12 million interest benefit for the Power Delivery segment and interest expense of $16 million for PCI and $66 million for Corporate and Other, respectively.

On November 18, 2015, PHI entered into the Global Tax Settlement with the IRS and the DOJ to provide for the resolution of the tax treatment of its previously held cross-border energy lease investments. The Global Tax Settlement is further discussed in Note (11), “Income Taxes” to the consolidated financial statements of PHI. Also, on November 18, 2015, the DOJ accepted PHI’s offer letter for the settlement of litigation related to the SILO transactions and the U.S. Court of Federal Claims dismissed the complaint on November 20, 2015. The litigation is further discussed in Note (16), “Commitments and Contingencies – PHI’s Cross-Border Energy Lease Investments” to the consolidated financial statements of PHI.

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Retail Electric and Natural Gas Supply Businesses of Pepco Energy Services

In December 2009, PHI announced the wind-down of the retail energy supply component of the Pepco Energy Services business which was comprised of the retail electric and natural gas supply businesses. Pepco Energy Services implemented the wind-down by not entering into any new retail electric or natural gas supply contracts while continuing to perform under its existing retail electric and natural gas supply contracts through their respective expiration dates. On March 21, 2013, Pepco Energy Services entered into an agreement whereby a third party assumed all the rights and obligations of the remaining retail natural gas supply customer contracts, and the associated supply obligations, inventory and derivative contracts. The transaction was completed on April 1, 2013. In addition, Pepco Energy Services completed the wind-down of its retail electric supply business in the second quarter of 2013 by terminating its remaining customer supply and wholesale purchase obligations beyond June 30, 2013.

The operations of Pepco Energy Services’ retail electric and natural gas supply businesses have been classified as discontinued operations and are not a part of the Pepco Energy Services segment for financial reporting purposes.

Earnings Overview

Year Ended December 31, 2015 Compared to Year Ended December 31, 2014

	2015		2014			Change
	(millions of dollars)
Power Delivery	$	302	$	320		$	(18	)
Pepco Energy Services		4		(39	)		43
Corporate and Other		12		(39	)		51
Net Income from Continuing Operations		318		242			76
Discontinued Operations		9		—			9
Total PHI Net Income	$	327	$	242		$	85

Net income from continuing operations for the year ended December 31, 2015 was $318 million, or $1.25 per share, compared to $242 million, or $0.96 per share, for the year ended December 31, 2014.

Net income from continuing operations for the year ended December 31, 2015 included the items set forth below, which are presented net of related federal and state income taxes and are in millions of dollars:

• Incremental merger-related transaction costs in Corporate and Other of $12 million ($12 million pre-tax)

• Change in fair value of derivative related to Preferred Stock in Corporate and Other of $10 million ($15 million pre-tax)

Net income from continuing operations for the year ended December 31, 2014 included the items set forth below, which are presented net of related federal and state income taxes and are in millions of dollars:

• Asset impairment losses in Pepco Energy Services of $48 million ($81 million pre-tax)

• Incremental merger-related transaction costs in Corporate and Other of $23 million ($25 million pre-tax)

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Excluding the items listed above, net income from continuing operations would have been $320 million, or $1.26 per share for the year ended December 31, 2015, and $313 million, or $1.24 per share for the year ended December 31, 2014.

PHI discloses net income from continuing operations and related per share data excluding certain items because management believes that these items are not representative of PHI’s ongoing business operations. Management uses this information, and believes that such information is useful to investors, in evaluating PHI’s period-over-period performance. The inclusion of this disclosure is intended to complement, and should not be considered as an alternative to, PHI’s reported net income from continuing operations and related per share data in accordance with GAAP.

Net income from discontinued operations was $9 million, or $.04 per share, for the year ended December 31, 2015.

Discussion of Operating Segment Net Income Variances:

Power Delivery’s $18 million decrease in earnings was primarily due to the following:

• A decrease of $65 million due to higher operation and maintenance expense primarily related to the implementation of a new customer information system, higher bad debt expense, higher tree trimming and system maintenance costs and higher environmental remediation costs.

• A decrease of $13 million due to higher depreciation and amortization expense primarily resulting from increases in plant investment and the implementation of a new customer information system.

• A decrease of $10 million from income tax adjustments, primarily related to the Global Tax Settlement.

• A decrease of $8 million due to higher interest expense.

• An increase of $27 million in gains from the sale of certain Pepco properties in 2015.

• An increase of $20 million from other distribution revenue, primarily due to customer growth and rate mix.

• An increase of $20 million from electric distribution base rate increases in 2014 (Pepco in the District of Columbia and Maryland, and ACE in New Jersey).

• An increase of $6 million from network service transmission revenues primarily due to higher revenue related to plant investment, partially offset by an increase in refund reserves related to the FERC ROE challenges.

• An increase of $6 million in regulated T&D electric revenue primarily due to the effect of warmer weather during the spring and summer months of 2015, as compared to 2014.

Pepco Energy Services’ $43 million increase in earnings was primarily due to asset impairment losses of $48 million (after-tax) recorded in 2014 associated with its combined heat and power thermal generating facilities and operations in Atlantic City, partially offset by lower energy savings construction activity in 2015.

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Corporate and Other’s $51 million increase in earnings was primarily due to the following:

• An increase of $43 million related to the impact of the Global Tax Settlement.

• An increase of $11 million due to lower incremental merger-related transaction costs.

• An increase of $10 million due to the increase in the fair value of a derivative related to the Preferred Stock.

• A decrease of $10 million primarily due to unfavorable state income tax adjustments and higher pension and other postretirement benefits costs.

Discussion of Discontinued Operations:

Net earnings from discontinued operations for the year ended December 31, 2015 was $9 million, due to the Global Tax Settlement’s resolution of outstanding tax issues related to the previously held cross-border energy lease investments.

Consolidated Results of Operations

The following results of operations discussion compares the year ended December 31, 2015 to the year ended December 31, 2014. All amounts in the tables (except sales and customers) are in millions of dollars.

Continuing Operations

Operating Revenue

A detail of the components of PHI’s consolidated operating revenue is as follows:

	2015			2014			Change
Power Delivery	$	4,805		$	4,607		$	198
Pepco Energy Services		223			278			(55	)
Corporate and Other		(5	)		(7	)		2
Total Operating Revenue	$	5,023		$	4,878		$	145

Power Delivery

The following table categorizes Power Delivery’s operating revenue by type of revenue.

	2015		2014		Change
Regulated T&D Electric Revenue	$	2,429	$	2,277	$	152
Default Electricity Supply Revenue		2,150		2,076		74
Other Electric Revenue		61		60		1
Total Electric Operating Revenue		4,640		4,413		227
Regulated Gas Revenue		154		176		(22	)
Other Gas Revenue		11		18		(7	)
Total Gas Operating Revenue		165		194		(29	)
Total Power Delivery Operating Revenue	$	4,805	$	4,607	$	198

Regulated Transmission and Distribution (T&D) Electric Revenue includes revenue from the distribution of electricity, including the distribution of Default Electricity Supply, by PHI’s utility subsidiaries to customers within their service territories at regulated rates. Regulated T&D Electric Revenue also includes transmission service revenue that PHI’s utility subsidiaries receive as transmission owners from PJM at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.

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Default Electricity Supply Revenue is the revenue received from the supply of electricity by PHI’s utility subsidiaries at regulated rates to retail customers who do not elect to purchase electricity from a competitive energy supplier. The costs related to Default Electricity Supply are included in Fuel and Purchased Energy. Default Electricity Supply Revenue also includes revenue from non-bypassable Transition Bond Charges that ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds, and revenue in the form of transmission enhancement credits that PHI utility subsidiaries receive as transmission owners from PJM in consideration for approved regional transmission expansion plan expenditures.

Other Electric Revenue includes work and services performed on behalf of customers, including other utilities, which is generally not subject to price regulation. Work and services include mutual assistance to other utilities, highway relocation, rentals of pole attachments, late payment fees and collection fees.

Regulated Gas Revenue includes the revenue DPL receives from on-system natural gas delivered sales and the transportation of natural gas for customers within its service territory at regulated rates.

Other Gas Revenue consists of DPL’s off-system natural gas sales and the short-term release of interstate pipeline transportation and storage capacity not needed to serve customers. Off-system sales are made possible when low demand for natural gas by regulated customers creates excess pipeline capacity.

Regulated T&D Electric

	2015		2014		Change
Regulated T&D Electric Revenue
Residential	$	914	$	824	$	90
Commercial and industrial		1,065		1,013		52
Transmission and other		450		440		10
Total Regulated T&D Electric Revenue	$	2,429	$	2,277	$	152
	2015		2014		Change
Regulated T&D Electric Sales (Gigawatt hour (GWh))
Residential		18,111		17,129		982
Commercial and industrial		29,365		29,831		(466	)
Transmission and other		235		255		(20	)
Total Regulated T&D Electric Sales		47,711		47,215		496
	2015		2014		Change
Regulated T&D Electric Customers (in thousands)
Residential		1,702		1,669		33
Commercial and industrial		200		200		—
Transmission and other		2		2		—
Total Regulated T&D Electric Customers		1,904		1,871		33

Regulated T&D Electric Revenue increased by $152 million primarily due to:

• An increase of $54 million due to EmPower Maryland (a Maryland demand-side management program for Pepco and DPL) rate increases effective February 2014 and February 2015 (which is substantially offset by a corresponding increase in Depreciation and Amortization).

• An increase of $36 million due to electric distribution base rate increases (Pepco in the District of Columbia effective April 2014 and in Maryland effective July 2014; ACE effective September 2014).

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• An increase of $15 million due to customer growth in 2015, primarily in the residential classes.

• An increase of $13 million in transmission revenue due to higher rates effective June 2014 and June 2015 related to increases in transmission plant investment and operating expenses, partially offset by the establishment of a reserve related to the FERC ROE challenges.

• An increase of $12 million due to higher sales primarily as a result of warmer weather during the spring and summer months of 2015, as compared to 2014.

• An increase of $10 million in capacity revenue as a result of expanding Maryland demand side management programs (which is partially offset in Depreciation and Amortization).

• An increase of $9 million due to a bill stabilization adjustment.

• An increase of $8 million primarily due to rate increases effective June 2014 and June 2015 associated with the Renewable Portfolio Surcharge in Delaware (which is substantially offset in Fuel and Purchased Energy and Depreciation and Amortization).

The aggregate amount of these increases was partially offset by a decrease of $6 million in revenue related to the resale by DPL of renewable energy to PJM (which is substantially offset in Purchased Energy and Depreciation and Amortization).

Default Electricity Supply

	2015		2014		Change
Default Electricity Supply Revenue
Residential	$	1,445	$	1,312	$	133
Commercial and industrial		562		553		9
Other		143		211		(68	)
Total Default Electricity Supply Revenue	$	2,150	$	2,076	$	74

Other Default Electricity Supply Revenue consists primarily of (i) revenue from the resale by ACE in the PJM RTO market of energy and capacity purchased under contracts with unaffiliated non-utility generators (NUGs), and (ii) revenue from transmission enhancement credits.

	2015		2014		Change
Default Electricity Supply Sales (GWh)
Residential		14,861		13,851		1,010
Commercial and industrial		5,479		5,420		59
Other		46		44		2
Total Default Electricity Supply Sales		20,386		19,315		1,071
	2015		2014		Change
Default Electricity Supply Customers (in thousands)
Residential		1,446		1,397		49
Commercial and industrial		129		129		—
Other		—		—		—
Total Default Electricity Supply Customers		1,575		1,526		49

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Default Electricity Supply Revenue increased by $74 million primarily due to:

• An increase of $64 million due to higher sales primarily as a result of customer migration from competitive suppliers.

• An increase of $29 million as a result of higher Default Electricity Supply rates.

• An increase of $26 million due to higher sales primarily as a result of warmer weather during the spring and summer months of 2015, as compared to 2014.

• An increase of $23 million in non-weather related average customer usage.

The aggregate amount of these increases was partially offset by a decrease of $70 million in wholesale energy and capacity resale revenues primarily due to lower market prices for the resale of electricity and capacity purchased from NUGs.

The variances described above with respect to Default Electricity Supply Revenue include the effects of a decrease of $2 million in ACE’s BGS unbilled revenue resulting primarily from lower average customer usage in the unbilled revenue period for the year ended December 31, 2015 as compared to the corresponding period in 2014. Such a decrease in ACE’s BGS unbilled revenue has the effect of directly decreasing the profitability of ACE’s Default Electricity Supply business ($1 million decrease in net income) as these unbilled revenues are not included in the deferral calculation until they are billed to customers under the BGS terms approved by the NJBPU.

Regulated Gas

	2015		2014		Change
Regulated Gas Revenue
Residential	$	94	$	106	$	(12	)
Commercial and industrial		49		59		(10	)
Transportation and other		11		11		—
Total Regulated Gas Revenue	$	154	$	176	$	(22	)
	2015		2014		Change
Regulated Gas Sales (million cubic feet)
Residential		8,020		8,550		(530	)
Commercial and industrial		5,796		6,063		(267	)
Transportation and other		6,193		6,418		(225	)
Total Regulated Gas Sales		20,009		21,031		(1,022	)
	2015		2014		Change
Regulated Gas Customers (in thousands)
Residential		120		118		2
Commercial and industrial		10		10		—
Transportation and other		—		—		—
Total Regulated Gas Customers		130		128		2

Regulated Gas Revenue decreased by $22 million primarily due to:

• A decrease of $11 million due to lower sales as a result of warmer weather primarily during the fourth quarter of 2015, as compared to 2014.

• A decrease of $11 million due to Gas Cost Rate (GCR) decreases effective November 2014 and November 2015.

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Other Gas Revenue

Other Gas Revenue decreased by $7 million primarily due to lower volumes and lower average prices for off-system sales to electric generators and gas marketers.

Pepco Energy Services

Pepco Energy Services’ operating revenue decreased by $55 million primarily due to:

• A decrease of $65 million in its energy savings business primarily associated with lower construction activity.

• A decrease of $14 million from its thermal business in Atlantic City primarily due to the loss of a customer in 2015.

The aggregate amount of these decreases was partially offset by an increase of $24 million in revenues associated with higher underground transmission and distribution construction activities.

Operating Expenses

Fuel and Purchased Energy and Other Services Cost of Sales

A detail of PHI’s consolidated Fuel and Purchased Energy and Other Services Cost of Sales is as follows:

	2015		2014		Change
Power Delivery	$	2,095	$	2,074	$	21
Pepco Energy Services		176		212		(36	)
Corporate and Other		1		1		—
Total	$	2,272	$	2,287	$	(15	)

Power Delivery’s Fuel and Purchased Energy expense consists of the cost of electricity and natural gas purchased by its utility subsidiaries to fulfill their respective Default Electricity Supply and Regulated Gas obligations and, as such, is recoverable from customers in accordance with the terms of public service commission orders. It also includes the cost of natural gas purchased for off-system sales. Fuel and Purchased Energy expense increased by $21 million primarily due to:

• An increase of $58 million primarily due to customer migration from competitive suppliers.

• An increase of $19 million due to higher electricity sales primarily as a result of warmer weather during the spring and summer months of 2015, as compared to 2014.

• An increase of $9 million in deferred electricity expense primarily due to higher revenue associated with Pepco and DPL Default Electricity Supply sales, which resulted in a higher rate of recovery of Default Electricity Supply costs.

• An increase of $8 million from the settlement of financial hedges entered into as part of DPL’s hedge program for the purchase of regulated natural gas.

The aggregate amount of these increases was partially offset by:

• A decrease of $41 million due to lower average electricity costs under Default Electricity Supply contracts.

• A decrease of $26 million in the cost of gas purchases for on-system sales as a result of lower prices.

• A decrease of $6 million in the cost of gas purchases for off-system sales as a result of lower volumes and lower average prices.

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Pepco Energy Services

Pepco Energy Services’ Fuel and Purchased Energy expense and Other Services Cost of Sales decreased by $36 million primarily due to:

• A decrease of $54 million in its energy savings business primarily associated with decreased construction activity.

• A decrease of $6 million in its thermal business primarily due to the loss of a customer in Atlantic City.

The aggregate amount of these decreases was partially offset by an increase of $23 million associated with increased underground transmission and distribution construction activities.

Other Operation and Maintenance

A detail of PHI’s Other Operation and Maintenance expense is as follows:

	2015			2014			Change
Power Delivery	$	1,019		$	904		$	115
Pepco Energy Services		43			52			(9	)
Corporate and Other		(46	)		(32	)		(14	)
Total	$	1,016		$	924		$	92

Other Operation and Maintenance expense for Power Delivery increased by $115 million primarily due to:

• An increase of $40 million due to implementation and support costs related to a new customer information system.

• An increase of $15 million in bad debt expense, of which $7 million is deferred and recoverable.

• An increase of $15 million associated with higher tree trimming and system maintenance costs.

• An increase of $12 million in environmental remediation costs.

• An increase of $11 million in customer service costs.

• An increase of $4 million in internal and external merger-related integration costs.

• An increase of $4 million due to lower capitalized labor in 2015, as compared to 2014.

• An increase of $3 million due to the 2014 deferral of distribution rate case costs previously charged to Other Operation and Maintenance expense. The deferral was recorded in accordance with the DCPSC rate order issued in March 2014 authorizing the recovery of these costs.

• An increase of $3 million primarily due to cancelled construction projects.

• An increase of $1 million primarily due to an increase in incremental storm costs related to a severe storm with damaging winds and heavy rains on June 23, 2015 in the respective service territories of DPL and ACE. The storm resulted in widespread customer outages in each of these service territories and caused damage to the electric transmission and distribution systems of each utility. Total incremental storm restoration costs incurred by DPL and ACE for the storm through December 31, 2015 were $40 million, with $15 million incurred for repair work and $25 million incurred as capital expenditures. Costs incurred for repair work of $14 million

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were deferred as regulatory assets to reflect the probable recovery of these costs in Maryland and New Jersey, and $1 million was charged to Other Operation and Maintenance expense. DPL and ACE intend to pursue recovery of these incremental storm restoration costs in their respective jurisdictions in their next electric distribution base rate cases.

The increased costs referred to above for implementation and support of a new customer information system, system maintenance, customer service and storm restoration each involve internal labor costs which reflect a higher level of pension benefit cost in 2015, as compared to 2014.

Pepco Energy Services

Other Operation and Maintenance expense for Pepco Energy Services decreased $9 million primarily due to:

• A decrease of $4 million associated with bad debt expense recorded in 2014 for customers in Atlantic City.

• A decrease of $3 million from lower personnel expenses in its energy savings business.

• A decrease of $2 million from lower costs associated with the demolition of its Benning Road generation facility that was completed in July 2015.

Corporate and Other

Other Operation and Maintenance expense for Corporate and Other decreased by $14 million primarily due to lower internal and external merger-related transaction costs during 2015, as compared to 2014.

Depreciation and Amortization

Depreciation and Amortization expense increased by $102 million to $651 million in 2015 from $549 million in 2014 primarily due to:

• An increase of $52 million in amortization of regulatory assets primarily associated with the EmPower Maryland surcharge rate increases effective February 2014 and February 2015 (which is offset by an increase in Regulated T&D Electric Revenue).

• An increase of $23 million due to utility plant additions.

• An increase of $15 million in amortization of stranded costs, primarily as the result of higher revenue due to a rate increase effective October 2014 for the ACE Market Transition Tax (partially offset in Default Supply Electricity Revenue).

• An increase of $10 million in amortization of software, primarily related to the implementation of a new customer information system.

Other Taxes

Other Taxes increased by $14 million to $427 million in 2015 from $413 million in 2014. The increase was primarily due to higher property taxes related to an increase in assets.

Deferred Electric Service Costs

Deferred Electric Service Costs, which relate only to ACE, represent (i) the over or under recovery of electricity costs incurred by ACE to fulfill its Default Electricity Supply obligation and (ii) the over or

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under recovery of costs incurred by ACE related to the New Jersey Societal Benefit Program (a statewide public interest program that is intended to benefit low income customers and address other public policy goals). The cost of electricity purchased is reported under Fuel and Purchased Energy expense and the corresponding revenue is reported under Default Electricity Supply Revenue. The costs of the New Jersey Societal Benefit Program are reported under Other Operation and Maintenance expense and the corresponding revenue is reported under Regulated T&D Electric Revenue.

Deferred Electric Service Costs increased by $10 million to an expense of $30 million in 2015 as compared to an expense of $20 million in 2014 primarily due to an increase in deferred electricity expense as a result of higher Default Electricity Supply revenue rates.

Impairment Losses

Impairment losses decreased by $81 million to zero in 2015 from $81 million in 2014. The decrease was primarily due to 2014 impairment losses of $81 million ($48 million after-tax) at Pepco Energy Services associated with its combined heat and power thermal generating facilities and operations in Atlantic City.

Gains on Sales of Land

Gains on sales of land increased by $46 million in 2015 from zero in 2014. The increase was primarily due to 2015 gains of $46 million ($27 million after-tax) recorded at Pepco associated with the sale of unimproved land, held as non-utility property.

Other Income (Expenses)

Other Expenses (which are net of Other Income) increased by $2 million to a net expense of $226 million in 2015 from a net expense of $224 million in 2014 primarily due to:

• An increase of $10 million in interest expense primarily associated with higher long-term debt and higher short-term debt.

• An increase of $15 million in income due to an increase in the fair value of the derivative related to the Preferred Stock.

• An increase of $2 million in income related to the allowance for funds used during construction (AFUDC) that is applied to construction projects.

• A decrease of $9 million in income related to gains recorded in 2014 associated with condemnation awards of certain Pepco transmission property.

Income Tax Expense

PHI’s income tax expense decreased by $9 million to $129 million in 2015 from $138 million in 2014. PHI’s consolidated effective income tax rates for the years ended December 31, 2015 and 2014 were 28.9% and 36.3%, respectively.

The decrease in the effective tax rate primarily resulted from the net tax benefits recorded in 2015 in connection with the Global Tax Settlement (as further described in Note (11), “Income Taxes,” to the consolidated financial statements of PHI) and lower non-deductible incremental merger-related costs incurred in 2015 as compared to 2014.

During 2015 and 2014, PHI recorded tax benefits of $6 million and $5 million, respectively, related to certain energy efficiency tax deductions related to Pepco Energy Services’ energy savings performance contracting services.

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Discontinued Operations

PHI’s Income (loss) from discontinued operations, net of income taxes, was $9 million for the year ended December 31, 2015, as compared to zero for the year ended December 31, 2014.

During 2015, income from discontinued operations, net of income taxes, resulted from the Global Tax Settlement reached with the IRS which resolves tax matters related to PHI’s previously held cross-border energy lease investments and is discussed further in Note (11), “Income Taxes” to the consolidated financial statements of Pepco Holdings.

During 2014, there was no activity related to PHI’s discontinued operations.

The following results of operations discussion compares the year ended December 31, 2014 to the year ended December 31, 2013. All amounts in the tables (except sales and customers) are in millions of dollars.

Continuing Operations

Operating Revenue

A detail of the components of PHI’s consolidated operating revenue is as follows:

	2014			2013			Change
Power Delivery	$	4,607		$	4,472		$	135
Pepco Energy Services		278			203			75
Corporate and Other		(7	)		(9	)		2
Total Operating Revenue	$	4,878		$	4,666		$	212

Power Delivery

The following table categorizes Power Delivery’s operating revenue by type of revenue.

	2014		2013		Change
Regulated T&D Electric Revenue	$	2,277	$	2,146	$	131
Default Electricity Supply Revenue		2,076		2,075		1
Other Electric Revenue		60		60		—
Total Electric Operating Revenue		4,413		4,281		132
Regulated Gas Revenue		176		165		11
Other Gas Revenue		18		26		(8	)
Total Gas Operating Revenue		194		191		3
Total Power Delivery Operating Revenue	$	4,607	$	4,472	$	135

Regulated T&D Electric Revenue includes revenue from the distribution of electricity, including the distribution of Default Electricity Supply, by PHI’s utility subsidiaries to customers within their service territories at regulated rates. Regulated T&D Electric Revenue also includes transmission service revenue that PHI’s utility subsidiaries receive as transmission owners from PJM at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.

Default Electricity Supply Revenue is the revenue received from the supply of electricity by PHI’s utility subsidiaries at regulated rates to retail customers who do not elect to purchase electricity from a competitive energy supplier. The costs related to Default Electricity Supply are included in Fuel and Purchased Energy. Default Electricity Supply Revenue also includes revenue from non-bypassable Transition Bond Charges that ACE receives, and pays to ACE Funding, to fund the principal and interest

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payments on Transition Bonds, and revenue in the form of transmission enhancement credits that PHI utility subsidiaries receive as transmission owners from PJM in consideration for approved regional transmission expansion plan expenditures.

Other Electric Revenue includes work and services performed on behalf of customers, including other utilities, which is generally not subject to price regulation. Work and services include mutual assistance to other utilities, highway relocation, rentals of pole attachments, late payment fees and collection fees.

Regulated Gas Revenue includes the revenue DPL receives from on-system natural gas delivered sales and the transportation of natural gas for customers within its service territory at regulated rates.

Other Gas Revenue consists of DPL’s off-system natural gas sales and the short-term release of interstate pipeline transportation and storage capacity not needed to serve customers. Off-system sales are made possible when low demand for natural gas by regulated customers creates excess pipeline capacity.

Regulated T&D Electric

	2014		2013		Change
Regulated T&D Electric Revenue
Residential	$	824	$	781	$	43
Commercial and industrial		1,013		970		43
Transmission and other		440		395		45
Total Regulated T&D Electric Revenue	$	2,277	$	2,146	$	131
	2014		2013		Change
Regulated T&D Electric Sales (GWh)
Residential		17,129		17,168		(39	)
Commercial and industrial		29,831		30,070		(239	)
Transmission and other		255		259		(4	)
Total Regulated T&D Electric Sales		47,215		47,497		(282	)
	2014		2013		Change
Regulated T&D Electric Customers (in thousands)
Residential		1,669		1,650		19
Commercial and industrial		200		200		—
Transmission and other		2		2		—
Total Regulated T&D Electric Customers		1,871		1,852		19

Regulated T&D Electric Revenue increased by $131 million primarily due to:

• An increase of $81 million due to electric distribution base rate increases (Pepco in the District of Columbia effective April 2014, and in Maryland effective July 2013 and July 2014; DPL in Maryland effective September 2013, and in Delaware effective October 2013; ACE effective July 2013 and September 2014).

• An increase of $20 million in transmission revenue resulting from higher rates effective June 2014 and June 2013 related to increases in transmission plant investment and operating expenses, partially offset by the establishment of a reserve related to the FERC ROE challenges.

• An increase of $19 million due to an EmPower Maryland rate increase effective February 2014 (which is substantially offset by a corresponding increase in Depreciation and Amortization).

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• An increase of $16 million due to customer growth in 2014 primarily in the residential classes.

• An increase of $12 million in transmission revenue related to the recovery of Mid-Atlantic Power Pathway (MAPP) abandonment costs, as approved by FERC (which is substantially offset in Depreciation and Amortization).

• An increase of $5 million primarily due to a rate increase in the New Jersey Societal Benefit Charge (a surcharge related to the New Jersey Societal Benefit Program, which is a public interest program for low income customers) effective January 2014 (which is offset in Depreciation and Amortization and Deferred Electric Service Costs).

• An increase of $5 million in transmission revenue related to the resale by DPL of renewable energy in Delaware (which is substantially offset in Purchased Energy and Depreciation and Amortization).

• An increase of $4 million in capacity revenue as a result of expanding Maryland demand side management programs (which is partially offset in Depreciation and Amortization).

The aggregate amount of these increases was partially offset by:

• A decrease of $12 million in distribution revenue due to lower pass-through revenue (which is substantially offset by a corresponding decrease in Other Taxes) primarily the result of a rate decrease effective July 2014 in utility taxes collected by Pepco on behalf of Montgomery County, Maryland.

• A decrease of $10 million in distribution revenue due to lower pass-through revenue primarily the result of the expiration of the New Jersey Transitional Energy Facility Assessment (TEFA) tax surcharge effective December 2013 (which is offset in Other Taxes).

• A decrease of $5 million due to lower ACE non-weather related average commercial and residential customer usage.

• A decrease of $4 million due to lower ACE sales primarily as a result of milder weather during the 2014 spring and summer months.

• A decrease of $2 million primarily due to a rate decrease effective May 2013 associated with the Renewable Portfolio Surcharge in Delaware (which is substantially offset in Fuel and Purchased Energy and Depreciation and Amortization).

Default Electricity Supply

	2014		2013		Change
Default Electricity Supply Revenue
Residential	$	1,312	$	1,376	$	(64	)
Commercial and industrial		553		542		11
Other		211		157		54
Total Default Electricity Supply Revenue	$	2,076	$	2,075	$	1

Other Default Electricity Supply Revenue consists primarily of (i) revenue from the resale by ACE in the PJM RTO market of energy and capacity purchased under contracts with unaffiliated NUGs, and (ii) revenue from transmission enhancement credits.

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	2014		2013		Change
Default Electricity Supply Sales (GWh)
Residential		13,851		13,743		108
Commercial and industrial		5,420		5,079		341
Other		44		55		(11	)
Total Default Electricity Supply Sales		19,315		18,877		438
	2014		2013		Change
Default Electricity Supply Customers (in thousands)
Residential		1,397		1,352		45
Commercial and industrial		129		125		4
Other		—		—		—
Total Default Electricity Supply Customers		1,526		1,477		49

Default Electricity Supply Revenue increased by $1 million primarily due to:

• A net increase of $68 million due to higher sales primarily as a result of customer migration from competitive suppliers in Pepco and ACE, partially offset by lower sales in DPL as a result of customer migration to competitive suppliers.

• An increase of $50 million in wholesale energy and capacity resale revenues primarily due to higher market prices for the resale of electricity and capacity purchased from NUGs.

• An increase of $5 million in revenue from PJM for transmission enhancement credits as a result of a higher total cost of transmission projects in 2014.

The aggregate amount of these increases was partially offset by:

• A decrease of $97 million as a result of lower Default Electricity Supply rates.

• A net decrease of $24 million due to lower Pepco and ACE non-weather related average customer usage, partially offset by higher usage at DPL.

The variances described above with respect to Default Electricity Supply Revenue include the effects of an increase of $3 million in ACE’s BGS unbilled revenue resulting primarily from higher rates and customer migration from competitive suppliers in the unbilled revenue period for December 31, 2014 as compared to the corresponding period for December 31, 2013. Such an increase in ACE’s BGS unbilled revenue has the effect of directly increasing the profitability of ACE’s Default Electricity Supply business ($2 million increase in net income) as these unbilled revenues are not included in the deferral calculation until they are billed to customers under the BGS terms approved by the NJBPU.

Regulated Gas

	2014		2013		Change
Regulated Gas Revenue
Residential	$	106	$	103	$	3
Commercial and industrial		59		52		7
Transportation and other		11		10		1
Total Regulated Gas Revenue	$	176	$	165	$	11

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	2014		2013		Change
Regulated Gas Sales (million cubic feet)
Residential		8,550		7,861		689
Commercial and industrial		6,063		4,945		1,118
Transportation and other		6,418		6,990		(572	)
Total Regulated Gas Sales		21,031		19,796		1,235

	2014		2013		Change
Regulated Gas Customers (in thousands)
Residential		118		117		1
Commercial and industrial		10		9		1
Transportation and other		—		—		—
Total Regulated Gas Customers		128		126		2

Regulated Gas Revenue increased by $11 million primarily due to:

• An increase of $9 million due to higher sales primarily as a result of colder weather during the winter months of 2014, as compared to 2013.

• An increase of $6 million due to higher non-weather related average customer usage.

• An increase of $4 million due to a distribution rate increase effective July 2013.

• An increase of $2 million due to customer growth primarily in the residential customer class.

The aggregate amount of these increases was partially offset by a decrease of $10 million due to GCR decreases effective November 2013 and November 2014.

Other Gas Revenue

Other Gas Revenue decreased by $8 million primarily due to lower volumes for off-system sales to electric generators and gas marketers.

Pepco Energy Services

Pepco Energy Services’ operating revenue increased by $75 million primarily due to:

• An increase of $46 million primarily in energy savings construction activities.

• An increase of $26 million in underground transmission and distribution construction activities.

• An increase of $3 million associated with the thermal business in Atlantic City primarily due to colder temperatures in the first half of 2014.

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Operating Expenses

Fuel and Purchased Energy and Other Services Cost of Sales

A detail of PHI’s consolidated Fuel and Purchased Energy and Other Services Cost of Sales is as follows:

	2014		2013			Change
Power Delivery	$	2,074	$	2,070		$	4
Pepco Energy Services		212		148			64
Corporate and Other		1		(2	)		3
Total	$	2,287	$	2,216		$	71

Power Delivery

Power Delivery’s Fuel and Purchased Energy expense consists of the cost of electricity and natural gas purchased by its utility subsidiaries to fulfill their respective Default Electricity Supply and Regulated Gas obligations and, as such, is recoverable from customers in accordance with the terms of public service commission orders. It also includes the cost of natural gas purchased for off-system sales. Fuel and Purchased Energy expense increased by $4 million primarily due to:

• An increase of $33 million primarily due to customer migration from competitive suppliers.

• An increase of $20 million in deferred electricity expense primarily due to higher revenue associated with Pepco and DPL Default Electricity Supply sales, which resulted in a higher rate of recovery of Default Electricity Supply costs.

• An increase of $16 million in the cost of gas purchases for on-system sales as a result of higher average gas prices.

• An increase of $3 million in the costs associated with purchasing Renewable Energy Credits in Delaware (which is offset by a corresponding increase in Regulated T&D Revenue).

• An increase of $2 million due to higher electricity sales primarily as a result of colder weather during the 2014 winter months, as compared to 2013.

The aggregate amount of these increases was partially offset by:

• A net decrease of $50 million due to lower average electricity costs under Pepco and DPL Default Electricity Supply contracts, and due to lower ACE costs under BGS contracts.

• A decrease of $8 million in the cost of gas purchases for off-system sales as a result of lower volumes.

• A decrease of $7 million in deferred gas expense as a result of a lower rate of recovery of natural gas supply costs.

• A decrease of $6 million from the settlement of financial hedges entered into as part of DPL’s hedge program for the purchase of regulated natural gas.

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Pepco Energy Services

Pepco Energy Services’ Fuel and Purchased Energy expense and Other Services Cost of Sales increased by $64 million primarily due to:

• An increase of $39 million primarily associated with increased energy savings construction activity.

• An increase of $25 million associated with increased underground transmission and distribution construction activities.

Other Operation and Maintenance

A detail of PHI’s Other Operation and Maintenance expense is as follows:

	2014			2013			Change
Power Delivery	$	904		$	871		$	33
Pepco Energy Services		52			42			10
Corporate and Other		(32	)		(62	)		30
Total	$	924		$	851		$	73

Power Delivery

Other Operation and Maintenance expense for Power Delivery increased by $33 million primarily due to:

• An increase of $14 million in internal and external merger-related integration costs.

• An increase of $8 million primarily due to higher tree trimming and maintenance costs.

• An increase of $7 million primarily due to new customer system support costs.

• An increase of $6 million in bad debt expense, of which $1 million is deferred and recoverable.

• An increase of $5 million in emergency restoration costs.

• An increase of $3 million due to the write-off of unrecoverable regulatory assets previously established in connection with the sale of certain ACE generation assets.

The aggregate amount of these increases was partially offset by:

• A decrease of $7 million in regulatory expenses.

• A decrease of $3 million resulting from the 2013 write-off of disallowed MAPP and associated transmission project costs.

Pepco Energy Services

Other Operation and Maintenance expense for Pepco Energy Services increased by $10 million primarily due to:

• An increase of $4 million in bad debt expense for accounts receivable.

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• An increase of $3 million in employee compensation primarily associated with its energy savings business.

• An increase of $2 million in repairs and maintenance costs associated with its thermal business in Atlantic City.

• An increase of $1 million associated with the demolition of the Benning Road generation facility.

Corporate and Other

Other Operation and Maintenance expense for Corporate and Other increased by $30 million primarily due to internal and external merger-related transaction costs.

Depreciation and Amortization

Depreciation and Amortization expense increased by $76 million to $549 million in 2014 from $473 million in 2013 primarily due to:

• An increase of $20 million due to utility plant additions.

• An increase of $13 million in amortization of regulatory assets primarily associated with the EmPower Maryland surcharge rate increase effective February 2014 (which is offset by an increase in Regulated T&D Electric Revenue).

• An increase of $12 million in amortization of MAPP abandonment costs (which is offset in Regulated T&D Electric Revenue).

• An increase of $12 million in amortization due to the expiration in August 2013 of the excess depreciation reserve regulatory liability of ACE.

• An increase of $10 million in amortization of regulatory assets primarily related to recoverable AMI costs, major storm costs and rate case costs.

• An increase of $5 million in amortization of solar renewable energy credits (which is offset by an increase in Regulated T&D Electric Revenue).

Other Taxes

Other Taxes decreased by $15 million to $413 million in 2014 from $428 million in 2013. The decrease was primarily due to:

• A decrease of $10 million in TEFA tax collections due to the expiration of the assessment effective December 2013 (which is offset by a corresponding decrease in Regulated T&D Electric Revenue).

• A decrease of $10 million in the Montgomery County, Maryland utility taxes that are collected and passed through by Pepco (substantially offset by a corresponding decrease in Regulated T&D Electric Revenue).

The aggregate amount of these decreases was partially offset by an increase of $7 million in property taxes in Maryland.

Deferred Electric Service Costs

Deferred Electric Service Costs, which relate only to ACE, represent (i) the over or under recovery of electricity costs incurred by ACE to fulfill its Default Electricity Supply obligation and (ii) the over or under recovery of New Jersey Societal Benefit Program costs incurred by ACE. The cost of electricity

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purchased is reported under Fuel and Purchased Energy and the corresponding revenue is reported under Default Electricity Supply Revenue. The cost of the New Jersey Societal Benefit Program is reported under Other Operation and Maintenance and the corresponding revenue is reported under Regulated T&D Electric Revenue.

Deferred Electric Service Costs decreased by $6 million to an expense of $20 million in 2014 as compared to an expense of $26 million in 2013 primarily due to a decrease in deferred electricity expense as a result of lower Default Electricity Supply revenue rates.

Impairment Losses

Impairment losses increased by $77 million to $81 million in 2014 from $4 million in 2013. The increase was primarily due to 2014 impairment losses of $81 million ($48 million after-tax) at Pepco Energy Services associated with its combined heat and power thermal generating facilities and operations in Atlantic City, partially offset by a 2013 impairment loss of $4 million ($3 million after-tax) associated with a landfill gas-fired electric generation facility.

Other Income (Expenses)

Other Expenses (which are net of Other Income) decreased by $15 million to a net expense of $224 million in 2014 from a net expense of $239 million in 2013 primarily due to:

• An increase of $9 million in Other Income associated with gains recorded in 2014 associated with condemnation awards for certain Pepco transmission properties.

• A decrease of $5 million in interest expense primarily associated with lower short-term debt and lower long-term debt interest expense.

Income Tax Expense

PHI’s income tax expense decreased by $181 million to $138 million in 2014 from $319 million in 2013. PHI’s consolidated effective income tax rates for the years ended December 31, 2014 and 2013 were 36.3% and 74.4%, respectively.

The decrease in the effective tax rate resulted from certain tax benefits associated with Pepco Energy Services recorded in the third quarter of 2014, changes in estimates and interest related to uncertain and effectively settled tax positions and deferred tax valuation allowances established in the first quarter of 2013, partially offset by the effect of certain incremental merger-related costs (as further described in Note (1), “Organization,” to the consolidated financial statements of PHI), incurred in 2014 that are not tax deductible.

During 2014, PHI recorded a tax benefit of $5 million related to certain energy efficiency tax deductions related to Pepco Energy Services’ energy savings performance contracting services.

During 2013, PHI recorded a $56 million charge for a change in estimates and interest related to uncertain and effectively settled tax positions, primarily representing the anticipated additional interest expense on estimated federal and state income tax obligations that was allocated to PHI’s continuing operations resulting from a change in assessment of tax benefits associated with the former cross-border energy lease investments of PCI in the first quarter of 2013.

Also, in the first quarter of 2013, PHI established valuation allowances of $101 million related to deferred tax assets. Between 1990 and 1999, PCI, through various subsidiaries, entered into certain transactions involving investments in aircraft and aircraft equipment, railcars and other assets. In connection with these transactions, PCI recorded deferred tax assets in prior years of $101 million in the aggregate. Following events that took place during the first quarter of 2013, which included (i) court decisions in favor of the IRS with respect to other taxpayers’ cross-border lease and other structured transactions (as

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discussed in Note (20), “Discontinued Operations – Cross-Border Energy Lease Investments”), (ii) the change in PHI’s tax position with respect to the tax benefits associated with its cross-border energy leases, and (iii) PHI’s decision in March 2013 to begin to pursue the early termination of its remaining cross-border energy lease investments (which represented a substantial portion of the remaining assets within PCI) without the intent to reinvest these proceeds in income-producing assets, management evaluated the likelihood that PCI would be able to realize the $101 million of deferred tax assets in the future. Based on this evaluation, PCI established valuation allowances against these deferred tax assets totaling $101 million in the first quarter of 2013. Further, during the fourth quarter of 2013, in light of additional court decisions in favor of the IRS involving other taxpayers, and after consideration of all relevant factors, management determined that it would abandon the further pursuit of these deferred tax assets, and these assets totaling $101 million were charged off against the previously established valuation allowances.

Discontinued Operations

PHI’s loss from discontinued operations, net of income taxes, is comprised of the following:

	2014		2013			Change
Cross-border energy lease investments	$	—	$	(327	)	$	327
Pepco Energy Services’ retail electric and natural gas supply businesses		—		5			(5	)
Loss from discontinued operations, net of income taxes	$	—	$	(322	)	$	322

During 2014, there was no activity in PHI’s discontinued operations.

In 2013, the loss from discontinued operations, net of income taxes, for PHI’s cross-border energy lease investments of $327 million was primarily related to a change in assessment regarding the tax benefits related to the cross-border energy lease investments consisting of a $373 million non-cash pre-tax charge ($313 million after-tax) to reduce the carrying value of the investments and a $16 million non-cash after-tax charge to reflect the anticipated additional interest expense related to the change in PCI’s estimated federal and state income tax obligations as if it were a separate taxpayer. In addition, PHI recorded a loss of $3 million ($2 million after-tax) in 2013 for the termination of PHI’s interests in its remaining cross-border energy lease investments, representing the excess of the carrying value of the terminated leases over the net cash proceeds received.

In 2013, the income from discontinued operations, net of income taxes, at Pepco Energy Services of $5 million was due to the completion of the wind-down of the retail electric and natural gas supply businesses in 2013.

Capital Resources and Liquidity

This section discusses PHI’s working capital, cash flow activity, capital requirements and other uses and sources of capital.

Working Capital

At December 31, 2015, PHI’s current assets on a consolidated basis totaled $1.2 billion and its consolidated current liabilities totaled $2.3 billion, resulting in a working capital deficit of $1,106 million. PHI expects the working capital deficit at December 31, 2015 to be funded during 2016 in part through cash flows from operations and from the issuance of short-term and long-term debt and to the extent necessary, the issuance of equity. At December 31, 2014, PHI’s current assets on a consolidated basis totaled $1.0 billion and its consolidated current liabilities totaled $2.1 billion, resulting in a working capital deficit of $1,022 million. The increase of $84 million in the working capital deficit from December 31, 2014 to December 31, 2015 was primarily due to an increase in short-term debt, partially offset by a decrease in the current portion of long-term debt and project funding, and increases in accounts receivable and income taxes and related accrued interest receivable.

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At December 31, 2015, PHI’s consolidated cash and cash equivalents totaled $25 million, which consisted of cash and uncollected funds but excluded current Restricted cash equivalents (cash that is available to be used only for designated purposes) that totaled $14 million. At December 31, 2014, PHI’s consolidated cash and cash equivalents totaled $14 million, which consisted of cash and uncollected funds but excluded current Restricted cash equivalents that totaled $25 million.

Detail of PHI’s short-term debt balance and current portion of long-term debt and project funding balance is as follows:

	As of December 31, 2015
Type	PHI Parent		Pepco		DPL		ACE		ACE Funding		Pepco Energy Services		PHI Consolidated
	(millions of dollars)
Variable Rate Demand Bonds	$	—	$	—	$	105	$	—	$	—	$	—	$	105
Commercial Paper		484		64		105		5		—		—		658
Term Loan		300		—		—		—		—		—		300
Total Short-Term Debt	$	784	$	64	$	210	$	5	$	—	$	—	$	1,063
Current Portion of Long-Term Debt and Project Funding	$	190	$	—	$	100	$	2	$	46	$	3	$	341

	As of December 31, 2014
Type	PHI Parent		Pepco		DPL		ACE		ACE Funding		Pepco Energy Services		PHI Consolidated
	(millions of dollars)
Variable Rate Demand Bonds	$	—	$	—	$	105	$	—	$	—	$	—	$	105
Commercial Paper		287		104		106		127		—		—		624
Total Short-Term Debt	$	287	$	104	$	211	$	127	$	—	$	—	$	729
Current Portion of Long-Term Debt and Project Funding	$	250	$	12	$	100	$	15	$	44	$	10	$	431

Commercial Paper

PHI, Pepco, DPL and ACE maintain on-going commercial paper programs to address short-term liquidity needs. As of December 31, 2015, the maximum capacity available under these programs was $875 million, $500 million, $500 million and $350 million, respectively, subject to available borrowing capacity under the credit facility.

The weighted average interest rate for commercial paper issued by PHI, Pepco, DPL and ACE during 2015 was 0.80%, 0.44%, 0.47% and 0.46%, respectively. The weighted average maturity of all commercial paper issued by PHI, Pepco, DPL and ACE during 2015 was ten, four, four and six days, respectively.

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Credit Facility

PHI, Pepco, DPL and ACE maintain an unsecured syndicated credit facility to provide for their respective liquidity needs, including obtaining letters of credit, borrowing for general corporate purposes and supporting their commercial paper programs. On August 1, 2013, as permitted under the existing terms of the credit agreement, a request by PHI, Pepco, DPL and ACE to extend the credit facility termination date to August 1, 2018 was approved. All of the terms and conditions as well as pricing remained the same.

The aggregate borrowing limit under the amended and restated credit facility is $1.5 billion, all or any portion of which may be used to obtain loans and up to $500 million of which may be used to obtain letters of credit. The facility also includes a swingline loan sub-facility, pursuant to which each company may make same day borrowings in an aggregate amount not to exceed 10% of the total amount of the facility. Any swingline loan must be repaid by the borrower within fourteen days of receipt. The credit sublimit is $750 million for PHI and $250 million for each of Pepco, DPL and ACE. The sublimits may be increased or decreased by the individual borrower during the term of the facility, except that (i) the sum of all of the borrower sublimits following any such increase or decrease must equal the total amount of the facility, and (ii) the aggregate amount of credit used at any given time by (a) PHI may not exceed $1.25 billion, and (b) each of Pepco, DPL or ACE may not exceed the lesser of $500 million or the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the sublimit reallocations may not exceed eight per year during the term of the facility.

For additional discussion of the Credit Facility, see Note (10), “Debt,” to the consolidated financial statements of PHI.

Credit Facility Amendment

During 2014, PHI, Pepco, DPL and ACE entered into an amendment of and consent with respect to the credit agreement (the Consent). PHI was required to obtain the consent of certain of the lenders under the credit facility in order to permit the consummation of the Merger. Pursuant to the Consent, certain of the lenders consented to the consummation of the Merger and the subsequent conversion of PHI from a Delaware corporation to a Delaware limited liability company, provided that the Merger and subsequent conversion are consummated on or before October 29, 2015. In addition, the Consent amends the definition of “Change in Control” in the credit agreement to mean, following consummation of the Merger, an event or series of events by which Exelon no longer owns, directly or indirectly, 100% of the outstanding shares of voting stock of Pepco Holdings. PHI requested and obtained an extension of the Consent to allow for completion of the Merger by June 30, 2016.

PHI Term Loan Agreements

On January 13, 2016, PHI entered into a $500 million term loan agreement, pursuant to which PHI borrowed $500 million at a rate of interest equal to the prevailing Eurodollar rate, which is determined by reference to the London Interbank Offered Rate with respect to the relevant interest period, all as defined in the loan agreement, plus a margin of 0.90%. PHI used the net proceeds of the loan under the loan agreement to repay its outstanding commercial paper, and for general corporate purposes. All indebtedness incurred under the loan agreement is unsecured, and the aggregate principal amount of all loans, together with any accrued but unpaid interest due under the loan agreement, must be repaid in full on or before July 13, 2016. Pursuant to the term loan agreement, PHI may consummate the Merger and

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the subsequent conversion of PHI from a Delaware corporation to a Delaware limited liability company, provided that the Merger and subsequent conversion are consummated on or before October 29, 2015. PHI requested and obtained the consent of the lenders under the term loan to allow for completion of the Merger by June 30, 2016.

On July 30, 2015, PHI entered into a $300 million term loan agreement, pursuant to which PHI borrowed $300 million at a rate of interest equal to the prevailing Eurodollar rate, which is determined by reference to the London Interbank Offered Rate with respect to the relevant interest period, all as defined in the loan agreement, plus a margin of 0.95%. PHI used the net proceeds of the loan under the loan agreement to repay a portion of its outstanding commercial paper, and for general corporate purposes. All indebtedness incurred under the loan agreement is unsecured, and the aggregate principal amount of all loans, together with any accrued but unpaid interest due under the loan agreement, must be repaid in full on or before July 28, 2016. Pursuant to the term loan agreement, PHI may consummate the Merger and the subsequent conversion of PHI from a Delaware corporation to a Delaware limited liability company, provided that the Merger and subsequent conversion are consummated on or before October 29, 2015. PHI requested and obtained the consent of the lenders under the term loan to allow for completion of the Merger by June 30, 2016.

ACE Term Loan Agreement

On May 10, 2013, ACE entered into a $100 million term loan agreement, pursuant to which ACE borrowed $100 million at a rate of interest equal to the prevailing Eurodollar rate, which was determined by reference to the London Interbank Offered Rate with respect to the relevant interest period, all as defined in the loan agreement, plus a margin of 0.75%. On August 21, 2014, ACE repaid the term loan in full.

Sale of Receivables

During 2015, Pepco, as seller, entered into a purchase agreement with a buyer to sell receivables from an energy savings project over a period of time pursuant to a task order. The purchase price to be received by Pepco is $5 million. Pursuant to the purchase agreement, following acceptance of the energy savings project by the buyer, the buyer is entitled to receive the contract payments under the task order payable by the customer over approximately 15 years. The energy savings project will be performed by Pepco Energy Services and is expected to be completed by the end of 2017.

During 2014, Pepco, as seller, entered into a purchase agreement with a buyer to sell receivables from an energy savings project pursuant to a task order entered into under a General Services Administration area-wide agreement. The purchase price received by Pepco was $12 million, which was included in the Current portion of long-term debt and project funding at December 31, 2014. The energy savings project was performed by Pepco Energy Services and was completed in 2014. Pursuant to the purchase agreement, following acceptance of the energy savings project by the buyer, the buyer was entitled to receive the contract payments under the task order payable by the buyer over approximately 9 years. The energy savings project was accepted during the first quarter of 2015 and the amount was removed from the Current portion of long-term debt and project funding.

During 2013, Pepco Energy Services, as seller, entered into a purchase agreement with a buyer to sell receivables from an energy savings project over a period of time pursuant to a task order. The purchase price received by Pepco Energy Services was $7 million, which was included in the Current portion of

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long-term debt and project funding at December 31, 2014. Pursuant to the purchase agreement, following acceptance of the energy savings project by the buyer, the buyer is entitled to receive the contract payments under the task order payable by the customer over approximately 23 years. The energy savings project was accepted during the first quarter of 2015 and the amount was removed from the Current portion of long-term debt and project funding.

Cash and Credit Facility Available as of December 31, 2015

	Consolidated PHI		PHI Parent		Utility Subsidiaries
	(millions of dollars)
Credit Facility (Total Capacity)	$	1,500	$	750	$	750
Less: Letters of Credit issued		1		1		—
Commercial Paper outstanding		658		484		174
Remaining Credit Facility Available		841		265		576
Cash Invested in Money Market Funds (a)		10		10		—
Total Cash and Credit Facility Available	$	851	$	275	$	576

(a) Cash and cash equivalents reported on the PHI consolidated balance sheet totaled $25 million, of which $10 million was invested in money market funds, and the balance was held in cash and uncollected funds.

Global Tax Settlement

PHI has recently settled through the Global Tax Settlement all tax matters in dispute with the IRS, including the appropriateness of certain significant income tax benefits claimed by PHI related to its cross-border energy lease investments beginning with its 2001 federal income tax return. In the first quarter of 2013, PHI made a $242 million advanced payment to the IRS, representing the estimated additional taxes and related interest that PHI would have been obligated to pay in the event the IRS were to be fully successful in its challenge to PHI’s tax position on the cross-border energy leases, adjusted for PHI’s estimate of the expected resolution of other uncertain and effectively settled tax positions unrelated to the leases, including the carrying back or carrying forward of any existing net operating losses and the application of certain amounts paid in advance to the IRS. This advanced payment of $242 million was funded from then currently available sources of liquidity and short-term borrowings.

As a result of the Global Tax Settlement, PHI has estimated that refunds of federal taxes and related interest will approximate $56 million for the resolution of all federal income tax liabilities for PHI through 2011. PHI expects the IRS to commence verification procedures on the estimated amount of the refund of federal taxes and related interest in the first quarter of 2016. Upon completion of the IRS verification procedures, the actual amount of the refund may differ significantly from PHI’s estimate. In addition, PHI has commenced the preparation and filing of amended state income tax returns that may result in further refunds of state income taxes for the open years subject to the federal tax adjustments incorporated into the Global Tax Settlement.

Pension and Other Postretirement Benefit Plans

PHI sponsors a non-contributory, defined benefit pension plan (the PHI Retirement Plan) that covers substantially all employees of Pepco, DPL and ACE and certain employees of other PHI subsidiaries. PHI also provides supplemental retirement benefits to certain eligible executive and key employees through nonqualified retirement plans. PHI’s funding policy with regard to the PHI Retirement Plan is to maintain a funding level that is at least equal to the target liability as defined under the Pension Protection Act of 2006, as modified by subsequent legislation.

Under the Pension Protection Act, if a plan incurs a funding shortfall in the preceding plan year, there can be required minimum quarterly contributions in the current and following plan years. In 2016, PHI, Pepco, DPL and ACE do not expect to make discretionary tax-deductible contributions to the PHI Retirement Plan. Management expects that the current balance of the PHI Retirement Plan assets is at

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least equal to the funding target liability for 2016 under the Pension Protection Act. During 2015 and 2014, PHI, Pepco, DPL and ACE made no discretionary tax-deductible contributions to the PHI Retirement Plan. PHI satisfied the minimum required contribution rules under the Pension Protection Act in 2015 and 2014. For additional discussion of PHI’s Pension and Other Postretirement Benefits, see Note (9), “Pension and Other Postretirement Benefits,” to the consolidated financial statements of PHI.

PHI provides certain postretirement health care and life insurance benefits for eligible retired employees. Most employees hired after January 1, 2005 or later will not have company subsidized retiree health care coverage; however, they will be able to purchase coverage at full cost through PHI.

In 2015 and 2014, Pepco contributed $2 million and $1 million, respectively, DPL made no contributions, and ACE contributed $3 million in each year to the other postretirement benefit plan. In 2015 and 2014, no contributions were made by other PHI subsidiaries.

Based on the results of the 2015 actuarial valuation, PHI’s net periodic pension and other postretirement benefit (OPEB) costs were approximately $97 million in 2015 versus $58 million in 2014. The current estimate of benefit cost for 2016 is $101 million. The increase in costs is primarily due to a reduction in pension trust assets as a result of benefit payments and market depreciation. For additional discussion, see Note (9), “Pension and Other Postretirement Benefits,” to the consolidated financial statements of PHI. The utility subsidiaries are responsible for substantially all of the total PHI net periodic pension and OPEB costs. Approximately 33% of net periodic pension and OPEB costs, excluding the nonqualified retirement plan costs, were capitalized in 2015. PHI estimates that its net periodic pension and OPEB expense will be approximately $71 million in 2016, as compared to $66 million in 2015 and $34 million in 2014.

Other Postretirement Benefit Plan Amendments

During 2013, PHI approved two amendments to its other postretirement benefits plan. These amendments impacted the retiree health care and the retiree life insurance benefits, and were effective on January 1, 2014. As a result of the amendments, which were cumulatively significant, PHI remeasured its accumulated postretirement benefit obligation as of July 1, 2013. The remeasurement resulted in a $193 million reduction of the accumulated postretirement benefit obligation, which included recording a prior service credit of $124 million, which will be amortized over approximately ten years, and a $69 million reduction from a change in the discount rate from 4.10% as of December 31, 2012 to 4.95% as of July 1, 2013.

Cash Flow Activity

PHI’s cash flows during 2015, 2014 and 2013 are summarized below:

	Cash Source (Use)
	2015			2014			2013
	(millions of dollars)
Operating Activities	$	939		$	854		$	497
Investing Activities		(1,161	)		(1,226	)		(411	)
Financing Activities		233			363			(88	)
Net increase (decrease) in cash and cash equivalents	$	11		$	(9	)	$	(2	)

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Operating Activities

Cash flows from operating activities during 2015, 2014 and 2013 are summarized below:

	Cash Source (Use)
	2015		2014			2013
	(millions of dollars)
Net income from continuing operations	$	318	$	242		$	110
Non-cash adjustments to net income		589		625			465
Pension contributions		—		—			(120	)
Advanced payment made to taxing authority		—		—			(242	)
Changes in cash collateral related to derivative activities		2		(9	)		31
Changes in other assets and liabilities		30		(4	)		206
Changes in net current assets held for disposition or sale		—		—			47
Net cash from operating activities	$	939	$	854		$	497

Net cash from operating activities increased $85 million for the year ended December 31, 2015, compared to the same period in 2014. The increase was primarily due to an increase in net income from continuing operations of $76 million and a $28 million increase in pension benefit obligations, excluding contributions, included in Changes in other assets and liabilities. This is partially offset by a $25 million payment made by PHI in the third quarter of 2015 to the District of Columbia for the purchase of future sponsorship rights, such as the rights expected to arise in connection with the development of certain sports and entertainment venues in the District of Columbia, including the Buzzard Point area where the District of Columbia has plans to develop a major league soccer stadium, included in Changes in other assets and liabilities.

Net cash from operating activities increased $357 million for the year ended December 31, 2014, compared to the same period in 2013. The increase was primarily due to an increase in net income from continuing operations of $132 million, a decrease in pension contributions of $120 million and a $242 million advanced payment to the IRS for estimated additional taxes and related interest made in 2013, partially offset by a $47 million reduction in net current assets held for disposition or sale associated with the termination of all cross-border energy lease investments and the wind-down of Pepco Energy Services’ retail electric and natural gas supply businesses.

Investing Activities

Cash flows used by investing activities during 2015, 2014 and 2013 are summarized below:

	Cash (Use) Source
	2015			2014			2013
	(millions of dollars)
Investment in property, plant and equipment	$	(1,230	)	$	(1,223	)	$	(1,310	)
DOE capital reimbursement awards received		—			4			22
Proceeds from sales of land		54			—			—
Changes in restricted cash equivalents		7			(12	)		1
Net other investing activities		8			5			3
Proceeds from discontinued operations, early termination of finance leases held in trust		—			—			873
Net cash used by investing activities	$	(1,161	)	$	(1,226	)	$	(411	)

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Net cash used by investing activities decreased $65 million for the year ended December 31, 2015, compared to the same period in 2014. The decrease was primarily due to a $54 million increase in proceeds from sales of land received in 2015 and a decrease in restricted cash equivalents related to changes in collateral received from third party suppliers for Default Electricity.

Net cash used by investing activities increased $815 million for the year ended December 31, 2014, compared to the same period in 2013. The increase was primarily due to $873 million of proceeds from discontinued operations related to the termination of all cross-border energy lease investments received in 2013.

Financing Activities

Cash flows from financing activities during 2015, 2014 and 2013 are summarized below:

	Cash (Use) Source
	2015			2014			2013
	(millions of dollars)
Dividends paid on common stock	$	(275	)	$	(272	)	$	(270	)
Common stock issued for the Direct Stock Purchase and Dividend Reinvestment Plan (DRP) and employee-related compensation (a)		18			34			50
Issuances of common stock		—			—			324
Issuance of Series A preferred stock		54			126			—
Issuances of long-term debt		558			766			800
Reacquisitions of long-term debt		(420	)		(334	)		(558	)
Issuances (repayments) of short-term debt, net		34			164			(200	)
Borrowings under term loans		300			—			250
Repayments of term loans		—			(100	)		(450	)
Cost of issuances		(7	)		(10	)		(23	)
Net other financing activities		(29	)		(11	)		(11	)
Net cash from (used by) financing activities	$	233		$	363		$	(88	)

(a) Prior to October 1, 2013, the DRP was named the Shareholder Dividend Reinvestment Plan.

Net cash from financing activities decreased $130 million for the year ended December 31, 2015, compared to the same period in 2014. The decrease was primarily due to a $130 million decrease in short-term debt issuances, net of repayments, a $294 million decrease in long-term debt issuances, net of reacquisitions, and a $72 million decrease in issuances of Series A preferred stock, partially offset by a $300 million term loan borrowing in 2015 and a $100 million term loan repayment in 2014.

Net cash from financing activities increased $451 million for the year ended December 31, 2014, compared to the same period in 2013. The increase was primarily due to a net increase of $190 million in long-term debt, a net decrease of $100 million in term loans, an increase of $364 million of short-term debt issuances, and an issuance of preferred stock of $126 million, partially offset by issuances of common stock of $324 million in 2013 primarily due to the settlement of an equity forward transaction. For additional information about the equity forward transaction, please refer to Note (12), “Stock-Based Compensation, Dividend Restrictions, and Calculations of Earnings Per Share of Common Stock,” to the consolidated financial statements of PHI.

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Common Stock Dividends

Common stock dividend payments were $275 million in 2015, $272 million in 2014 and $270 million in 2013.

Changes in Outstanding Common Stock

PHI issued approximately 1 million shares of common stock in each of 2015, 2014 and 2013 under PHI’s long-term incentive plans.

Under the DRP, PHI issued less than 1 million shares of common stock in 2015, 1.1 million shares of common stock in 2014, and 1.6 million shares of common stock in 2013.

In February 2013, PHI issued 17.9 million shares of common stock pursuant to the settlement of the equity forward transaction.

Changes in Outstanding Long-Term Debt

Cash flows from issuances and reacquisitions of long-term debt in 2015, 2014 and 2013 are summarized in the tables below:

	2015		2014		2013
	(millions of dollars)
Issuances
Pepco
4.15% First mortgage bonds due 2043	$	208	$	—	$	250
4.95% First mortgage bonds due 2043		—		—		150
3.60% First mortgage bonds due 2024		—		400		—
Project Funding Debt		—		12		—
		208		412		400
DPL
4.15% First mortgage bonds due 2045		200		—		—
3.50% First mortgage bonds due 2023		—		204		300
		200		204		300
ACE
3.50% First mortgage bonds due 2025		150		—		—
3.375% First mortgage bonds due 2024		—		150		—
Variable rate term loan due 2014		—		—		100
		150		150		100
	$	558	$	766	$	800

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	2015		2014		2013
	(millions of dollars)
Reacquisitions
PHI
2.70% Unsecured notes due 2015	$	250	$	—	$	—
		250		—		—
Pepco
Project Funding Debt		12		—		—
4.65% First mortgage bonds due 2014		—		175		—
4.95% First mortgage bonds due 2013		—		—		200
		12		175		200
DPL
5.00% Unsecured notes due 2015		100		—		—
5.00% Unsecured notes due 2014		—		100		—
6.40% First mortgage bonds due 2013 (a)		—		—		250
		100		100		250
ACE
Securitization bonds due 2013-2015		43		41		39
7.68% First mortgage bonds due 2015		15		—		—
7.63% First mortgage bonds due 2014		—		7		—
6.625% First mortgage bonds due 2013		—		—		69
		58		48		108
PCI
6.59%-6.69% Recourse Debt		—		11		—
		—		11		—
	$	420	$	334	$	558

(a) These bonds were secured by an outstanding series of collateral first mortgage bonds issued by the utility, which had maturity dates, optional and mandatory redemption provisions, interest rates and interest payment dates that were identical to the terms of the tax-exempt bonds. The collateral first mortgage bonds were automatically redeemed simultaneously with the redemption of the tax-exempt bonds.

First Mortgage Bond Issuances

During 2015, Pepco issued $200 million of 4.15% first mortgage bonds due March 15, 2043, with a 3.9% yield to maturity. Net proceeds from the issuance of the bonds, which included a premium of $8 million, were used by Pepco to repay outstanding commercial paper and for general corporate purposes.

During 2015, DPL issued $200 million of 4.15% first mortgage bonds due May 15, 2045. Net proceeds from the issuance of the bonds were used by DPL to repay outstanding commercial paper and for general corporate purposes.

During 2015, ACE issued $150 million of 3.50% first mortgage bonds due December 1, 2025 in a private placement. The net proceeds from the issuance of the bonds were used by ACE to repay outstanding commercial paper and for general corporate purposes.

During 2014, Pepco issued $400 million of 3.60% first mortgage bonds due March 15, 2024. These bonds were issued under a Mortgage and Deed of Trust and are secured thereunder by a first lien, subject to certain leases, permitted liens and other exceptions, on substantially all of Pepco’s properties, except for such property excluded from the lien of the Mortgage and Deed of Trust. Pepco used a portion of the net proceeds of the offering to repay in full at maturity $175 million in aggregate principal amount of its 4.65% senior notes due April 15, 2014, plus accrued and unpaid interest.

During 2014, DPL issued $200 million of its 3.50% first mortgage bonds due November 15, 2023. These bonds were issued under a Mortgage and Deed of Trust and are secured thereunder by a first lien, subject to certain leases, permitted liens and other exceptions, on substantially all of DPL’s properties, except for such property excluded from the lien of the Mortgage and Deed of Trust. Net proceeds from the issuance of the bonds, which included a premium of $4 million, were used to repay DPL’s outstanding commercial paper and for general corporate purposes.

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During 2014, ACE issued $150 million of its 3.375% first mortgage bonds due September 1, 2024. These bonds were issued under a Mortgage and Deed of Trust and are secured thereunder by a first lien, subject to certain leases, permitted liens and other exceptions, on substantially all of ACE’s properties, except for such property excluded from the lien of the Mortgage and Deed of Trust. ACE used $7 million of the net proceeds from the issuance of the bonds to repay in full at maturity $7 million in aggregate principal amount of ACE’s 7.63% secured medium term notes due August 29, 2014, plus accrued and unpaid interest thereon. ACE used the remainder of the net proceeds to repay its outstanding commercial paper, including commercial paper that ACE issued to prepay in full its $100 million term loan, and for general corporate purposes.

During 2013, Pepco issued $250 million of 4.15% first mortgage bonds due March 15, 2043 and $150 million of 4.95% first mortgage bonds due November 15, 2043. Net proceeds from the issuance of the 4.15% bonds were used to repay Pepco’s outstanding commercial paper and for general corporate purposes. The net proceeds from the 4.95% bonds were used to repay outstanding commercial paper, including commercial paper issued to repay in full at maturity $200 million of Pepco’s 4.95% senior notes due November 15, 2013, plus accrued but unpaid interest thereon. The senior notes were secured by a like principal amount of Pepco first mortgage bonds, which under Pepco’s Mortgage and Deed of Trust were deemed to be satisfied with the repayment of the senior notes.

During 2013, DPL issued $300 million of 3.50% first mortgage bonds due November 15, 2023. The net proceeds from the issuance of the bonds were used to repay at maturity $250 million of DPL’s 6.40% first mortgage bonds due December 1, 2013, plus accrued but unpaid interest thereon, to repay outstanding commercial paper and for general corporate purposes.

Reacquisitions of Long-term Debt

During 2015, PHI retired, at maturity, $250 million of its 2.70% unsecured notes due October 1, 2015.

During 2015, DPL retired, at maturity, $100 million of its 5.00% unsecured notes due June 1, 2015.

During 2015, ACE retired, at maturity, $15 million of its secured medium-term notes series C. The medium-term notes were secured by a like principal amount of its 7.68% first mortgage bonds due August 24, 2015, which under the mortgage and deed of trust were deemed to be satisfied when the medium-term notes were repaid.

During 2014, Pepco retired, at maturity, $175 million of its 4.65% senior notes. The senior notes were secured by a like principal amount of its 4.65% first mortgage bonds due April 15, 2014, which under Pepco’s mortgage and deed of trust were deemed to be satisfied when the senior notes were repaid.

During 2014, DPL retired, at maturity, $100 million of its 5.00% unsecured notes.

During 2014, ACE retired, at maturity, $7 million of its 7.63% medium term notes due August 29, 2014. The notes were secured by a like principal amount of first mortgage bonds due August 29, 2014, which under ACE’s mortgage and deed of trust were deemed to be satisfied when the notes were repaid.

During 2014, PCI retired, at maturity, $11 million of bank loans.

During 2013, Pepco retired, at maturity, $200 million of its 4.95% senior notes, which were secured by a like principal amount of Pepco’s first mortgage bonds as previously discussed above.

During 2013, DPL retired, at maturity, $250 million of its 6.40% first mortgage bonds.

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During 2013, ACE retired, at maturity, $69 million of its 6.625% non-callable first mortgage bonds. ACE also funded the redemption, prior to maturity, of $4 million of outstanding weekly rate pollution control revenue refunding bonds due 2017, issued by the Pollution Control Financing Authority of Salem County, New Jersey for ACE’s benefit.

Changes in Short-Term Debt

As of December 31, 2015, PHI had a total of $658 million of commercial paper outstanding as compared to $624 million and $442 million of commercial paper outstanding at December 31, 2014 and 2013, respectively.

Capital Requirements

Capital Expenditures

Pepco Holdings’ capital expenditures for the year ended December 31, 2015 totaled $1,230 million, an increase of $7 million from $1,223 million in 2014. Capital expenditures in 2015 were $544 million for Pepco, $352 million for DPL, $300 million for ACE, $3 million for Pepco Energy Services and $31 million for Corporate and Other. The Power Delivery expenditures were primarily related to capital costs associated with distribution and transmission services. Corporate and Other capital expenditures primarily consisted of hardware and software expenditures that will be allocated to Power Delivery when the assets are placed in service.

The table below shows the projected capital expenditures for Power Delivery, Pepco Energy Services and Corporate and Other for the five-year period 2016 through 2020. PHI expects to fund these expenditures through internally generated cash and external financing.

	For the Year Ended December 31,
	2016		2017		2018		2019		2020		Total
	(millions of dollars)
Power Delivery
Distribution	$	798	$	874	$	894	$	801	$	815	$	4,182
Transmission		456		440		504		398		256		2,054
Gas Delivery		32		35		36		38		40		181
Other		109		80		66		56		56		367
Total for Power Delivery		1,395		1,429		1,500		1,293		1,167		6,784
Pepco Energy Services		1		1		1		1		1		5
Corporate and Other		6		6		6		6		6		30
Total PHI	$	1,402	$	1,436	$	1,507	$	1,300	$	1,174	$	6,819

Transmission and Distribution

The projected capital expenditures listed in the table for distribution, transmission and gas delivery are primarily for facility replacements and upgrades to accommodate customer growth and service reliability, including capital expenditures for continuing reliability enhancement efforts. For a more detailed discussion of these efforts, see “General Overview – Power Delivery.” The projected capital expenditures related to the DC PLUG initiative are included as part of distribution expenditures in the table above.

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DOE Capital Reimbursement Awards

In 2009, the Department of Energy (DOE) announced awards under the American Recovery and Reinvestment Act of 2009 of:

• $105 million and $44 million in Pepco’s Maryland and District of Columbia service territories, respectively, for the implementation of an AMI system, direct load control, distribution automation, and communications infrastructure.

• $19 million in ACE’s New Jersey service territory for the implementation of an AMI system, direct load control, distribution automation, and communications infrastructure.

Of the total $168 million in DOE awards, $130 million was offset against smart grid-related capital expenditures of Pepco and ACE. The remaining $38 million was used to offset incremental expenditures associated with direct load control and other Pepco and ACE programs, which were deferred as regulatory assets. As of December 31, 2015, Pepco and ACE have received all of their DOE award payments.

The IRS announced that, to the extent these grants are expended on capital items, they would not be considered taxable income.

Dividends

Pepco Holdings’ annual dividend rate on its common stock is determined by the Board of Directors on a quarterly basis and takes into consideration, among other factors, current and possible future developments that may affect PHI’s income and cash flows. In 2015, PHI’s Board of Directors declared quarterly dividends of 27 cents per share of common stock payable on March 31, 2015, June 30, 2015, September 30, 2015 and December 31, 2015.

PHI, on a stand-alone basis, generates no operating income of its own. Accordingly, its ability to pay dividends to its shareholders depends on dividends received from its subsidiaries. In addition to their future financial performance, the ability of each of PHI’s direct and indirect subsidiaries to pay dividends is subject to limits imposed by: (i) state corporate laws, which impose limitations on the funds that can be used to pay dividends and when such dividends can be paid, and, in the case of ACE, the regulatory requirement that it obtain the prior approval of the NJBPU before dividends can be paid if its equity as a percent of its total capitalization, excluding securitization debt, falls below 30%; (ii) the prior rights of holders of existing and future mortgage bonds and other long-term debt issued by the subsidiaries, and any preferred stock that may be issued by the subsidiaries in the future, (iii) any other restrictions imposed in connection with the incurrence of liabilities; and (iv) certain provisions of ACE’s charter that impose restrictions on payment of common stock dividends for the benefit of preferred stockholders. In addition, if the Merger is not completed, PHI and each of its utility subsidiaries expect that they will be required to undertake certain actions to address their ongoing results of operations and financial condition. These actions are likely to include, but may not be limited to, a reevaluation of PHI’s common stock dividend policy. None of Pepco, DPL or ACE currently have shares of preferred stock outstanding. Currently, the capitalization ratio limitation to which ACE is subject and the restriction in the ACE charter do not limit ACE’s ability to pay common stock dividends. PHI had approximately $617 million and $565 million of retained earnings free of restrictions at December 31, 2015 and 2014, respectively. These amounts represent the total retained earnings balances at those dates.

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Contractual Obligations and Commercial Commitments

Summary information about Pepco Holdings’ consolidated contractual obligations and commercial commitments at December 31, 2015, is as follows:

			Contractual Maturity
Contractual Obligations	Total		Less than 1 Year		2-3 Years		4-5 Years		After 5 Years
	(millions of dollars)
Variable rate demand bonds	$	105	$	105	$	—	$	—	$	—
Commercial paper		658		658		—		—		—
Term loan		300		300		—		—		—
Long-term debt (a)		5,172		340		416		50		4,366
Long-term project funding		5		1		1		2		1
Interest payments on debt		3,845		262		473		428		2,682
Capital leases, including interest		61		15		30		16		—
Operating leases		522		52		95		71		304
Non-derivative power purchase contracts (b)		2,202		268		469		472		993
Total (c)	$	12,870	$	2,001	$	1,484	$	1,039	$	8,346

(a) Includes Transition Bonds issued by ACE Funding.

(b) Excludes contracts for the purchase of electricity to satisfy Default Electricity Supply load service obligations which have neither a fixed commitment amount nor a minimum purchase amount. In addition, costs are recoverable from customers.

(c) Excludes $22 million of net current and non-current liabilities related to uncertain tax positions due to uncertainty in the timing of the associated cash payments.

Guarantees, Indemnifications and Off-Balance Sheet Arrangements

PHI and certain of its subsidiaries have various financial and performance guarantees and indemnification obligations that they have entered into in the normal course of business to facilitate commercial transactions with third parties.

PHI guarantees the obligations of Pepco Energy Services under certain contracts in its energy savings performance contracting business and underground transmission and distribution construction business. At December 31, 2015, PHI’s guarantees of Pepco Energy Services’ obligations under these contracts totaled $269 million. PHI also guarantees the obligations of Pepco Energy Services under surety bonds obtained by Pepco Energy Services for construction projects. These guarantees totaled $177 million at December 31, 2015.

In addition, PHI guarantees certain obligations of Pepco, DPL and ACE under surety bonds obtained by these subsidiaries, for construction projects and self-insured workers compensation matters. These guarantees totaled $56 million at December 31, 2015.

For additional discussion of PHI’s third party guarantees, indemnifications, obligations and off-balance sheet arrangements, see Note (16), “Commitments and Contingencies – Third Party Guarantees, Indemnifications, and Off-Balance Sheet Arrangements,” to the consolidated financial statements of PHI.

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Contractual Arrangements with Credit Rating Triggers or Margining Rights

Under certain contractual arrangements entered into by PHI’s subsidiaries, the subsidiary may be required to provide cash collateral or letters of credit as security for its contractual obligations if the credit ratings of PHI or the subsidiary are downgraded. In the event of a downgrade, the amount required to be posted would depend on the amount of the underlying contractual obligation existing at the time of the downgrade. Based on contractual provisions in effect at December 31, 2015, a downgrade in the unsecured debt credit ratings of PHI and each of its rated subsidiaries to below “investment grade” would increase the collateral obligation of PHI and its subsidiaries by up to $32 million. This amount is attributable primarily to project financing for energy services contracts and accounts payable to independent system operators and distribution companies. PHI believes that it and its subsidiaries currently have sufficient liquidity to fund their operations and meet their financial obligations.

Many of the contractual arrangements entered into by PHI’s subsidiaries in connection with Default Electricity Supply activities include margining rights pursuant to which the PHI subsidiary or a counterparty may request collateral if the market value of the contractual obligations reaches levels in excess of the credit thresholds established in the applicable arrangements. Pursuant to these margining rights, the affected PHI subsidiary may receive, or be required to post, collateral due to energy price movements. PHI believes that it and its subsidiaries currently have sufficient liquidity to fund their operations and meet their financial obligations.

Environmental Remediation Obligations

PHI’s accrued liabilities for environmental remediation obligations as of December 31, 2015 totaled approximately $33 million, of which approximately $4 million is expected to be incurred in 2016, for potential environmental cleanup and related costs at sites owned or formerly owned by an operating subsidiary where an operating subsidiary is a potentially responsible party or is alleged to be a third-party contributor. For further information concerning the remediation obligations associated with these sites, see Note (16), “Commitments and Contingencies – Environmental Matters,” to the consolidated financial statements of PHI. The most significant environmental remediation obligations as of December 31, 2015, are for the following items:

• Environmental investigation and remediation costs payable by Pepco with respect to the Benning Road site.

• Amounts payable by Pepco in connection with a January 2011 mineral oil release at Pepco’s Potomac River substation in Alexandria, Virginia.

• Estimated costs for implementation of a closure plan and cap on a Pepco right-of-way that traverses the NRG Energy, Inc. (as successor to GenOn MD Ash Management, LLC) (NRG) fly ash disposal site in Brandywine, Prince George’s County, Maryland. PHI and Pepco believe that the costs incurred in this matter will be recoverable from NRG under a 2000 agreement covering the sale of this site, the terms of which specify that the buyer of Pepco’s generation assets assumed environmental liability for hazardous substances, including ash, which remain on or have been removed from the land on which the acquired generating stations are situated.

• Estimated costs for implementation of a closure plan for the Edge Moor landfill.

• Costs associated with investigation and resolution of potential impacts from a September 2013 mineral oil release from a Pepco underground feeder to Watts Branch.

• Amounts payable by DPL in accordance with a 2001 consent agreement reached with the Delaware Department of Natural Resources and Environmental Control, for remediation, site restoration, natural resource damage compensatory projects and other costs associated with environmental contamination that resulted from an oil release at the Indian River power plant, which DPL sold in June 2001.

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• Potential compliance remediation costs under New Jersey’s Industrial Site Recovery Act payable by PHI associated with the retained environmental exposure from the sale of the Conectiv Energy wholesale power generation business.

• Amounts payable by DPL in connection with the Wilmington Coal Gas South site located in Wilmington, Delaware, to remediate residual material from the historical operation of a manufactured gas plant.

Sources of Capital

PHI’s sources to meet its long-term funding needs, such as capital expenditures, dividends, and new investments, and its short-term funding needs, such as working capital and the temporary funding of long-term funding needs, include internally generated funds, issuances by PHI, Pepco, DPL and ACE under their commercial paper programs, securities issuances, medium- and short-term loans, and bank financing under new or existing facilities. PHI’s ability to generate funds from its operations and to access capital and credit markets is subject to risks and uncertainties. Volatile and deteriorating financial market conditions, diminished liquidity and tightening credit may affect access to certain of PHI’s potential funding sources.

Cash Flow from Operations

Cash flow generated by regulated utility subsidiaries in Power Delivery is the primary source of PHI’s cash flow from operations. Additional cash flows are generated by the business of Pepco Energy Services and from the occasional sale of non-core assets.

Short-Term Funding Sources

Pepco Holdings and its regulated utility subsidiaries have traditionally used a number of sources to fulfill short-term funding needs, such as commercial paper, short-term notes and bank term loans and lines of credit. Proceeds from short-term borrowings are used primarily to meet working capital needs but may also be used to temporarily fund long-term capital requirements. For additional discussion of PHI’s short-term debt, see Note (10), “Debt,” to the consolidated financial statements of PHI.

Long-Term Funding Sources

The sources of long-term funding for PHI and its subsidiaries are the issuance of debt and equity securities and borrowing under long-term credit agreements. Proceeds from long-term financings are used primarily to fund long-term capital requirements, such as capital expenditures and new investments, and to repay or refinance existing indebtedness.

Regulatory Restrictions on Financing Activities

The issuance of debt securities by PHI’s principal subsidiaries requires the approval of either FERC or one or more state public utility commissions. Neither FERC approval nor state public utility commission approval is required as a condition to the issuance of securities by PHI.

State Financing Authority

Pepco’s long-term financing activities (including the issuance of securities and the incurrence of long-term debt) are subject to authorization by the DCPSC and MPSC. DPL’s long-term financing activities are subject to authorization by the MPSC and the DPSC. ACE’s long-term and short-term (consisting of debt instruments with a maturity of one year or less) financing activities are subject to authorization by the NJBPU. Each utility, through periodic filings with the state public service commission(s) having jurisdiction over its financing activities, has maintained standing authority sufficient to cover its projected financing needs over a multi-year period.

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FERC Financing Authority

Under the Federal Power Act (FPA), FERC has jurisdiction over the issuance of long-term and short-term securities of public utilities, but only if the issuance is not regulated by the state public utility commission in which the public utility is organized and operating. Under these provisions, FERC has jurisdiction over the issuance of short-term debt by Pepco and DPL. Pepco and DPL have obtained FERC authority for the issuance of short-term debt. Because Pepco Energy Services also qualifies as a public utility under the FPA and is not regulated by a state utility commission, FERC also has jurisdiction over the issuance of securities by Pepco Energy Services. Pepco Energy Services has obtained the requisite FERC financing authority in its market-based rate orders.

Money Pool

Pepco Holdings operates a system money pool under a blanket authorization adopted by FERC. The money pool is an unsecured cash management mechanism used by Pepco Holdings to manage the short-term investment and borrowing requirements of its subsidiaries that participate in the money pool. Pepco Holdings may invest in but not borrow from the money pool. Eligible subsidiaries with surplus cash may deposit those funds in the money pool. Deposits in the money pool are guaranteed by Pepco Holdings. Eligible subsidiaries with cash requirements may borrow from the money pool. Depositors in the money pool receive, and borrowers from the money pool pay, an interest rate based primarily on Pepco Holdings’ short-term borrowing rate. Pepco Holdings deposits funds in the money pool to the extent that the pool has insufficient funds to meet the borrowing needs of its participants, which may require Pepco Holdings to borrow funds for deposit from external sources.

Regulatory and Other Matters

Rate Proceedings

Distribution

The rates that each of Pepco, DPL and ACE is permitted to charge for the retail distribution of electricity and natural gas to its various classes of customers are based on the principle that the utility is entitled to generate an amount of revenue sufficient to recover the cost of providing the service, including a reasonable rate of return on its invested capital. These “base rates” are intended to cover all of each utility’s reasonable and prudent expenses of constructing, operating and maintaining its distribution facilities (other than costs covered by specific cost-recovery surcharges).

A change in base rates in a jurisdiction requires the approval of the public service commission. In the rate application submitted to the public service commission, the utility specifies an increase in its “revenue requirement,” which is the additional revenue that the utility is seeking authorization to earn. The “revenue requirement” consists of (i) the allowable expenses incurred by the utility, including operation and maintenance expenses, taxes and depreciation, and (ii) the utility’s cost of capital. The compensation of the utility for its cost of capital takes the form of an overall “rate of return” allowed by the public service commission on the utility’s distribution “rate base” to compensate the utility’s investors for their debt and equity investments in the company. The rate base is the aggregate value of the investment in property used by the utility in providing electricity and natural gas distribution services and generally consists of plant in service net of accumulated depreciation and accumulated deferred taxes, plus cash working capital, material and operating supplies and, depending on the jurisdiction, construction work in progress. Over time, the rate base is increased by utility property additions and reduced by depreciation and property retirements and write-offs.

In addition to its base rates, some of the costs of providing distribution service are recovered through the operation of surcharges. Examples of costs recovered by PHI’s utility subsidiaries through surcharges, which vary depending on the jurisdiction, include: a surcharge to reimburse the utility for the cost of purchasing electricity from NUGs (New Jersey); surcharges to reimburse the utility for costs of public interest programs for low income customers and for demand-side management programs (New Jersey,

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Maryland, Delaware and the District of Columbia); a surcharge to pay the Transitional Bond Charge (New Jersey); surcharges to reimburse the utility for certain environmental costs (Delaware and Maryland); and surcharges related to the BSA (Maryland and the District of Columbia). Each utility subsidiary regularly reviews its distribution rates in each jurisdiction of its service territory, and files applications to adjust its rates as necessary in an effort to ensure that its revenues are sufficient to cover its operating expenses and its cost of capital. The timing of future rate filings and the change in the distribution rate requested will depend on a number of factors, including changes in revenues and expenses and the incurrence or the planned incurrence of capital expenditures.

As further described in the “– General Overview – Agreement and Plan of Merger with Exelon Corporation,” PHI has entered into the Merger Agreement with Exelon and Merger Sub. Subject to certain exceptions, prior to the Merger or the termination of the Merger Agreement, PHI and its subsidiaries may not, without the consent of Exelon, initiate, file or pursue any rate cases, other than concluding pending filings.

In general, a request for new distribution rates is made on the basis of “test year” balances for rate base allowable operating expenses and a requested rate of return. The test year amounts used in the filing may be historical or partially projected. The public service commission may, however, select a different test period than that proposed by the applicable utility. Although the approved tariff rates are intended to be forward-looking, and therefore provide for the recovery of some future changes in rate base and operating costs, they typically do not reflect all of the changes in costs for the period in which the new rates are in effect. See “– General Overview – Power Delivery Initiatives and Activities – Mitigation of Regulatory Lag.”

The following table shows, for each of the PHI utility subsidiaries, the authorized return on equity as determined in the most recently concluded base rate proceeding and the effective date of the authorized return:

	Authorized Return on Equity			Rate Effective Date
Pepco:
District of Columbia (electricity)		9.40	%	April 2014
Maryland (electricity)		9.62	%	July 2014
DPL:
Delaware (electricity)		9.70	%	May 2014 (a)
Maryland (electricity)		9.81	% (b)	September 2013
Delaware (natural gas)		9.75	% (c)	November 2013
ACE:
New Jersey (electricity)		9.75	%	September 2014

(a) Beginning in September 2014, DPL provided credits or refunds to any customer whose rates were increased in October 2013 in excess of the increase approved by the DPSC in April 2014.

(b) ROE has not been determined by any proceeding and is specified only for the purposes of calculating the AFUDC and regulatory asset carrying costs.

(c) ROE has not been determined by any proceeding and is specified only for reporting purposes and for calculating the AFUDC, construction work in progress, regulatory asset carrying costs and other accounting metrics.

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Transmission

The rates Pepco, DPL and ACE are permitted to charge for the transmission of electricity are regulated by FERC and are based on each utility’s transmission rate base, transmission operating expenses and an overall rate of return that is approved by FERC. For each utility subsidiary, FERC has approved a formula for the calculation of the utility transmission rate, which is referred to as a “formula rate.” The formula rates include both fixed and variable elements. Certain of the fixed elements, such as the return on equity and depreciation rates, can be changed only in a FERC transmission rate proceeding. The variable elements of the formula, including the utility’s rate base and operating expenses, are updated annually, effective June 1 of each year, with data from the utility’s most recent annual FERC Form 1 filing.

In addition to its formula rate, each utility’s return on equity is supplemented by incentive rates, sometimes referred to as “adders,” and other incentives, which are authorized by FERC to promote capital investment in transmission infrastructure. The base ROE currently authorized by FERC for PHI’s utilities is (i) 11.3% for facilities placed into service after January 1, 2006, and (ii) 10.8% for facilities placed into service prior to 2006. The 10.8% base ROE for facilities placed into service prior to 2006 receives a 50-basis-point incentive adder for being a member of a regional transmission organization. In addition, ROE adders are in effect for each of Pepco, DPL and ACE relating to specific transmission upgrades and improvements. Subject to FERC’s approval of a settlement agreement, effective March 8, 2016, the authorized base ROE for PHI’s utilities will be 10.0%, to which a 50-basis-point incentive adder will be applied for being a member of a regional transmission organization. As members of PJM, the transmission rates of Pepco, DPL and ACE are set out in PJM’s Open Access Transmission Tariff. For additional information regarding the settlement agreement referred to above, see Note (7), “Regulatory Matters – Rate Proceedings – FERC Transmission ROE Challenges,” to the consolidated financial statements of PHI.

Legal Proceedings and Regulatory Matters

For a discussion of legal proceedings, see Note (15), “Commitments and Contingencies,” to the consolidated financial statements of PHI, and for a discussion of regulatory matters, see Note (7), “Regulatory Matters,” to the consolidated financial statements of PHI.

Critical Accounting Policies

General

PHI has identified the following critical accounting policies that result in having to make certain estimates that, as a result of the judgments, uncertainties, uniqueness and complexities of the underlying accounting standards and estimates involved, could result in material changes in its financial condition or results of operations under different conditions or using different assumptions. PHI has discussed the development, selection and disclosure of each of these policies with the Audit Committee of the Board of Directors.

Goodwill Impairment Evaluation

Substantially all of PHI’s goodwill was generated by Pepco’s acquisition of Conectiv in 2002 and is allocated entirely to the Power Delivery reporting unit for purposes of assessing impairment under FASB guidance on goodwill and other intangibles (ASC 350). PHI has identified Power Delivery as a single reporting unit because its components have similar economic characteristics, similar products and services, similar distribution methods and support processes, and operate in a similar regulatory environment.

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PHI tests its goodwill for impairment annually as of November 1 and whenever an event occurs or circumstances change in the interim that would more likely than not (that is, a greater than 50% chance) reduce the estimated fair value of a reporting unit below the carrying amount of its net assets.

Factors that may result in an interim impairment test include, but are not limited to: an adverse change in business conditions; a protracted decline in stock price causing market capitalization to fall significantly below book value; an adverse regulatory action; impairment of long-lived assets in the reporting unit; or a change in identified reporting units.

In evaluating goodwill for impairment, PHI first assesses qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. For reporting units in which PHI concludes that it is more likely than not that the fair value is more than its carrying value, goodwill is not considered impaired and PHI is not required to perform the two-step goodwill impairment test. Qualitative factors considered in this assessment include industry and market considerations, including the price per share of PHI common stock, overall financial performance, lack of significant changes in any key inputs to the prior year impairment test, including the discount rate and forecasted cash flows, and other relevant events and factors affecting the reporting unit.

For reporting units in which PHI concludes that it is more likely than not that the fair value is less than its carrying value, PHI performs the first step of the goodwill impairment test. The first step of the goodwill impairment test compares the estimated fair value of the reporting unit with its carrying amount, including goodwill. PHI uses its best judgment to make reasonable projections of future cash flows and selection of a discount rate for the associated risk with those cash flows when estimating the reporting unit’s fair value. These judgments are inherently uncertain, and actual results could vary from those used in PHI’s estimates. The impact of such variations could significantly alter the results of a goodwill impairment test, which could materially impact the estimated fair value of Power Delivery and potentially the amount of any impairment recorded in the financial statements.

PHI’s November 1, 2015 annual impairment test indicated that its goodwill was not impaired. See Note (6), “Goodwill,” to the consolidated financial statements of PHI.

In order to estimate the fair value of the Power Delivery reporting unit, PHI prepares an analysis of traditional valuation techniques: an income approach and a market approach. The income approach estimates fair value based on a discounted future cash flow analysis and a terminal value that is consistent with Power Delivery’s long-term view of the business. This approach uses a discount rate based on the estimated weighted average cost of capital (WACC) for the reporting unit. PHI determines the estimated WACC by considering appropriate market-based information for the cost of equity and cost of debt as of the measurement date. The market approach estimates fair value based on a multiple of earnings before interest, taxes, depreciation and amortization (EBITDA) that PHI believes is consistent with EBITDA multiples for comparable utilities. PHI has consistently used this valuation technique to estimate the fair value of Power Delivery.

The estimation of fair value is dependent on a number of factors including but not limited to interest rates, growth assumptions, returns on rate base, operating and capital expenditure requirements, and other factors, changes in which could materially impact the results of impairment testing. Assumptions used were consistent with historical experience, including assumptions concerning the recovery of operating costs and capital expenditures, and current market-based information. A hypothetical 10 percent decrease in estimated fair value of the Power Delivery reporting unit at November 1, 2015 would not have resulted in the Power Delivery reporting unit failing the first step of the impairment test, as defined in the guidance, as the estimated fair value of the reporting unit would have been above its carrying value. Sensitive, interrelated and uncertain variables that could decrease the estimated fair value of the Power Delivery reporting unit include utility sector market performance, sustained adverse business conditions, change in forecasted revenues, higher operating and maintenance capital expenditure requirements, a significant increase in the weighted average cost of capital, and other factors.

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PHI believes that the estimates involved in its goodwill impairment evaluation process represent “Critical Accounting Estimates” because they are subjective and susceptible to change from period to period as PHI makes assumptions and judgments, and the impact of a change in such assumptions and estimates could be material to financial results.

Long-Lived Assets Impairment Evaluation

PHI believes that the estimates involved in its long-lived asset impairment evaluation process represent “Critical Accounting Estimates” because (i) they are highly susceptible to change from period to period because PHI is required to make assumptions and judgments about when events indicate the carrying value may not be recoverable and how to estimate undiscounted and discounted future cash flows and fair values, which are inherently uncertain, (ii) actual results could vary from those used in PHI’s estimates and the impact of such variations could be material, and (iii) the impact that recognizing an impairment would have on PHI’s assets as well as the net loss related to an impairment charge could be material. The primary assets subject to a long-lived asset impairment evaluation are property, plant, and equipment.

The FASB guidance on the accounting for the impairment or disposal of long-lived assets (ASC 360), requires that certain long-lived assets must be tested for recoverability whenever events or circumstances indicate that the carrying amount may not be recoverable, such as (i) a significant decrease in the market price of a long-lived asset or asset group, (ii) a significant adverse change in the extent or manner in which a long-lived asset or asset group is being used or in its physical condition, (iii) a significant adverse change in legal factors or in the business climate, including an adverse action or assessment by a regulator, (iv) an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset or asset group, (v) a current-period operating or cash flow loss combined with a history of operating or cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset or asset group, and (vi) a current expectation that, more likely than not, a long-lived asset or asset group will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.

An impairment loss may only be recognized if the carrying amount of an asset is not recoverable and the carrying amount exceeds its estimated fair value. The asset is deemed not to be recoverable when its carrying amount exceeds the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset. PHI uses reasonable estimates in making these evaluations of an asset’s future cash flows and considers various factors, including forward price curves for energy, related fuel costs, legislative initiatives, operating costs, and historical cash flows.

Pension and Other Postretirement Benefit Plans

PHI believes that the estimates involved in reporting the costs of providing pension and OPEB benefits represent Critical Accounting Estimates because (i) they are based on an actuarial calculation that includes a number of assumptions which are subjective in nature, (ii) they are dependent on numerous factors resulting from actual plan experience and assumptions of future experience, and (iii) changes in assumptions could impact PHI’s expected future cash funding requirements for the benefit plans and would have an impact on the benefit obligations, which affect the reported amount of net periodic pension and OPEB cost on the consolidated income statement.

Assumptions about the future, including the discount rate applied to benefit obligations, the expected long-term rate of return on plan assets, the anticipated rate of increase in health care costs, average remaining service period and life expectancy, and participant compensation have a significant impact on net periodic pension and OPEB costs.

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The discount rate for determining the pension benefit obligation for the qualified and nonqualified pension plans was 4.65% and 4.55%, respectively, as of December 31, 2015. The discount rate for determining the pension benefit obligation for the qualified and nonqualified pension plans was 4.20% as of December 31, 2014. The discount rate for determining the postretirement benefit obligation was 4.55% and 4.15% as of December 31, 2015 and 2014, respectively. PHI utilizes an analytical tool developed by its actuaries to select the discount rate. The analytical tool utilizes a high-quality bond portfolio with cash flows that match the benefit payments expected to be made under the plans.

The expected long-term rate of return on pension and postretirement benefit plan assets used to determine net periodic pension and OPEB cost was 6.50% and 6.75%, respectively, for 2015 and 7.00% and 7.25%, respectively, for 2014. PHI uses a building block approach to estimate the expected rate of return on plan assets. Under this approach, the percentage of plan assets in each asset class according to PHI’s target asset allocation, at the measurement date of net periodic cost, is applied to the expected asset return for the related asset class. PHI incorporates long-term assumptions for real returns, inflation expectations, volatility, and correlations among asset classes to determine expected returns for the related asset class. The pension and postretirement benefit plan assets consist of equity, fixed income, real estate and private equity investments.

The average remaining service periods for participating employees of the benefit plans was approximately 11 years for both 2015 and 2014. PHI utilizes plan census data to estimate these average remaining service periods. PHI uses mortality tables and mortality improvement scales issued by the Society of Actuaries to estimate participants’ life expectancy. In 2014, the Society of Actuaries issued updated mortality tables and mortality improvement scales which PHI applied in determining its benefit obligations as of December 31, 2014. In 2015, the Society of Actuaries modified the tables issued in 2014 to reflect updated mortality improvement experience. PHI applied these modified tables in determining its benefit obligations as of December 31, 2015.

The following table reflects the effect on the projected benefit obligation for the pension plans and the accumulated benefit obligation for the OPEB plan, as well as the net periodic cost, if there were changes in these critical actuarial assumptions while holding all other actuarial assumptions constant:

(in millions, except percentages)	Change in Assumptions	Impact on Benefit Obligation		Projected Increase in 2015 Net Periodic Cost
Pension Plans
Discount rate	(0.25)%	$	85	$	7
Expected return	(0.25)%		—		5
Postretirement Benefit Plan
Discount rate	(0.25)%		16		1
Expected return	(0.25)%		—		1
Health care cost trend rate	1.00%		16		2

The impact of changes in assumptions and the difference between actual and expected or estimated results on pension and postretirement benefit obligations is generally recognized over the average remaining service period of the employees who benefit under the plans rather than immediate recognition in the statement of income.

For additional discussion, see Note (9), “Pension and Other Postretirement Benefits,” to the consolidated financial statements of PHI.

Accounting for Regulated Activities

FASB guidance on the accounting for regulated operations (ASC 980), applies to Power Delivery and can result in the deferral of costs or revenue that would otherwise be recognized by non-regulated entities. PHI defers the recognition of costs and records regulatory assets when it is probable that those

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costs will be recovered in future customer rates. PHI defers the recognition of revenues and records regulatory liabilities when it is probable that it will refund payments received from customers in the future or that it will incur future costs related to the payments currently received from customers. PHI believes that the judgments involved in accounting for its regulated operations represent “Critical Accounting Estimates” because (i) PHI must interpret laws and regulatory commission orders to assess the probability of the recovery of costs in customer rates or the return of revenues to customers when determining whether those costs or revenues should be deferred, (ii) decisions made by regulatory commissions or legislative changes at a later date could vary from earlier interpretations made by PHI and the impact of such variations could be material, and (iii) the elimination of a regulatory asset because deferred costs are no longer probable of recovery in future customer rates could have a material negative impact on PHI’s assets and earnings.

PHI’s most significant judgment is whether to defer costs or revenues when there is not a current regulatory order specific to the item being considered for deferral. In those cases, PHI considers relevant historical precedents of the regulatory commissions, the results of recent rate orders, and any new information from its more current interactions with the regulatory commissions on that item. PHI regularly evaluates whether it should defer costs or revenues and reviews whether adjustments to its previous conclusions regarding its regulatory assets and liabilities are necessary based on the current regulatory and legislative environment as well as recent rate orders.

For additional discussion, see Note (7), “Regulatory Matters,” to the consolidated financial statements of PHI.

Unbilled Revenue

Unbilled revenue represents an estimate of revenue earned from services rendered by PHI’s utility operations that have not yet been billed. PHI’s utility operations calculate unbilled revenue using an output-based methodology. The calculation is based on the supply of electricity or natural gas distributed to customers but not yet billed, adjusted for estimated line losses (estimates of electricity and gas expected to be lost in the process of a utility’s transmission and distribution to customers).

PHI estimates involved in its unbilled revenue process represent “Critical Accounting Estimates” because PHI is required to make assumptions and judgments about factors to the unbilled revenue calculation. Specifically, the determination of estimated line losses is inherently uncertain. Estimated line losses is defined as the estimates of electricity and natural gas expected to be lost in the process of its transmission and distribution to customers. A change in estimated line losses can change the output available for sale which is a factor in the unbilled revenue calculation. Certain factors can influence the estimated line losses such as weather and a change in customer mix. These factors may vary between companies due to geography and density of service territory, and the impact of changes in these factors could be material. PHI seeks to reduce the risk of an inaccurate estimate of unbilled revenue through corroboration of the estimate with historical information and other output-based observable metrics.

Accounting for Income Taxes

PHI exercises significant judgment about the outcome of income tax matters in its application of the FASB guidance on accounting for income taxes (ASC 740) and believes it represents a “Critical Accounting Estimate” because: (i) it records a current tax liability for estimated current tax expense on its federal and state tax returns; (ii) it records deferred tax assets for temporary differences between the financial statement and tax return determination of pre-tax income and the carrying amount of assets and liabilities that are more likely than not going to result in tax deductions in future years; (iii) it determines whether a valuation allowance is needed against deferred tax assets if it is more likely than not that some portion of the future tax deductions will not be realized; (iv) it records deferred tax liabilities for temporary differences between the financial statement and tax return determination of pre-tax income and the carrying amount of assets and liabilities if it is more likely than not that they are expected to result in tax payments in future years; (v) the measurement of deferred tax assets and deferred tax liabilities

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requires it to estimate future effective tax rates and future taxable income on its federal and state tax returns; (vi) it must consider the effect of newly enacted tax law on its estimated effective tax rate and in measuring deferred tax balances; and (vii) it asserts that tax positions in its tax returns or expected to be taken in its tax returns are more likely than not to be sustained assuming that the tax positions will be examined by taxing authorities with full knowledge of all relevant information prior to recording the related tax benefit in the financial statements.

Assumptions, judgment and the use of estimates are required in determining if the more-likely-than-not measurement threshold (that is, the cumulative result for a greater than 50% chance of being realized) has been met when developing the provision for current and deferred income taxes and the associated current and deferred tax assets and liabilities. PHI’s assumptions, judgments and estimates take into account current tax laws and regulations, interpretation of current tax laws and regulations, the impact of newly enacted tax laws and regulations, developments in case law, settlements of tax positions, and the possible outcomes of current and future investigations conducted by tax authorities. PHI has established reserves for income taxes to address potential exposures involving tax positions that could be challenged by tax authorities. Although PHI believes that these assumptions, judgments and estimates are reasonable, changes in tax laws and regulations or its interpretation of tax laws and regulations as well as the resolutions of the current and any future investigations or legal proceedings could significantly impact the financial results from applying the accounting for income taxes in the consolidated financial statements. PHI reviews its application of the more-likely-than-not measurement threshold quarterly.

PHI also evaluates quarterly the probability of realizing deferred tax assets by reviewing a forecast of future taxable income and prudent and feasible tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. Failure to achieve forecasted taxable income or successfully implement tax planning strategies may affect the realization of deferred tax assets and the amount of any associated valuation allowance. The forecast of future taxable income is dependent on a number of factors that can change over time, including growth assumptions, business conditions, returns on rate base, operating and capital expenditures, cost of capital, tax laws and regulations, the legal structure of entities and other factors, which could materially impact the realizability of deferred tax assets and the associated financial results in the consolidated financial statements.

New Accounting Standards and Pronouncements

For information concerning new accounting standards and pronouncements that have recently been adopted, or will be required to be adopted in the future, by PHI and its subsidiaries , see Note (3), “Newly Adopted Accounting Standards,” and Note (4), “Recently Issued Accounting Standards, Not Yet Adopted,” to the consolidated financial statements of PHI.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Potomac Electric Power Company

Pepco meets the conditions set forth in General Instruction I(1)(a) and (b) to Form 10-K, and accordingly information otherwise required under this Item has been omitted in accordance with General Instruction I(2)(a) to Form 10-K.

General Overview

Pepco is engaged in the transmission and distribution of electricity in the District of Columbia and major portions of Prince George’s County and Montgomery County in suburban Maryland. Pepco also provides Default Electricity Supply. Pepco’s service territory covers approximately 640 square miles and, as of December 31, 2015, had a population of approximately 2.3 million. As of December 31, 2015, approximately 57% of delivered electricity sales were to Maryland customers and approximately 43% were to District of Columbia customers.

Pepco’s results historically have been seasonal, generally producing higher revenue and income in the warmest and coldest periods of the year. For retail customers of Pepco in Maryland and in the District of Columbia, revenue is not affected by unseasonably warmer or colder weather because a BSA for retail customers was implemented that provides for a fixed distribution charge per customer rather than a charge based on energy usage. The BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during the period. As a result, the only factors that will cause distribution revenue from customers in Maryland and the District of Columbia to fluctuate from period to period are changes in the number of customers and changes in the approved distribution charge per customer. Changes in customer usage (due to weather conditions, energy prices, energy savings programs or other reasons) from period to period have no impact on reported distribution revenue for customers to whom the BSA applies.

In accounting for the BSA in Maryland and the District of Columbia, a Revenue Decoupling Adjustment is recorded representing either (i) a positive adjustment equal to the amount by which revenue from Maryland and District of Columbia retail distribution sales falls short of the revenue that Pepco is entitled to earn based on the approved distribution charge per customer or (ii) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that Pepco is entitled to earn based on the approved distribution charge per customer.

Pepco is a wholly owned subsidiary of PHI. Because PHI is a public utility holding company subject to the Public Utility Holding Company Act of 2005 (PUHCA 2005), the relationship between each of PHI, PHI Service Company (a subsidiary service company of PHI, which provides a variety of support services, including legal, accounting, treasury, tax, purchasing and information technology services to PHI and its operating subsidiaries) and Pepco, as well as certain activities of Pepco, are subject to FERC’s regulatory oversight under PUHCA 2005.

Agreement and Plan of Merger with Exelon Corporation

PHI has entered into the Merger Agreement with Exelon and Merger Sub, providing for the Merger, with PHI surviving the Merger as an indirect, wholly owned subsidiary of Exelon. For additional information regarding the Merger, see PHI’s “Management’s Discussion and Analysis of Financial Condition and Results of Operations – General Overview – Agreement and Plan of Merger with Exelon Corporation.”

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Utility Capital Expenditures

Pepco allocates a substantial portion of its total capital expenditures to improving the reliability of its electrical transmission and distribution systems and replacing aging infrastructure throughout its service territories. These activities include one or more of the following:

• Identifying and upgrading under-performing feeder lines;

• Adding new facilities to support load;

• Installing distribution automation systems on both the overhead and underground network systems;

• Rejuvenating and replacing underground residential cables; and

• Replacing equipment at the end of its useful life.

Pepco’s capital expenditures for continuing reliability enhancement efforts are included in the table of projected capital expenditures within “– Capital Requirements – Capital Expenditures” below.

Smart Grid

Pepco is building a “smart grid” which is designed to meet the challenges of rising energy costs, improve service reliability of the energy distribution system, provide timely and accurate customer information and address government energy reduction goals. For a discussion of the smart grid, see PHI’s “Management’s Discussion and Analysis of Financial Condition and Results of Operations – General Overview – Power Delivery Initiatives and Activities – Smart Grid Initiatives.”

District of Columbia Power Line Undergrounding Initiative

For information about the District of Columbia Power Line Undergrounding Initiative, please refer to Note (6), “Regulatory Matters – District of Columbia Power Line Undergrounding Initiative,” to the financial statements of Pepco.

Mitigation of Regulatory Lag

An important factor in the ability of Pepco to earn its authorized ROE is the willingness of the DCPSC and the MPSC to adequately address the shortfall in revenues in Pepco’s rate structure due to the delay in time or “lag” between when costs are incurred and when they are reflected in rates. This delay is commonly known as “regulatory lag.” Pepco is currently experiencing significant regulatory lag because investments in rate base and operating expenses are increasing more rapidly than revenue growth.

In an effort to minimize the effects of regulatory lag, prior to the initial execution of the Merger Agreement in April 2014, Pepco had been filing electric distribution base rate cases every nine to twelve months in each of its jurisdictions, pursuing alternative ratemaking mechanisms, evaluating potential reductions in planned capital expenditures, and discussing with the regulatory community and other stakeholders the changing regulatory model economics that are causing regulatory lag.

As further described in PHI’s “Management’s Discussion and Analysis of Financial Condition and Results of Operations – General Overview – Agreement and Plan of Merger with Exelon Corporation,” PHI entered into the Merger Agreement with Exelon and Merger Sub in April 2014. Subject to certain exceptions, prior to the Merger or the termination of the Merger Agreement, Pepco may not, without the consent of Exelon, initiate, file or pursue any rate cases, other than concluding pending filings. To date, Pepco has not requested such consent from Exelon and accordingly, no new distribution base rate cases have been filed since entering into the Merger Agreement. Accordingly, Pepco’s efforts to mitigate regulatory lag have been delayed pending the closing of the Merger or the termination of the Merger Agreement.

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Transmission ROE Challenges

For information about the challenges to Pepco’s base ROE and the application of the formula rate process, each associated with the transmission services it provides, please refer to Note (6), “Regulatory Matters – Rate Proceedings – FERC Transmission ROE Challenges,” to the financial statements of Pepco.

Earnings Overview

Year Ended December 31, 2015 Compared to Year Ended December 31, 2014

Pepco’s net income for the year ended December 31, 2015 was $187 million compared to $171 million for the year ended December 31, 2014. The $16 million increase in earnings was primarily due to the following:

• An increase of $27 million related to gains recorded from the sale of certain Pepco properties.

• An increase of $15 million from other distribution revenue, primarily due to customer growth and rate mix.

• An increase of $11 million from electric distribution base rate increases in 2014 in the District of Columbia and in Maryland.

• An increase of $4 million in transmission revenue resulting from a change in FERC formula rates, partially offset by an increase in refund reserves related to the FERC ROE challenges.

• A decrease of $30 million due to higher operation and maintenance expense primarily related to the implementation of a new customer information system, higher environmental remediation costs, higher tree trimming and system maintenance costs, and previously expensed District of Columbia rate case costs established as a regulatory asset in 2014.

• A decrease of $6 million due to higher depreciation and amortization expense associated with increases in plant investment.

• A decrease of $5 million primarily due to higher long-term debt interest expense.

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Results of Operations

The following results of operations discussion compares the year ended December 31, 2015 to the year ended December 31, 2014. All amounts in the tables (except sales and customers) are in millions of dollars.

A condensed summary of Pepco’s statement of income for the year ended December 31, 2015 compared to the year ended December 31, 2014, is set forth in the table below:

	2015			2014			Change
Operating revenue	$	2,189		$	2,101		$	88
Purchased energy		763			771			(8	)
Other operation and maintenance		441			390			51
Depreciation and amortization		277			229			48
Other taxes		369			363			6
Gains on sales of land		(46	)		—			(46	)
Total operating expenses		1,804			1,753			51
Operating income		385			348			37
Other income (expenses)		(100	)		(85	)		(15	)
Income before income tax expense		285			263			22
Income tax expense		98			92			6
Net income	$	187		$	171		$	16

Operating Revenue

	2015		2014		Change
Regulated T&D Electric Revenue	$	1,363	$	1,269	$	94
Default Electricity Supply Revenue		789		798		(9	)
Other Electric Revenue		37		34		3
Total Operating Revenue	$	2,189	$	2,101	$	88

The table above shows the amount of Operating Revenue earned that is subject to price regulation (Regulated T&D Electric Revenue and Default Electricity Supply Revenue) and that which is not subject to price regulation (Other Electric Revenue).

Regulated T&D Electric Revenue includes revenue from the distribution of electricity, including the distribution of Default Electricity Supply, to Pepco’s customers within its service territories at regulated rates. Regulated T&D Electric Revenue also includes transmission service revenue that Pepco receives as a transmission owner from PJM at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.

The costs related to Default Electricity Supply are included in Purchased Energy. Default Electricity Supply Revenue also includes transmission enhancement credits that Pepco receives as a transmission owner from PJM in consideration for approved regional transmission expansion plan expenditures.

Other Electric Revenue includes work and services performed on behalf of customers, including other utilities, which is generally not subject to price regulation. Work and services includes mutual assistance to other utilities, highway relocation, rentals of pole attachments, late payment fees and collection fees.

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Regulated T&D Electric

	2015		2014		Change
Regulated T&D Electric Revenue
Residential	$	433	$	375	$	58
Commercial and industrial		733		705		28
Transmission and other		197		189		8
Total Regulated T&D Electric Revenue	$	1,363	$	1,269	$	94
	2015		2014		Change
Regulated T&D Electric Sales (GWh)
Residential		8,452		7,854		598
Commercial and industrial		17,391		17,737		(346	)
Transmission and other		145		160		(15	)
Total Regulated T&D Electric Sales		25,988		25,751		237
	2015		2014		Change
Regulated T&D Electric Customers (in thousands)
Residential		767		740		27
Commercial and industrial		75		75		—
Transmission and other		—		—		—
Total Regulated T&D Electric Customers		842		815		27

Regulated T&D Electric Revenue increased by $94 million primarily due to:

• An increase of $38 million due to EmPower Maryland rate increases effective February 2014 and 2015 (which is substantially offset by a corresponding increase in Depreciation and Amortization).

• An increase of $19 million due to electric distribution base rate increases in the District of Columbia effective April 2014 and in Maryland effective July 2014.

• An increase of $18 million due to customer growth in 2015, primarily in the residential class.

• An increase of $7 million in capacity revenue as a result of expanding Maryland demand side management programs (which is partially offset in Depreciation and Amortization).

• An increase of $6 million due to a bill stabilization adjustment.

• An increase of $6 million in transmission revenue due to higher rates effective June 2014 and June 2015 related to increases in transmission plant investment and operating expenses, partially offset by the establishment of a reserve related to the FERC ROE challenges.

Default Electricity Supply

	2015		2014		Change
Default Electricity Supply Revenue
Residential	$	555	$	527	$	28
Commercial and industrial		213		251		(38	)
Other		21		20		1
Total Default Electricity Supply Revenue	$	789	$	798	$	(9	)
	2015		2014		Change
Default Electricity Supply Sales (GWh)
Residential		6,505		6,027		478
Commercial and industrial		2,638		2,993		(355	)
Other		5		6		(1	)
Total Default Electricity Supply Sales		9,148		9,026		122

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	2015		2014		Change
Default Electricity Supply Customers (in thousands)
Residential		624		591		33
Commercial and industrial		45		45		—
Other		—		—		—
Total Default Electricity Supply Customers		669		636		33

Default Electricity Supply Revenue decreased by $9 million primarily due to a decrease of $21 million as a result of lower Default Electricity Supply rates, partially offset by:

• An increase of $6 million due to higher sales primarily as a result of customer migration from competitive suppliers.

• An increase of $6 million due to higher sales primarily as a result of warmer weather during the spring and summer months of 2015, as compared to 2014.

The following table shows the percentages of Pepco’s total distribution sales by jurisdiction that are derived from customers receiving Default Electricity Supply from Pepco. Amounts are for the year ended December 31:

	2015			2014
Sales to District of Columbia customers		29	%		27	%
Sales to Maryland customers		40	%		41	%

Operating Expenses

Purchased Energy

Purchased Energy consists of the cost of electricity purchased by Pepco to fulfill its Default Electricity Supply obligation and, as such, is recoverable from customers in accordance with the terms of public service commission orders. Purchased Energy decreased by $8 million to $763 million in 2015 from $771 million in 2014 primarily due to a decrease of $19 million due to lower average electricity costs under Default Electricity Supply contracts, partially offset by:

• An increase of $5 million primarily due to customer migration from competitive suppliers.

• An increase of $4 million due to higher electricity sales primarily as a result of warmer weather during the spring and summer months of 2015, as compared to 2014.

• An increase of $1 million in deferred electricity expense primarily due to higher revenue associated with Default Electricity Supply sales, which resulted in a higher rate of recovery of Default Electricity Supply costs.

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PEPCO

Other Operation and Maintenance

Other Operation and Maintenance expense increased by $51 million to $441 million in 2015 from $390 million in 2014 primarily due to:

• An increase of $19 million due to implementation and support costs related to a new customer information system.

• An increase of $9 million in environmental remediation costs.

• An increase of $6 million primarily associated with higher tree trimming and system maintenance costs.

• An increase of $4 million due to lower capitalized labor in 2015, as compared to 2014.

• An increase of $3 million due to the 2014 deferral of distribution rate case costs previously charged to Other Operation and Maintenance expense. The deferral was recorded in accordance with a DCPSC rate order issued in March 2014 authorizing the recovery of these costs.

• An increase of $3 million in customer service costs.

• An increase of $3 million in bad debt expense.

• An increase of $2 million in internal and external merger-related integration costs.

The aggregate amount of these increases was partially offset by a $4 million decrease in emergency restoration costs.

The increased costs referred to above for implementation and support of a new customer information system, system maintenance and customer service each involve internal labor costs which reflect a higher level of pension benefit cost in 2015, as compared to 2014.

Depreciation and Amortization

Depreciation and Amortization expense increased by $48 million to $277 million in 2015 from $229 million in 2014 primarily due to:

• An increase of $38 million in amortization of regulatory assets primarily associated with EmPower Maryland surcharge rate increases effective February 2014 and 2015 (which is offset in Regulated T&D Electric Revenue).

• An increase of $10 million due to utility plant additions.

Other Taxes

Other Taxes increased by $6 million to $369 million in 2015 from $363 million in 2014. The increase was primarily due to an increase in Maryland property taxes related to an increase in assets.

Gains on Sales of Land

Gains on Sales of Land increased by $46 million in 2015 from zero in 2014. The increase was primarily due to 2015 gains of $46 million ($27 million after-tax) recorded at Pepco associated with the sale of unimproved lands, held as non-utility properties.

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Other Income (Expenses)

Other Expenses (which are net of Other Income) increased by $15 million to a net expense of $100 million in 2015 from a net expense of $85 million in 2014. The increase was primarily due to:

• An increase of $8 million in long-term debt interest expense.

• A decrease of $9 million in income related to gains recorded in 2014 associated with condemnation awards for certain transmission property.

• An increase of $2 million in income related to the AFUDC that is applied to construction projects.

Income Tax Expense

Pepco’s income tax expense increased by $6 million to $98 million in 2015 from $92 million in 2014. Pepco’s effective income tax rates for the years ended December 31, 2015 and 2014 were 34.4% and 35.0%, respectively. The decrease in the effective tax rate primarily resulted from an increase in asset removal costs.

Capital Requirements

Sources of Capital

Pepco has a range of capital sources available, in addition to internally generated funds, to meet its long-term and short-term funding needs. The sources of long-term funding include the issuance of mortgage bonds and other debt securities and bank financings, as well as the ability to issue preferred stock. Proceeds from long-term financings are used primarily to fund long-term capital requirements, such as capital expenditures, and to repay or refinance existing indebtedness. Pepco traditionally has used a number of sources to fulfill short-term funding needs, including commercial paper, short-term notes, bank lines of credit and borrowings under the PHI money pool. Proceeds from short-term borrowings are used primarily to meet working capital needs, but may also be used to temporarily fund long-term capital requirements. Pepco’s ability to generate funds from its operations and to access the capital and credit markets is subject to risks and uncertainties. Volatile and deteriorating financial market conditions, diminished liquidity and tightening credit may affect access to certain of Pepco’s potential funding sources.

Debt Securities

Pepco has a Mortgage and Deed of Trust (the Mortgage) under which it issues First Mortgage Bonds. First Mortgage Bonds issued under the Mortgage are secured by a lien on substantially all of Pepco’s property, plant and equipment, except for such property excluded from the lien of the Mortgage. The principal amount of First Mortgage Bonds that Pepco may issue under the Mortgage is limited by the principal amount of retired First Mortgage Bonds and 60% of the lesser of the cost or fair value of new property additions that have not been used as the basis for the issuance of additional First Mortgage Bonds. Pepco also has an indenture under which it issues senior notes secured by First Mortgage Bonds and an indenture under which it can issue unsecured debt securities, including medium-term notes. To fund the construction of pollution control facilities, Pepco also has from time to time raised capital through tax-exempt bonds issued by a municipality or public agency, the proceeds of which are loaned to Pepco by the municipality or agency.

Information concerning the principal amount and terms of Pepco’s outstanding debt securities, as of December 31, 2015, is set forth in Note (9), “Debt,” to the financial statements of Pepco.

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Bank Financing

As further discussed in Note (9), “Debt,” to the financial statements of Pepco, Pepco is a borrower under a $1.5 billion unsecured syndicated credit facility, along with PHI, DPL and ACE, which expires in August 2018. This credit facility provides for Pepco’s liquidity needs, including obtaining letters of credit, borrowing for general corporate purposes and supporting its commercial paper program. Pepco’s credit limit under the facility is the lesser of $250 million and the maximum amount of short-term debt Pepco is permitted to have outstanding by its regulatory authorities. The short-term borrowing limit established by FERC for Pepco is $500 million.

Commercial Paper Program

Pepco maintains an ongoing commercial paper program to address its short-term liquidity needs. As of December 31, 2015, the maximum capacity available under the program was $500 million, subject to available borrowing capacity under the credit facility.

Pepco had $64 million of commercial paper outstanding at December 31, 2015. The weighted average interest rate for commercial paper issued by Pepco during 2015 was 0.44% and the weighted average maturity of all commercial paper issued by Pepco during 2015 was four days.

Money Pool

Pepco participates in the money pool operated by PHI under authorization received from FERC. The money pool is an unsecured cash management mechanism used by PHI and eligible subsidiaries to manage their short-term investment and borrowing requirements. PHI may invest in, but not borrow from, the money pool. Eligible subsidiaries with surplus cash may deposit those funds in the money pool. Deposits in the money pool are guaranteed by PHI. Eligible subsidiaries with cash requirements may borrow from the money pool. Depositors in the money pool receive, and borrowers from the money pool pay, an interest rate based primarily on PHI’s short-term borrowing rate. PHI deposits funds in the money pool to the extent that the pool has insufficient funds to meet the borrowing needs of its participants, which may require PHI to borrow funds for deposit from external sources.

Preferred Stock

Under its Articles of Incorporation, Pepco is authorized to issue and have outstanding up to 6 million shares of preferred stock in one or more series, with each series having such rights, preferences and limitations, including dividend and voting rights and redemption provisions, as the Board of Directors may establish. As of December 31, 2015 and 2014, there were no shares of Pepco preferred stock outstanding.

Regulatory Restrictions on Financing Activities

Pepco’s long-term financing activities (including the issuance of securities and the incurrence of debt) are subject to authorization by the DCPSC and MPSC. Through its periodic filings with the respective utility commissions, Pepco generally maintains standing authority sufficient to cover its projected financing needs over a multi-year period. Under the FPA, FERC has jurisdiction over the issuance of long-term and short-term securities of public utilities, but only if the issuance is not regulated by the state public utility commission in which the public utility is organized and operating. Pepco has obtained FERC authorization for the issuance of short-term debt under these provisions.

Capital Expenditures

Pepco’s capital expenditures for the year ended December 31, 2015 were $544 million. These expenditures were primarily related to capital costs associated with distribution and transmission services. The expenditures also include an allocation by PHI of hardware and software expenditures that primarily benefit Power Delivery and are allocated to Pepco when the assets are placed in service.

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Pepco’s projected capital expenditures for the five-year period from 2016 through 2020 are summarized below. Pepco expects to fund these expenditures through internally generated cash, external financing and capital contributions from PHI.

	For the Year Ended December 31,
	2016		2017		2018		2019		2020		Total
	(millions of dollars)
Pepco
Distribution	$	516	$	589	$	608	$	522	$	526	$	2,761
Transmission		155		165		207		235		125		887
Other		49		31		22		24		22		148
Total Pepco	$	720	$	785	$	837	$	781	$	673	$	3,796

Pepco has several construction projects within its service territory where performance has been subcontracted to Pepco Energy Services. Pepco guarantees the obligations of Pepco Energy Services under surety bonds obtained by Pepco Energy Services for these projects. These guarantees totaled $40 million at December 31, 2015.

District of Columbia Power Line Undergrounding Initiative

In May 2014, the Council of the District of Columbia enacted the Improvement Financing Act, which provides enabling legislation for the DC PLUG initiative. This $1 billion initiative seeks to selectively place underground some of the District of Columbia’s most outage-prone power lines, which lines and surrounding conduit would be owned and maintained by Pepco. A more detailed discussion of the Improvement Financing Act is provided in Note (6), “Regulatory Matters — District of Columbia Power Line Undergrounding Initiative,” to the financial statements of Pepco.

Transmission and Distribution

The projected capital expenditures listed in the table above for distribution and transmission are primarily for facility replacements and upgrades to accommodate customer growth and service reliability, including capital expenditures for continuing reliability enhancement efforts. The projected capital expenditures related to the DC Plug initiative are included as part of distribution expenditures in the table above.

DOE Capital Reimbursement Awards

During 2009, the DOE announced a $168 million award to PHI under the American Recovery and Reinvestment Act of 2009 for the implementation of an AMI system, direct load control, distribution automation, and communications infrastructure. Pepco was awarded $149 million, with $105 million to be used in the Maryland service territory and $44 million to be used in the District of Columbia service territory.

During 2010, Pepco and the DOE signed agreements formalizing Pepco’s $149 million share of the $168 million award. Of the $149 million, $118 million was offset against smart grid-related capital expenditures of Pepco. The remaining $31 million was used to offset incremental expenditures associated with direct load control and other programs, which were deferred as regulatory assets. As of December 31, 2015, Pepco has received all of its DOE award payments.

The IRS has announced that, to the extent these grants are expended on capital items, they will not be considered taxable income.

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Pension and Other Postretirement Benefit Plans

Pepco participates in pension and OPEB plans sponsored by PHI for its employees. Pepco made no contributions to the PHI Retirement Plan during 2015 and 2014. In 2015 and 2014, Pepco contributed $2 million and $1 million, respectively, to the other postretirement benefit plan.

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DPL

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Delmarva Power & Light Company

DPL meets the conditions set forth in General Instruction I(1)(a) and (b) to Form 10-K, and accordingly information otherwise required under this Item has been omitted in accordance with General Instruction I(2)(a) to Form 10-K.

General Overview

DPL is engaged in the transmission and distribution of electricity in portions of Delaware and Maryland. DPL also provides Default Electricity Supply. DPL’s electricity distribution service territory covers approximately 5,000 square miles and, as of December 31, 2015, had a population of approximately 1.4 million. As of December 31, 2015, approximately 65% of delivered electricity sales were to Delaware customers and approximately 35% were to Maryland customers. In northern Delaware, DPL also supplies and distributes natural gas to retail customers and provides transportation-only services to retail customers who purchase natural gas from other suppliers. DPL’s natural gas distribution service territory covers approximately 275 square miles and, as of December 31, 2015, had a population of approximately 0.6 million.

DPL’s results historically have been seasonal, generally producing higher revenue and income in the warmest and coldest periods of the year. For retail customers of DPL in Maryland, revenues are not affected by unseasonably warmer or colder weather because a BSA for retail customers was implemented that provides for a fixed distribution charge per customer. The BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during the period. As a result, the only factors that will cause distribution revenue from customers in Maryland to fluctuate from period to period are changes in the number of customers and changes in the approved distribution charge per customer. A modified fixed variable rate design, which would provide for a charge not tied to a customer’s volumetric consumption of electricity or natural gas, has been proposed for DPL electricity and natural gas customers in Delaware. Changes in customer usage (due to weather conditions, energy prices, energy efficiency programs or other reasons) from period to period have no impact on reported distribution revenue for customers to whom the BSA applies.

In accounting for the BSA in Maryland, a Revenue Decoupling Adjustment is recorded representing either (i) a positive adjustment equal to the amount by which revenue from Maryland retail distribution sales falls short of the revenue that DPL is entitled to earn based on the approved distribution charge per customer or (ii) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that DPL is entitled to earn based on the approved distribution charge per customer.

DPL is a wholly owned subsidiary of Conectiv, which is wholly owned by PHI. Because each of PHI and Conectiv is a public utility holding company subject to PUHCA 2005, the relationship between each of PHI, Conectiv, PHI Service Company and DPL, as well as certain activities of DPL, are subject to FERC’s regulatory oversight under PUHCA 2005.

Agreement and Plan of Merger with Exelon Corporation

PHI has entered into the Merger Agreement with Exelon and Merger Sub, providing for the Merger, with PHI surviving the Merger as an indirect, wholly owned subsidiary of Exelon. For additional information regarding the Merger, see PHI’s “Management’s Discussion and Analysis of Financial Condition and Results of Operations – General Overview – Agreement and Plan of Merger with Exelon Corporation.”

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DPL

Utility Capital Expenditures

DPL allocates a substantial portion of its total capital expenditures to improving the reliability of its electrical transmission and distribution systems and replacing aging infrastructure throughout its service territories. These activities include one or more of the following:

• Identifying and upgrading under-performing feeders;

• Adding new facilities to support load;

• Installing distribution automation systems on both the overhead and underground network systems;

• Rejuvenating and replacing underground residential cables; and

• Replacing equipment at the end of its useful life.

DPL’s capital expenditures for continuing reliability enhancement efforts are included in the table of projected capital expenditures within “– Capital Requirements – Capital Expenditures” below.

Smart Grid

DPL is building a smart grid which is designed to meet the challenges of rising energy costs, improve service reliability of the energy distribution system, provide timely and accurate customer information and address government energy reduction goals. For a discussion of the smart grid, see PHI’s “Management’s Discussion and Analysis of Financial Condition and Results of Operations – General Overview – Power Delivery Initiatives and Activities – Smart Grid Initiatives.”

Mitigation of Regulatory Lag

An important factor in the ability of DPL to earn its authorized ROE is the willingness of the DPSC and the MPSC to adequately address the shortfall in revenues in DPL’s rate structure due to the delay in time or “lag” between when costs are incurred and when they are reflected in rates. This delay is commonly known as “regulatory lag.” DPL is currently experiencing significant regulatory lag because investments in rate base and operating expenses are increasing more rapidly than revenue growth.

In an effort to minimize the effects of regulatory lag, prior to the initial execution of the Merger Agreement in April 2014, DPL had been filing electric distribution base rate cases every nine to twelve months in each of its jurisdictions, pursuing alternative ratemaking mechanisms, evaluating potential reductions in planned capital expenditures, and discussing with the regulatory community and other stakeholders the changing regulatory model economics that are causing regulatory lag.

As further described in PHI’s “Management’s Discussion and Analysis of Financial Condition and Results of Operations – General Overview – Agreement and Plan of Merger with Exelon Corporation,” PHI entered into the Merger Agreement with Exelon and Merger Sub in April 2014. Subject to certain exceptions, prior to the Merger or the termination of the Merger Agreement, DPL may not, without the consent of Exelon, initiate, file or pursue any rate cases, other than concluding pending filings. To date, DPL has not requested such consent from Exelon and accordingly, no new distribution base rate cases have been filed since entering into the Merger Agreement. Accordingly, DPL’s efforts to mitigate regulatory lag have been delayed pending the closing of the Merger or the termination of the Merger Agreement.

Transmission ROE Challenges

For information about the challenges to DPL’s base ROE and the application of the formula rate process, each associated with the transmission services it provides, please refer to Note (7), “Regulatory Matters – Rate Proceedings – FERC Transmission ROE Challenges,” to the financial statements of DPL.

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DPL

Earnings Overview

Year Ended December 31, 2015 Compared to Year Ended December 31, 2014

DPL’s net income for the year ended December 31, 2015 was $76 million compared to $104 million for the year ended December 31, 2014. The $28 million decrease in earnings was primarily due to the following:

• A decrease of $22 million due to higher operation and maintenance expense primarily related to the implementation of a new customer information system, higher bad debt expense, higher tree trimming and system maintenance costs, higher customer service costs and higher environmental remediation costs.

• A decrease of $6 million due to higher depreciation and amortization expense primarily resulting from increases in plant investment.

• A decrease of $3 million from income tax adjustments, primarily related to the Global Tax Settlement.

• A decrease of $2 million from higher property taxes.

• A decrease of $1 million due to higher long-term debt interest expense.

• An increase of $4 million in transmission revenue resulting from a change in FERC formula rates, partially offset by an increase in refund reserves related to the FERC ROE challenges.

• An increase of $4 million from other distribution revenue, primarily due to customer growth and rate mix.

Results of Operations

The following results of operations discussion compares the year ended December 31, 2015 to the year ended December 31, 2014. All amounts in the tables (except sales and customers) are in millions of dollars.

A condensed summary of DPL’s statement of income for the year ended December 31, 2015 compared to the year ended December 31, 2014, is set forth in the table below:

	2015			2014			Change
Operating revenue	$	1,318		$	1,293		$	25
Purchased energy		568			546			22
Gas purchased		79			104			(25	)
Other operation and maintenance		306			269			37
Depreciation and amortization		153			125			28
Other taxes		47			42			5
Total operating expenses		1,153			1,086			67
Operating income		165			207			(42	)
Other income (expenses)		(40	)		(38	)		(2	)
Income before income tax expense		125			169			(44	)
Income tax expense		49			65			(16	)
Net income	$	76		$	104		$	(28	)

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DPL

Electric Operating Revenue

	2015		2014		Change
Regulated T&D Electric Revenue	$	591	$	559	$	32
Default Electricity Supply Revenue		551		527		24
Other Electric Revenue		11		13		(2	)
Total Electric Operating Revenue	$	1,153	$	1,099	$	54

The table above shows the amount of Electric Operating Revenue earned that is subject to price regulation (Regulated T&D Electric Revenue and Default Electricity Supply Revenue) and that which is not subject to price regulation (Other Electric Revenue).

Regulated T&D Electric Revenue includes revenue from the distribution of electricity, including the distribution of Default Electricity Supply, to DPL’s customers within its service territories at regulated rates. Regulated T&D Electric Revenue also includes transmission service revenue that DPL receives as a transmission owner from PJM at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.

The costs related to Default Electricity Supply are included in Purchased Energy. Default Electricity Supply Revenue also includes transmission enhancement credits that DPL receives as a transmission owner from PJM in consideration for approved regional transmission expansion plan expenditures.

Other Electric Revenue includes work and services performed on behalf of customers, including other utilities, which is generally not subject to price regulation. Work and services includes mutual assistance to other utilities, highway relocation, rentals of pole attachments, late payment fees and collection fees.

Regulated T&D Electric

	2015		2014		Change
Regulated T&D Electric Revenue
Residential	$	263	$	251	$	12
Commercial and industrial		174		156		18
Transmission and other		154		152		2
Total Regulated T&D Electric Revenue	$	591	$	559	$	32
	2015		2014		Change
Regulated T&D Electric Sales (GWh)
Residential		5,337		5,188		149
Commercial and industrial		7,092		7,178		(86	)
Transmission and other		45		47		(2	)
Total Regulated T&D Electric Sales		12,474		12,413		61
	2015		2014		Change
Regulated T&D Electric Customers (in thousands)
Residential		453		449		4
Commercial and industrial		61		60		1
Transmission and other		1		1		—
Total Regulated T&D Electric Customers		515		510		5

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DPL

Regulated T&D Electric Revenue increased by $32 million primarily due to:

• An increase of $16 million primarily due to EmPower Maryland rate increases effective February 2014 and 2015 (which is substantially offset by a corresponding increase in Depreciation and Amortization).

• An increase of $8 million primarily due to rate increases effective June 2014 and June 2015 associated with the Renewable Portfolio Surcharge in Delaware (which is substantially offset in Fuel and Purchased Energy and Depreciation and Amortization).

• An increase of $8 million in transmission revenue resulting from higher rates effective June 2014 and June 2015 related to increases in transmission plant investment and operating expenses, partially offset by the establishment of a reserve related to the FERC ROE challenges.

• An increase of $3 million due to higher sales primarily as a result of warmer weather during the spring and summer months of 2015, as compared to 2014.

• An increase of $3 million due to a Maryland bill stabilization adjustment.

The aggregate amount of these increases was partially offset by a decrease of $6 million in revenue related to the resale by DPL of renewable energy to PJM (which is substantially offset in Purchased Energy and Depreciation and Amortization).

Default Electricity Supply

	2015		2014		Change
Default Electricity Supply Revenue
Residential	$	418	$	402	$	16
Commercial and industrial		120		112		8
Other		13		13		—
Total Default Electricity Supply Revenue	$	551	$	527	$	24
	2015		2014		Change
Default Electricity Supply Sales (GWh)
Residential		4,610		4,420		190
Commercial and industrial		1,476		1,371		105
Other		25		26		(1	)
Total Default Electricity Supply Sales		6,111		5,817		294
	2015		2014		Change
Default Electricity Supply Customers (in thousands)
Residential		397		392		5
Commercial and industrial		40		40		—
Other		—		—		—
Total Default Electricity Supply Customers		437		432		5

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DPL

Default Supply Revenue increased by $24 million primarily due to:

• An increase of $22 million due to higher sales primarily as a result of customer migration from competitive suppliers.

• An increase of $4 million due to higher sales primarily as a result of warmer weather during the spring and summer months of 2015, as compared to 2014.

The aggregate amount of these increases was partially offset by a decrease of $3 million as a result of lower Default Electricity Supply rates.

The following table shows the percentages of DPL’s total distribution sales by jurisdiction that are derived from customers receiving Default Electricity Supply from DPL. Amounts are for the years ended December 31:

	2015			2014
Sales to Delaware customers		47	%		44	%
Sales to Maryland customers		53	%		51	%

Natural Gas Operating Revenue

	2015		2014		Change
Regulated Gas Revenue	$	154	$	176	$	(22	)
Other Gas Revenue		11		18		(7	)
Total Natural Gas Operating Revenue	$	165	$	194	$	(29	)

The table above shows the amounts of Natural Gas Operating Revenue from sources that are subject to price regulation (Regulated Gas Revenue) and those that generally are not subject to price regulation (Other Gas Revenue). Regulated Gas Revenue includes the revenue DPL receives from on-system natural gas delivered sales and the transportation of natural gas for customers within its service territory at regulated rates. Other Gas Revenue consists of off-system natural gas sales and the short-term release of interstate pipeline transportation and storage capacity not needed to serve customers. Off-system sales are made possible when low demand for natural gas by regulated customers creates excess pipeline capacity.

Regulated Gas

	2015		2014		Change
Regulated Gas Revenue
Residential	$	94	$	106	$	(12	)
Commercial and industrial		49		59		(10	)
Transportation and other		11		11		—
Total Regulated Gas Revenue	$	154	$	176	$	(22	)

	2015		2014		Change
Regulated Gas Sales (million cubic feet)
Residential		8,020		8,550		(530	)
Commercial and industrial		5,796		6,063		(267	)
Transportation and other		6,193		6,418		(225	)
Total Regulated Gas Sales		20,009		21,031		(1,022	)

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DPL

	2015		2014		Change
Regulated Gas Customers (in thousands)
Residential		120		118		2
Commercial and industrial		10		10		—
Transportation and other		—		—		—
Total Regulated Gas Customers		130		128		2

Regulated Gas Revenue decreased by $22 million primarily due to:

• A decrease of $11 million due to lower sales as a result of warmer weather primarily during the fourth quarter of 2015, as compared to 2014.

• A decrease of $11 million due to GCR decreases effective November 2014 and November 2015.

Other Gas Revenue

Other Gas Revenue decreased by $7 million primarily due to lower volumes and lower average prices for off-system sales to electric generators and gas marketers.

Operating Expenses

Purchased Energy consists of the cost of electricity purchased by DPL to fulfill its Default Electricity Supply obligation and, as such, is recoverable from customers in accordance with the terms of public service commission orders. Purchased Energy increased by $22 million to $568 million in 2015 from $546 million in 2014 primarily due to:

• An increase of $19 million primarily due to customer migration from competitive suppliers.

• An increase of $8 million in deferred electric expense primarily due to higher Default Electricity Supply rates, which resulted in a higher rate of recovery of Default Electricity Supply costs.

• An increase of $4 million due to higher electricity sales primarily as a result of warmer weather during the spring and summer months of 2015, as compared to 2014.

The aggregate amount of these increases was partially offset by a decrease of $8 million in due to higher average electricity costs under Default Electricity Supply contracts.

Gas Purchased

Gas Purchased expense consists of the cost of gas purchased by DPL to fulfill its obligation to regulated gas customers and, as such, is recoverable from customers in accordance with the terms of public service commission orders. It also includes the cost of gas purchased for off-system sales. Total Gas Purchased expense decreased by $25 million to $79 million in 2015 from $104 million in 2014 primarily due to the following:

• A decrease of $26 million in the cost of gas purchases for on-system sales as a result of lower prices.

• A decrease of $6 million in the cost of gas purchases for off-system sales as a result of lower volumes and lower average prices.

The aggregate amount of these decreases was partially offset by an increase of $8 million from the settlement of financial hedges entered into as part of DPL’s hedge program for the purchase of regulated natural gas.

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Other Operation and Maintenance

Other Operation and Maintenance expense increased by $37 million to $306 million in 2015 from $269 million in 2014 primarily due to:

• An increase of $10 million due to implementation and support costs related to a new customer information system.

• An increase of $6 million in bad debt expense, of which $1 million is deferred and recoverable.

• An increase of $6 million associated with higher tree trimming and system maintenance costs.

• An increase of $4 million in customer service costs.

• An increase of $3 million in environmental remediation costs.

• An increase of $2 primarily due to cancelled construction projects.

• An increase of $1 million in internal and external merger-related integration costs.

• An increase of $1 million primarily due to an increase in incremental storm costs related to a severe storm with damaging winds and heavy rains in DPL’s Maryland jurisdiction on June 23, 2015. The storm resulted in widespread customer outages and caused damage to the electric transmission and distribution systems. Total incremental storm restoration costs incurred by DPL for the storm through December 31, 2015 were $4 million, with $2 million incurred for repair work and $2 million incurred as capital expenditures. Costs incurred for repair work of $1 million were deferred as regulatory assets to reflect the probable recovery of these costs in Maryland, and $1 million was charged to Other Operation and Maintenance expense. DPL intends to pursue recovery of these incremental storm restoration costs in its next electric distribution base rate cases.

The increased costs referred to above for implementation and support of a new customer information system, system maintenance, customer service and storm restoration each involve internal labor costs which reflect a higher level of pension benefit cost in 2015, as compared to 2014.

Depreciation and Amortization

Depreciation and Amortization expense increased by $28 million to $153 million in 2015 from $125 million in 2014 primarily due to:

• An increase of $14 million in amortization of regulatory assets primarily associated with EmPower Maryland surcharge rate increases effective February 2014 and 2015 (which is offset in Regulated T&D Electric Revenue).

• An increase of $9 million due to utility plant additions.

• An increase of $3 million in the Delaware Renewable Energy Portfolio Standards deferral (which is substantially offset by a corresponding increase in Regulated T&D Electric Revenue).

• An increase of $1 million in amortization of regulatory assets primarily related to recoverable major storm costs and rate case costs.

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Other Taxes

Other Taxes increased by $5 million to $47 million in 2015 from $42 million in 2014. The increase was primarily due to:

• An increase of $4 million in property taxes related to an increase in assets.

• An increase of $1 million in utility taxes that are collected and passed through by DPL (substantially offset by a corresponding increase in Regulated T&D Electric Revenue).

Other Income (Expenses)

Other Expenses (which are net of Other Income) increased by $2 million to a net expense of $40 million in 2015 from a net expense of $38 million in 2014. The increase is primarily due to a $1 million increase in long-term debt interest expense and a $1 million decrease in income related to the AFUDC that is applied to construction projects.

Income Tax Expense

DPL’s income tax expense decreased by $16 million to $49 million in 2015 from $65 million in 2014. DPL’s effective income tax rates for the years ended December 31, 2015 and 2014 were 39.2% and 38.5%, respectively. The increase in the effective tax rate primarily resulted from the net tax charges associated with the Global Tax Settlement as described in Note (11), “Income Taxes,” to the financial statements of DPL.

Capital Requirements

Sources of Capital

DPL has a range of capital sources available, in addition to internally generated funds, to meet its long-term and short-term funding needs. The sources of long-term funding include the issuance of mortgage bonds and other debt securities and bank financings, as well as the ability to issue preferred stock. Proceeds from long-term financings are used primarily to fund long-term capital requirements, such as capital expenditures, and to repay or refinance existing indebtedness. DPL traditionally has used a number of sources to fulfill short-term funding needs, including commercial paper, medium- and short-term notes, bank lines of credit, and borrowings under the PHI money pool. Proceeds from short-term borrowings are used primarily to meet working capital needs, but may also be used to temporarily fund long-term capital requirements. DPL’s ability to generate funds from its operations and to access the capital and credit markets is subject to risks and uncertainties. Volatile and deteriorating financial market conditions, diminished liquidity and tightening credit may affect access to certain of DPL’s potential funding sources.

Debt Securities

DPL has a Mortgage and Deed of Trust (the Mortgage) under which it issues First Mortgage Bonds. First Mortgage Bonds issued under the Mortgage are secured by a lien on substantially all of DPL’s property, plant and equipment, except for such property excluded from the lien of the Mortgage. The principal amount of First Mortgage Bonds that DPL may issue under the Mortgage is limited by the principal amount of retired First Mortgage Bonds and 60% of the lesser of the cost or fair value of new property additions that have not been used as the basis for the issuance of additional First Mortgage Bonds. DPL also has an indenture under which it issues unsecured senior notes, medium-term notes and Variable Rate Demand Bonds (VRDBs). To fund the construction of pollution control facilities, DPL also has from time to time raised capital through tax-exempt bonds, including tax-exempt VRDBs, issued by a public agency, the proceeds of which are loaned to DPL by the agency.

Information concerning the principal amount and terms of DPL’s outstanding First Mortgage Bonds, senior notes, medium-term notes and tax-exempt bonds issued for the benefit of DPL, as of December 31, 2015, is set forth in Note (10), “Debt,” to the financial statements of DPL.

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Bank Financing

As further discussed in Note (10), “Debt,” to the financial statements of DPL, DPL is a borrower under a $1.5 billion unsecured syndicated credit facility, along with PHI, Pepco and ACE, which expires in August 2018. This credit facility provides for DPL’s liquidity needs, including obtaining letters of credit, borrowing for general corporate purposes and supporting its commercial paper program. DPL’s credit limit under the facility is the lesser of $250 million and the maximum amount of short-term debt DPL is permitted to have outstanding by its regulatory authorities. The short-term borrowing limit established by FERC for DPL is $500 million.

Commercial Paper Program

DPL maintains an ongoing commercial paper program to address its short-term liquidity needs. As of December 31, 2015, the maximum capacity available under the program was $500 million, subject to available borrowing capacity under the credit facility.

DPL had $105 million of commercial paper outstanding at December 31, 2015. The weighted average interest rate for commercial paper issued by DPL during 2015 was 0.47% and the weighted average maturity of all commercial paper issued by DPL during 2015 was four days.

Money Pool

DPL participates in the money pool operated by PHI under authorization received from FERC. The money pool is an unsecured cash management mechanism used by PHI and eligible subsidiaries to manage their short-term investment and borrowing requirements. PHI may invest in, but not borrow from, the money pool. Eligible subsidiaries with surplus cash may deposit those funds in the money pool. Deposits in the money pool are guaranteed by PHI. Eligible subsidiaries with cash requirements may borrow from the money pool. Depositors in the money pool receive, and borrowers from the money pool pay, an interest rate based primarily on PHI’s short-term borrowing rate. PHI deposits funds in the money pool to the extent that the pool has insufficient funds to meet the borrowing needs of its participants, which may require PHI to borrow funds for deposit from external sources.

Regulatory Restrictions on Financing Activities

DPL’s long-term financing activities (including the issuance of securities and the incurrence of debt) is subject to authorization by the DPSC and the MPSC. Through its periodic filings with the respective utility commissions, DPL generally maintains standing authority sufficient to cover its projected financing needs over a multi-year period. Under the FPA, FERC has jurisdiction over the issuance of long-term and short-term securities of public utilities, but only if the issuance is not regulated by the state public utility commission in which the public utility is organized and operating. DPL has obtained FERC authorization for the issuance of short-term debt under these provisions.

Capital Expenditures

DPL’s capital expenditures for the year ended December 31, 2015 were $352 million. These expenditures were primarily related to capital costs associated with distribution and transmission services. The expenditures also include an allocation by PHI of hardware and software expenditures that primarily benefit Power Delivery and are allocated to DPL when the assets are placed in service.

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DPL’s projected capital expenditures for the five-year period from 2016 through 2020 are summarized below. DPL expects to fund these expenditures through internally generated cash, external financing and capital contributions from PHI.

	For the Year Ended December 31,
	2016		2017		2018		2019		2020		Total
	(millions of dollars)
DPL
Distribution	$	157	$	153	$	153	$	148	$	156	$	767
Transmission		136		123		146		66		53		524
Gas Delivery		32		35		36		38		40		181
Other		34		26		24		21		20		125
Total DPL	$	359	$	337	$	359	$	273	$	269	$	1,597

Transmission and Distribution

The projected capital expenditures listed in the table above for distribution, transmission and gas delivery are primarily for facility replacements and upgrades to accommodate customer growth and service reliability, including capital expenditures for reliability enhancement efforts.

Pension and Other Postretirement Benefit Plans

DPL participates in pension and OPEB plans sponsored by PHI for its employees. DPL made no contributions to the PHI Retirement Plan during 2015 and 2014. In 2015 and 2014, DPL made no contributions to the other postretirement benefit plan.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Atlantic City Electric Company

ACE meets the conditions set forth in General Instruction I(1)(a) and (b) to Form 10-K, and accordingly information otherwise required under this Item has been omitted in accordance with General Instruction I(2)(a) to Form 10-K.

General Overview

ACE is engaged in the transmission and distribution of electricity in portions of southern New Jersey. ACE also provides Default Electricity Supply. Default Electricity Supply is known as BGS in New Jersey. ACE’s service territory covers approximately 2,700 square miles and, as of December 31, 2015, had a population of approximately 1.1 million.

ACE is a wholly owned subsidiary of Conectiv, which is wholly owned by PHI. Because each of PHI and Conectiv is a public utility holding company subject to PUHCA 2005, the relationship between each of PHI, Conectiv, PHI Service Company and ACE, as well as certain activities of ACE, are subject to FERC’s regulatory oversight under PUHCA 2005.

Agreement and Plan of Merger with Exelon Corporation

PHI has entered into the Merger Agreement with Exelon and Merger Sub, providing for the Merger, with PHI surviving the Merger as an indirect, wholly owned subsidiary of Exelon. For additional information regarding the Merger, see PHI’s “Management’s Discussion and Analysis of Financial Condition and Results of Operations – General Overview – Agreement and Plan of Merger with Exelon Corporation.”

Utility Capital Expenditures

ACE allocates a substantial portion of its total capital expenditures to improving the reliability of its electrical transmission and distribution systems and replacing aging infrastructure throughout its service territory. These activities include one or more of the following:

• Identifying and upgrading under-performing feeders;

• Adding new facilities to support load;

• Installing distribution automation systems on both the overhead and underground network systems;

• Rejuvenating and replacing underground residential cables; and

• Replacing equipment at the end of its useful life.

ACE’s capital expenditures for continuing reliability enhancement efforts are included in the table of projected capital expenditures within “– Capital Requirements – Capital Expenditures” below.

Mitigation of Regulatory Lag

An important factor in the ability of ACE to earn its authorized ROE is the willingness of the NJBPU to adequately address the shortfall in revenues in ACE’s rate structure due to the delay in time or “lag” between when costs are incurred and when they are reflected in rates. This delay is commonly known as “regulatory lag.” ACE is currently experiencing significant regulatory lag because investments in rate base and operating expenses are increasing more rapidly than revenue growth.

In an effort to minimize the effects of regulatory lag, prior to the initial execution of the Merger Agreement in April 2014, ACE had been filing electric distribution base rate cases every nine to twelve months, pursuing alternative ratemaking mechanisms, evaluating potential reductions in planned capital expenditures, and discussing with the regulatory community and other stakeholders the changing regulatory model economics that are causing regulatory lag.

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As further described in PHI’s “Management’s Discussion and Analysis of Financial Condition and Results of Operations – General Overview – Agreement and Plan of Merger with Exelon Corporation,” PHI entered into the Merger Agreement with Exelon and Merger Sub in April 2014. Subject to certain exceptions, prior to the Merger or the termination of the Merger Agreement, ACE may not, without the consent of Exelon, initiate, file or pursue any rate cases, other than concluding pending filings. To date, ACE has not requested such consent from Exelon and accordingly, no new distribution base rate cases have been filed since entering into the Merger Agreement. Accordingly, ACE’s efforts to mitigate regulatory lag have been delayed pending the closing of the Merger or the termination of the Merger Agreement.

Transmission ROE Challenges

For information about the challenges to ACE’s base ROE and the application of the formula rate process, each associated with the transmission services it provides, please refer to Note (6), “Regulatory Matters – Rate Proceedings – FERC Transmission ROE Challenges,” to the consolidated financial statements of ACE.

Earnings Overview

Year Ended December 31, 2015 Compared to Year Ended December 31, 2014

ACE’s consolidated net income for the year ended December 31, 2015 was $38 million compared to $45 million for the year ended December 31, 2014. The $7 million decrease in earnings was primarily due to the following:

• A decrease of $14 million due to higher operation and maintenance expense primarily related to the implementation of a new customer information system, higher bad debt expense, higher storm restoration costs and higher customer service costs.

• A decrease of $5 million from income tax adjustments, primarily related to the Global Tax Settlement.

• A decrease of $3 million due to higher depreciation and amortization expense primarily resulting from increases in plant investment.

• A decrease of $1 million due to an increase in refund reserves related to the FERC ROE challenges, partially offset by a change in FERC formula rates.

• An increase of $10 million from an electric distribution base rate increase in 2014 in New Jersey.

• An increase of $6 million from other distribution revenue primarily due to the effect of warmer weather during the spring and summer months of 2015, as compared to 2014.

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Results of Operations

The following results of operations discussion compares the year ended December 31, 2015 to the year ended December 31, 2014. All amounts in the tables (except sales and customers) are in millions of dollars.

A condensed summary of ACE’s consolidated statement of income for the year ended December 31, 2015 compared to the year ended December 31, 2014, is set forth in the table below:

	2015			2014			Change
Operating revenue	$	1,298		$	1,213		$	85
Purchased energy		685			653			32
Other operation and maintenance		272			246			26
Depreciation and amortization		176			157			19
Other taxes		5			2			3
Deferred electric service costs		30			20			10
Total operating expenses		1,168			1,078			90
Operating income		130			135			(5	)
Other income (expenses)		(61	)		(62	)		1
Income before income tax expense		69			73			(4	)
Income tax expense		31			28			3
Consolidated Net Income	$	38		$	45		$	(7	)

Operating Revenue

	2015		2014		Change
Regulated T&D Electric Revenue	$	475	$	449	$	26
Default Electricity Supply Revenue		811		751		60
Other Electric Revenue		12		13		(1	)
Total Operating Revenue	$	1,298	$	1,213	$	85

The table above shows the amount of Operating Revenue earned that is subject to price regulation (Regulated T&D Electric Revenue and Default Electricity Supply Revenue) and that which is not subject to price regulation (Other Electric Revenue).

Regulated T&D Electric Revenue includes revenue from the distribution of electricity, including the distribution of Default Electricity Supply, to ACE’s customers within its service territory at regulated rates. Regulated T&D Electric Revenue also includes transmission service revenue that ACE receives as a transmission owner from PJM at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.

The costs related to Default Electricity Supply are included in Purchased Energy. Default Electricity Supply Revenue also includes revenue from Transition Bond Charges that ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds, and revenue in the form of transmission enhancement credits.

Other Electric Revenue includes work and services performed on behalf of customers, including other utilities, which is generally not subject to price regulation. Work and services includes mutual assistance to other utilities, highway relocation, rentals of pole attachments, late payment fees and collection fees.

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Regulated T&D Electric

	2015		2014		Change
Regulated T&D Electric Revenue
Residential	$	218	$	198	$	20
Commercial and industrial		158		152		6
Transmission and other		99		99		—
Total Regulated T&D Electric Revenue	$	475	$	449	$	26
	2015		2014		Change
Regulated T&D Electric Sales (GWh)
Residential		4,322		4,087		235
Commercial and industrial		4,882		4,916		(34	)
Transmission and other		45		48		(3	)
Total Regulated T&D Electric Sales		9,249		9,051		198
	2015		2014		Change
Regulated T&D Electric Customers (in thousands)
Residential		482		480		2
Commercial and industrial		64		65		(1	)
Transmission and other		1		1		—
Total Regulated T&D Electric Customers		547		546		1

Regulated T&D Electric Revenue increased by $26 million primarily due to:

• An increase of $17 million due to an electric distribution rate increase effective September 2014.

• An increase of $9 million due to higher sales primarily as a result of warmer weather during the spring and summer months of 2015, as compared to 2014.

The aggregate amount of these increases was partially offset by a decrease of $1 million in transmission revenue due to the establishment of a reserve related to the FERC ROE challenges, partially offset by higher rates effective June 1, 2014 and June 1, 2015 related to increases in transmission plant investment and operating expenses.

Default Electricity Supply

	2015		2014		Change
Default Electricity Supply Revenue
Residential	$	472	$	383	$	89
Commercial and industrial		229		190		39
Other		110		178		(68	)
Total Default Electricity Supply Revenue	$	811	$	751	$	60

Other Default Electricity Supply Revenue consists primarily of (i) revenue from the resale in the PJM RTO market of energy and capacity purchased under contracts with unaffiliated NUGs and (ii) revenue from transmission enhancement credits.

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	2015		2014		Change
Default Electricity Supply Sales (GWh)
Residential		3,746		3,404		342
Commercial and industrial		1,365		1,056		309
Other		16		12		4
Total Default Electricity Supply Sales		5,127		4,472		655
	2015		2014		Change
Default Electricity Supply Customers (in thousands)
Residential		425		414		11
Commercial and industrial		44		44		—
Other		—		—		—
Total Default Electricity Supply Customers		469		458		11

Default Electricity Supply Revenue increased by $60 million primarily due to:

• An increase of $59 million due to higher sales primarily as a result of customer migration from competitive suppliers.

• An increase of $53 million as a result of higher Default Electricity Supply rates.

• An increase of $16 million due to higher sales primarily as a result of warmer weather during the spring and summer months of 2015, as compared to 2014.

The aggregate amount of these increases was partially offset by a decrease of $70 million in wholesale energy and capacity resale revenues primarily due to lower market prices for the resale of electricity and capacity purchased from NUGs.

The variances described above with respect to Default Electricity Supply Revenue include the effects of a decrease of $2 million in ACE’s BGS unbilled revenue resulting primarily from lower average customer usage in the unbilled revenue period for the year ended December 31, 2015 as compared to the corresponding period in 2014. Such a decrease in ACE’s BGS unbilled revenue has the effect of directly decreasing the profitability of ACE’s Default Electricity Supply business ($1 million decrease in net income) as these unbilled revenues are not included in the deferral calculation until they are billed to customers under the BGS terms approved by the NJBPU.

For the year ended December 31, 2015 and 2014, the percentages of ACE’s total distribution sales that are derived from customers receiving Default Electricity Supply are 55% and 49%, respectively.

Operating Expenses

Purchased Energy

Purchased Energy consists of the cost of electricity purchased by ACE to fulfill its Default Electricity Supply obligation and, as such, is recoverable from customers in accordance with the terms of public service commission orders. Purchased Energy increased by $32 million to $685 million in 2015 from $653 million in 2014 primarily due to:

• An increase of $34 million primarily due to customer migration from competitive suppliers.

• An increase of $11 million due to higher electricity sales primarily as a result of warmer weather during the spring and summer months of 2015, as compared to 2014.

The aggregate amount of these increases was partially offset by a decrease of $14 million due to lower average electricity costs under BGS contracts.

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Other Operation and Maintenance

Other Operation and Maintenance expense increased by $26 million to $272 million in 2015 from $246 million in 2014 primarily due to:

• An increase of $11 million due to implementation and support costs related to a new customer information system.

• An increase of $6 million in bad debt expense that is deferred and recoverable.

• An increase of $6 million in storm restoration costs.

• An increase of $4 million in customer service costs.

• An increase of $3 million in tree trimming and system maintenance costs.

• An increase of $1 million in internal and external merger-related integration costs.

The aggregate amount of these increases was partially offset by:

• A decrease of $3 million due to adjustments of self-insurance reserves for general liability claims.

• A decrease of $3 million due to the 2014 write-off of unrecoverable regulatory assets previously established in connection with the sale of certain generation assets.

On June 23, 2015, ACE’s service territory was affected by a severe storm with damaging winds and heavy rains. This storm resulted in widespread customer outages and caused damage to the electric transmission and distribution systems. Total incremental storm restoration costs incurred by ACE for the storm through December 31, 2015 were $36 million, with $13 million incurred for repair work and $23 million incurred as capital expenditures. Costs incurred for repair work of $13 million were deferred as regulatory assets to reflect the probable recovery of these costs in New Jersey. ACE intends to pursue recovery of these incremental storm restoration costs in its next electric distribution base rate case.

The increased costs referred to above for implementation and support of a new customer information system, system maintenance, storm restoration and customer service each involve internal labor costs which reflect a higher level of pension benefit cost in 2015, as compared to 2014.

Depreciation and Amortization

Depreciation and Amortization expense increased by $19 million to $176 million in 2015 from $157 million in 2014 primarily due to:

• An increase of $15 million in amortization of stranded costs primarily as the result of higher revenue due to a rate increase effective October 2014 for the ACE Market Transition Tax (partially offset in Default Electricity Supply Revenue).

• An increase of $4 million due to utility plant additions.

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Other Taxes

Other Taxes increased by $3 million to $5 million in 2015 from $2 million in 2014. The increase was primarily due to an increase in the New Jersey Use Tax.

Deferred Electric Service Costs

Deferred Electric Service Costs represent (i) the over or under recovery of electricity costs incurred by ACE to fulfill its Default Electricity Supply obligation and (ii) the over or under recovery of costs incurred by ACE related to the New Jersey Societal Benefit Program. The cost of electricity purchased is reported under Purchased Energy expense and the corresponding revenue is reported under Default Electricity Supply Revenue. The costs of the New Jersey Societal Benefit Program are reported under Other Operation and Maintenance expense and the corresponding revenue is reported under Regulated T&D Electric Revenue.

Deferred Electric Service Costs increased by $10 million to an expense of $30 million in 2015 as compared to an expense of $20 million in 2014, primarily due to an increase in deferred electricity expense as a result of higher Default Electricity Supply revenue rates.

Other Income (Expenses)

Other Expenses (which are net of Other Income) decreased by $1 million to a net expense of $61 million in 2015 from a net expense of $62 million in 2014. The decrease was primarily due to an increase in income related to a higher income tax component of contributions in aid of construction resulting from a higher level of customer requested construction activity.

Income Tax Expense

ACE’s consolidated income tax expense increased by $3 million to $31 million in 2015 from $28 million in 2014. ACE’s consolidated effective income tax rates for the years ended December 31, 2015 and 2014 were 44.9% and 38.4%, respectively. The increase in the effective tax rate primarily resulted from the net tax charges associated with the Global Tax Settlement.

Capital Requirements

Sources of Capital

ACE has a range of capital sources available, in addition to internally generated funds, to meet its long-term and short-term funding needs. The sources of long-term funding include the issuance of mortgage bonds and other debt securities and bank financings, as well as preferred stock. Proceeds from long-term financings are used primarily to fund long-term capital requirements, such as capital expenditures, and to repay or refinance existing indebtedness. ACE traditionally has used a number of sources to fulfill medium- and short-term funding needs, including commercial paper, medium- and short-term notes, bank lines of credit, and under certain circumstances, borrowings under the PHI money pool. Proceeds from short-term borrowings are used primarily to meet working capital needs, but may also be used to temporarily fund long-term capital requirements. ACE’s ability to generate funds from its operations and to access the capital and credit markets is subject to risks and uncertainties. Volatile and deteriorating financial market conditions, diminished liquidity and tightening credit may affect access to certain of ACE’s potential funding sources.

Debt Securities

ACE has a Mortgage and Deed of Trust (the Mortgage) under which it issues First Mortgage Bonds. First Mortgage Bonds issued under the Mortgage are secured by a lien on substantially all of ACE’s property, plant and equipment, except for such property excluded from the lien of the Mortgage. The principal amount of First Mortgage Bonds that ACE may issue under the Mortgage is limited by the principal amount of retired First Mortgage Bonds and 65% of the lesser of the cost or fair value of new property

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additions that have not been used as the basis for the issuance of additional First Mortgage Bonds. ACE also has an indenture under which it issues senior notes secured by First Mortgage Bonds and an indenture under which it can issue unsecured debt securities, including VRDBs. To fund the construction of pollution control facilities, ACE also has from time to time raised capital through tax-exempt bonds, including tax-exempt VRDBs, issued by a municipality, the proceeds of which are loaned to ACE by the municipality.

Information concerning the principal amount and terms of ACE’s outstanding First Mortgage Bonds, senior notes and tax-exempt bonds issued for the benefit of ACE, as of December 31, 2015, is set forth in Note (9), “Debt,” to the consolidated financial statements of ACE.

Bank Financing

As further discussed in Note (9), “Debt,” to the consolidated financial statements of ACE, ACE is a borrower under a $1.5 billion unsecured syndicated credit facility, along with PHI, Pepco and DPL, which expires in August 2018. This credit facility provides for ACE’s liquidity needs, including obtaining letters of credit, borrowing for general corporate purposes and supporting its commercial paper program. ACE’s credit limit under the facility is the lesser of $250 million and the maximum amount of short-term debt ACE is permitted to have outstanding by its regulatory authorities. The short-term borrowing limit established by the NJBPU for ACE is $350 million.

Commercial Paper Program

ACE maintains an ongoing commercial paper program to address its short-term liquidity needs. As of December 31, 2015, the maximum capacity available under the program was $350 million, subject to available borrowing capacity under the credit facility.

ACE had $5 million of commercial paper outstanding at December 31, 2015. The weighted average interest rate for commercial paper issued by ACE during 2015 was 0.46% and the weighted average maturity of all commercial paper issued by ACE during 2015 was six days.

Money Pool

ACE participates in the money pool operated by PHI under authorization received from the NJBPU. The money pool is an unsecured cash management mechanism used by PHI and eligible subsidiaries to manage their short-term investment and borrowing requirements. PHI may invest in, but not borrow from, the money pool. Eligible subsidiaries with surplus cash may deposit those funds in the money pool. Deposits in the money pool are guaranteed by PHI. Eligible subsidiaries with cash requirements may borrow from the money pool. Depositors in the money pool receive, and borrowers from the money pool pay, an interest rate based primarily on PHI’s short-term borrowing rate. PHI deposits funds in the money pool to the extent that the pool has insufficient funds to meet the borrowing needs of its participants, which may require PHI to borrow funds for deposit from external sources. By regulatory order, the NJBPU has restricted ACE’s participation in the PHI money pool. ACE may not invest in the money pool, but may borrow from it if the interest rates are lower than the interest rates at which ACE could borrow funds externally.

Preferred Stock

Under its Certificate of Incorporation, ACE is authorized to issue and have outstanding up to (i) 799,979 shares of Cumulative Preferred Stock, (ii) 2 million shares of No Par Preferred Stock and (iii) 3 million shares of Preference Stock, each such type of preferred stock having such terms and conditions as are set forth in or authorized by the Certificate of Incorporation. As of December 31, 2015 and 2014, ACE had no shares of preferred stock outstanding.

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Regulatory Restrictions on Financing Activities

ACE’s long-term and short-term (consisting of debt instruments with a maturity of one year or less) financing activities are subject to authorization by the NJBPU. Through its periodic filings with the NJBPU, ACE generally maintains standing authority sufficient to cover its projected financing needs over a multi-year period. ACE’s long-term and short-term financing activities do not require FERC approval.

State corporate laws impose limitations on the funds that can be used to pay dividends. In addition, ACE must obtain the approval of the NJBPU before dividends can be paid if its equity as a percent of its total capitalization, excluding securitization debt, falls below 30%. As of December 31, 2015, ACE complied with this requirement without the need to seek approval of the NJBPU.

Capital Expenditures

ACE’s capital expenditures for the year ended December 31, 2015 were $300 million. These expenditures were primarily related to capital costs associated with distribution and transmission services. The expenditures also include an allocation by PHI of hardware and software expenditures that primarily benefit Power Delivery and are allocated to ACE when the assets are placed in service.

ACE’s projected capital expenditures for the five-year period from 2016 through 2020 are summarized below. ACE expects to fund these expenditures through internally generated cash, external financing and capital contributions from PHI.

	For the Year Ended December 31,
	2016		2017		2018		2019		2020		Total
	(millions of dollars)
ACE
Distribution	$	125	$	132	$	133	$	131	$	133	$	654
Transmission		165		152		151		97		78		643
Other		26		23		20		11		14		94
Total ACE	$	316	$	307	$	304	$	239	$	225	$	1,391

Transmission and Distribution

The projected capital expenditures listed in the table for distribution and transmission are primarily for facility replacements and upgrades to accommodate customer growth and service reliability, including continued capital expenditures for reliability enhancement efforts.

DOE Capital Reimbursement Awards

During 2009, the DOE announced a $168 million award to PHI under the American Recovery and Reinvestment Act of 2009 for the implementation of an AMI system, direct load control, distribution automation, and communications infrastructure, of which $19 million was for ACE’s service territory.

During 2010, ACE and the DOE signed agreements formalizing ACE’s $19 million share of the $168 million award. Of the $19 million, $12 million was offset against smart grid-related capital expenditures of ACE. The remaining $7 million was used to offset incremental expenditures associated with direct load control and other programs, which were deferred as regulatory assets. As of December 31, 2015, ACE has received all of its DOE award payments.

The IRS has announced that, to the extent these grants are expended on capital items, they will not be considered taxable income.

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Pension and Other Postretirement Benefit Plans

ACE participates in pension and OPEB plans sponsored by PHI for its employees. ACE made no contributions to the PHI Retirement Plan during 2015 and 2014. In 2015 and 2014, ACE contributed $3 million in each year to the other postretirement benefit plan.

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Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Risk management policies for PHI and its subsidiaries are determined by PHI’s Corporate Risk Management Committee (CRMC), the members of which are PHI’s Chief Risk Officer, Executive Vice President (Power Delivery), Chief Financial Officer, General Counsel, Chief Information Officer and other senior executives. The CRMC monitors interest rate fluctuation, commodity price fluctuation, and credit risk exposure, and sets risk management policies that establish limits on unhedged risk and determine risk reporting requirements. For information about PHI’s derivative activities, other than the information otherwise disclosed herein, refer to Note (2), “Significant Accounting Policies – Accounting For Derivatives,” and Note (14), “Derivative Instruments and Hedging Activities,” of the consolidated financial statements of PHI.

Pepco Holdings, Inc.

Interest Rate Risk

Pepco Holdings’ and its subsidiaries’ variable or floating rate debt is subject to the risk of fluctuating interest rates in the normal course of business. Pepco Holdings manages interest rate risk through the use of fixed and, to a lesser extent, variable rate debt. The effect of a hypothetical 10% change in interest rates on the annual interest costs for short-term and variable rate debt was $1 million as of December 31, 2015.

Potomac Electric Power Company

Interest Rate Risk

Pepco’s debt is subject to the risk of fluctuating interest rates in the normal course of business. Pepco manages interest rate risk through the use of fixed and, to a lesser extent, variable rate debt. The effect of a hypothetical 10% change in interest rates on the annual interest costs for short-term debt and variable rate debt was less than $1 million as of December 31, 2015.

Delmarva Power & Light Company

Commodity Price Risk

DPL uses derivative instruments (for example, forward contracts, futures, swaps, and exchange-traded and over-the-counter options) primarily to reduce natural gas commodity price volatility. DPL also manages commodity risk with capacity contracts that do not meet the definition of derivatives. The primary goal of these activities is to reduce the exposure of its regulated retail natural gas customers to natural gas price spikes. All premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all gains and losses on the natural gas hedging activity, are fully recoverable through the GCR clause included in DPL’s natural gas tariff rates approved by the DPSC and are deferred until recovered. At December 31, 2015 and 2014, after the effects of cash collateral and netting of derivative assets and liabilities available to be offset under master netting arrangements, DPL had no net derivative assets or liabilities.

Interest Rate Risk

DPL’s debt is subject to the risk of fluctuating interest rates in the normal course of business. DPL manages interest rate risk through the use of fixed and, to a lesser extent, variable rate debt. The effect of a hypothetical 10% change in interest rates on the annual interest costs for short-term debt and variable rate debt was less than $1 million as of December 31, 2015.

133

Atlantic City Electric Company

Interest Rate Risk

ACE’s debt is subject to the risk of fluctuating interest rates in the normal course of business. ACE manages interest rate risk through the use of fixed and, to a lesser extent, variable rate debt. The effect of a hypothetical 10% change in interest rates on the annual interest costs for short-term debt and variable rate debt was less than $1 million as of December 31, 2015.

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Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Listed below is a table that sets forth, for each registrant, the page number where the information is contained herein.

	Registrants
Item	Pepco Holdings		Pepco *		DPL *		ACE
Management’s Report on Internal Control Over Financial Reporting		136		230		273		314
Report of Independent Registered Public Accounting Firm		137		231		274		315
Consolidated Statements of Income (Loss)		139		232		275		316
Consolidated Statements of Comprehensive Income (Loss)		140		N/A		N/A		N/A
Consolidated Balance Sheets		141		233		276		317
Consolidated Statements of Cash Flows		143		235		278		319
Consolidated Statements of Equity		144		236		279		320
Notes to Consolidated Financial Statements		145		237		280		321

* Pepco and DPL have no operating subsidiaries and, therefore, their financial statements are not consolidated.

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Management’s Report on Internal Control Over Financial Reporting

The management of Pepco Holdings, Inc. (Pepco Holdings) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management of Pepco Holdings assessed Pepco Holdings’ internal control over financial reporting as of December 31, 2015 based on criteria established in the Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its assessment, the management of Pepco Holdings concluded that Pepco Holdings’ internal control over financial reporting was effective as of December 31, 2015.

PricewaterhouseCoopers LLP, the independent registered public accounting firm that audited the consolidated financial statements of Pepco Holdings included in this Annual Report on Form 10-K, has also issued its attestation report on the effectiveness of Pepco Holdings’ internal control over financial reporting, which is included herein.

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Report of Independent Registered Public Accounting Firm

To the Shareholders and Board of Directors of

Pepco Holdings, Inc.

In our opinion, the consolidated financial statements listed in the accompanying index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Pepco Holdings, Inc. and its subsidiaries at December 31, 2015 and December 31, 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in the accompanying index appearing under Item 15(a)(2) present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on criteria established in the Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedules, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements, on the financial statement schedules, and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

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Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

Washington, D.C.

February 18, 2016

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PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (LOSS)

For the Year Ended December 31,	2015			2014			2013
	(millions of dollars, except per share data)
Operating Revenue	$	5,023		$	4,878		$	4,666
Operating Expenses
Fuel and purchased energy		2,097			2,080			2,070
Other services cost of sales		175			207			146
Other operation and maintenance		1,016			924			851
Depreciation and amortization		651			549			473
Other taxes		427			413			428
Deferred electric service costs		30			20			26
Impairment losses		—			81			4
Gains on sales of land		(46	)		—			—
Total Operating Expenses		4,350			4,274			3,998
Operating Income		673			604			668
Other Income (Expenses)
Interest expense		(280	)		(268	)		(273	)
Gain from equity investments		—			—			2
Other income		54			44			32
Total Other Expenses		(226	)		(224	)		(239	)
Income from Continuing Operations Before Income Tax Expense		447			380			429
Income Tax Expense Related to Continuing Operations		129			138			319
Net Income from Continuing Operations		318			242			110
Income (Loss) from Discontinued Operations, net of Income Taxes		9			—			(322	)
Net Income (Loss)	$	327		$	242		$	(212	)
Basic Share Information
Weighted average shares outstanding – Basic (millions)		253			251			246
Earnings per share of common stock from Continuing Operations - Basic	$	1.25		$	0.96		$	0.45
Earnings (loss) per share of common stock from Discontinued Operations – Basic		0.04			—			(1.31	)
Earnings (loss) per share - Basic	$	1.29		$	0.96		$	(0.86	)
Diluted Share Information
Weighted average shares outstanding – Diluted (millions)		254			252			246
Earnings per share of common stock from Continuing Operations - Diluted	$	1.25		$	0.96		$	0.45
Earnings (loss) per share of common stock from Discontinued Operations - Diluted		0.04			—			(1.31	)
Earnings (loss) per share - Diluted	$	1.29		$	0.96		$	(0.86	)

The accompanying Notes are an integral part of these Consolidated Financial Statements.

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PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Year Ended December 31,	2015		2014			2013
	(millions of dollars)
Net Income (Loss)	$	327	$	242		$	(212	)
Other Comprehensive Income (Loss) from Continuing Operations
Losses on treasury rate locks reclassified into income		1		1			1
Pension and other postretirement benefit plans		15		(20	)		13
Other comprehensive income (loss), before income taxes		16		(19	)		14
Income tax expense (benefit) related to other comprehensive income		6		(7	)		6
Other comprehensive income (loss) from continuing operations, net of income taxes		10		(12	)		8
Other Comprehensive Income from Discontinued Operations, Net of Income Taxes		—		—			6
Comprehensive Income (Loss)	$	337	$	230		$	(198	)

The accompanying Notes are an integral part of these Consolidated Financial Statements.

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PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS	December 31, 2015			December 31, 2014
	(millions of dollars)
CURRENT ASSETS
Cash and cash equivalents	$	25		$	14
Restricted cash equivalents		14			25
Accounts receivable, less allowance for uncollectible accounts of $56 million and $40 million, respectively		839			782
Inventories		141			141
Income taxes and related accrued interest receivable		111			9
Prepaid expenses and other		72			63
Total Current Assets		1,202			1,034
OTHER ASSETS
Goodwill		1,406			1,407
Regulatory assets		2,246			2,409
Deferred income tax assets, net		15			17
Income taxes and related accrued interest receivable		6			81
Restricted cash equivalents		18			14
Other		129			121
Total Other Assets		3,820			4,049
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		16,218			15,465
Accumulated depreciation		(4,914	)		(4,959	)
Net Property, Plant and Equipment		11,304			10,506
TOTAL ASSETS	$	16,326		$	15,589

The accompanying Notes are an integral part of these Consolidated Financial Statements.

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PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

LIABILITIES AND EQUITY	December 31, 2015			December 31, 2014
	(millions of dollars, except shares)
CURRENT LIABILITIES
Short-term debt	$	1,063		$	729
Current portion of long-term debt and project funding		341			431
Accounts payable		175			174
Accrued liabilities		322			313
Capital lease obligations due within one year		11			10
Taxes accrued		51			41
Interest accrued		49			47
Liabilities and accrued interest related to uncertain tax positions		9			6
Other		287			305
Total Current Liabilities		2,308			2,056
DEFERRED CREDITS
Regulatory liabilities		308			343
Deferred income tax liabilities, net		3,393			3,242
Investment tax credits		15			16
Pension benefit obligation		466			396
Other postretirement benefit obligations		215			265
Other		202			195
Total Deferred Credits		4,599			4,457
OTHER LONG-TERM LIABILITIES
Long-term debt		4,656			4,397
Transition bonds issued by ACE Funding		124			170
Long-term project funding		4			8
Capital lease obligations		39			50
Total Other Long-Term Liabilities		4,823			4,625
COMMITMENTS AND CONTINGENCIES (NOTE 16)
PREFERRED STOCK
Series A preferred stock, $.01 par value – 18,000 shares authorized, 18,000 and 12,600 shares outstanding, respectively		183			129
EQUITY
Common stock, $.01 par value – 400,000,000 shares authorized, 254,289,261 and 252,728,684 shares outstanding, respectively		3			3
Premium on stock and other capital contributions		3,829			3,800
Accumulated other comprehensive loss		(36	)		(46	)
Retained earnings		617			565
Total Equity		4,413			4,322
TOTAL LIABILITIES AND EQUITY	$	16,326		$	15,589

The accompanying Notes are an integral part of these Consolidated Financial Statements.

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PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Year Ended December 31,	2015			2014			2013
	(millions of dollars)
OPERATING ACTIVITIES
Net income (loss)	$	327		$	242		$	(212	)
(Income) loss income from discontinued operations, net of income taxes		(9	)		—			322
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		651			549			473
Deferred income taxes		122			302			458
Gains on sales of land		(46	)		—			—
Losses on treasury rate locks reclassified into income		1			1			1
Impairment losses		—			81			4
Increase in fair value of preferred stock derivative		(15	)		—			—
Other		(2	)		(6	)		(13	)
Changes in:
Accounts receivable		(56	)		48			(46	)
Inventories		—			7			5
Prepaid expenses		8			(8	)		17
Regulatory assets and liabilities, net		(146	)		(216	)		(121	)
Accounts payable and accrued liabilities		(14	)		(22	)		1
Pension contributions		—			—			(120	)
Pension benefit obligation, excluding contributions		76			48			65
Cash collateral related to derivative activities		2			(9	)		31
Income tax-related prepayments, receivables and payables		32			(173	)		(182	)
Advanced payment made to taxing authority		—			—			(242	)
Other assets and liabilities		8			10			9
Net current assets held for disposition or sale		—			—			47
Net Cash From Operating Activities		939			854			497
INVESTING ACTIVITIES
Investment in property, plant and equipment		(1,230	)		(1,223	)		(1,310	)
Department of Energy capital reimbursement awards received		—			4			22
Proceeds from sales of land		54			—			—
Changes in restricted cash equivalents		7			(12	)		1
Net other investing activities		8			5			3
Proceeds from discontinued operations, early termination of finance leases held in trust		—			—			873
Net Cash Used By Investing Activities		(1,161	)		(1,226	)		(411	)
FINANCING ACTIVITIES
Dividends paid on common stock		(275	)		(272	)		(270	)
Common stock issued for the Direct Stock Purchase and Dividend Reinvestment Plan (DRP) and employee-related compensation		18			34			50
Issuances of common stock		—			—			324
Issuances of Series A preferred stock		54			126			—
Issuances of long-term debt		558			766			800
Reacquisitions of long-term debt		(420	)		(334	)		(558	)
Issuances (repayments) of short-term debt, net		34			164			(200	)
Borrowings under term loans		300			—			250
Repayments of term loans		—			(100	)		(450	)
Cost of issuances		(7	)		(10	)		(23	)
Net other financing activities		(29	)		(11	)		(11	)
Net Cash From (Used By) Financing Activities		233			363			(88	)
Net Increase (Decrease) In Cash and Cash Equivalents		11			(9	)		(2	)
Cash and Cash Equivalents at Beginning of Year		14			23			25
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	25		$	14		$	23
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for interest (net of capitalized interest of $8 million, $8 million and $7 million, respectively)	$	268		$	257		$	260
Cash (received) paid for income taxes		(13	)		(2	)		228

The accompanying Notes are an integral part of these Consolidated Financial Statements.

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PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY

	Common Stock					Premium on Stock		Accumulated Other Comprehensive (Loss) Income			Retained Earnings			Total
(millions of dollars, except shares)	Shares			Par Value
Balance as of December 31, 2012		230,015,427		$	2	$	3,383	$	(48	)	$	1,077		$	4,414
Net Loss		—			—		—		—			(212	)		(212	)
Other comprehensive income		—			—		—		14			—			14
Dividends on common stock ($1.08 per share)		—			—		—		—			(270	)		(270	)
Issuance of common stock:
Original issue shares, net		18,734,128			1		331		—			—			332
DRP original issue shares		1,575,343			—		30		—			—			30
Net activity related to stock-based awards		—			—		7		—			—			7
Balance as of December 31, 2013		250,324,898			3		3,751		(34	)		595			4,315
Net Income		—			—		—		—			242			242
Other comprehensive loss		—			—		—		(12	)		—			(12	)
Dividends on common stock ($1.08 per share)		—			—		—		—			(272	)		(272	)
Issuance of common stock:
Original issue shares, net		1,310,276			—		14		—			—			14
DRP original issue shares		1,122,575			—		28		—			—			28
Net activity related to stock-based awards		(29,065	)		—		7		—			—			7
Balance as of December 31, 2014		252,728,684			3		3,800		(46	)		565			4,322
Net Income		—			—		—		—			327			327
Other comprehensive income		—			—		—		10			—			10
Dividends on common stock ($1.08 per share)		—			—		—		—			(275	)		(275	)
Issuance of common stock:
Original issue shares, net		1,157,203			—		15		—			—			15
DRP original issue shares		397,939			—		11		—			—			11
Net activity related to stock-based awards		5,435			—		3		—			—			3
Balance as of December 31, 2015		254,289,261		$	3	$	3,829	$	(36	)	$	617		$	4,413

The accompanying Notes are an integral part of these Consolidated Financial Statements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

PEPCO HOLDINGS, INC.

(1) ORGANIZATION

Pepco Holdings, Inc. (PHI or Pepco Holdings), a Delaware corporation incorporated in 2001, is a holding company that, through the following regulated public utility subsidiaries, is engaged primarily in the transmission, distribution and default supply of electricity and, to a lesser extent, the distribution and supply of natural gas (Power Delivery):

• Potomac Electric Power Company (Pepco), which was incorporated in Washington, D.C. in 1896 and became a domestic Virginia corporation in 1949,

• Delmarva Power & Light Company (DPL), which was incorporated in Delaware in 1909 and became a domestic Virginia corporation in 1979, and

• Atlantic City Electric Company (ACE), which was incorporated in New Jersey in 1924.

Each of PHI, Pepco, DPL and ACE is also a reporting company under the Securities Exchange Act of 1934, as amended. Together, Pepco, DPL and ACE constitute the Power Delivery segment for financial reporting purposes.

Through Pepco Energy Services, Inc. and its subsidiaries (collectively, Pepco Energy Services), PHI provides energy savings performance contracting services, underground transmission and distribution construction and maintenance services, and steam and chilled water under long-term contracts.

PHI Service Company, a wholly owned subsidiary service company of PHI, provides a variety of support services, including legal, accounting, treasury, tax, purchasing and information technology services to PHI and its operating subsidiaries. These services are provided pursuant to service agreements among PHI, PHI Service Company and the participating operating subsidiaries. The expenses of PHI Service Company are charged to PHI and the participating operating subsidiaries in accordance with cost allocation methodologies set forth in the service agreements.

Agreement and Plan of Merger with Exelon Corporation

PHI entered into an Agreement and Plan of Merger, dated April 29, 2014, as amended and restated on July 18, 2014 (the Merger Agreement), with Exelon Corporation, a Pennsylvania corporation (Exelon), and Purple Acquisition Corp., a Delaware corporation and an indirect, wholly owned subsidiary of Exelon (Merger Sub), providing for the merger of Merger Sub with and into PHI (the Merger), with PHI surviving the Merger as an indirect, wholly owned subsidiary of Exelon. Pursuant to the Merger Agreement, at the effective time of the Merger, each outstanding share of common stock, par value $0.01 per share, of PHI (other than (i) shares owned by Exelon, Merger Sub or any other direct or indirect wholly owned subsidiary of Exelon and shares owned by PHI or any direct or indirect, wholly owned subsidiary of PHI, and in each case not held on behalf of third parties (but not including shares held by PHI in any rabbi trust or similar arrangement in respect of any compensation plan or arrangement) and (ii) shares that are owned by stockholders who have perfected and not withdrawn a demand for appraisal rights pursuant to Delaware law), will be canceled and converted into the right to receive $27.25 in cash, without interest.

In connection with entering into the Merger Agreement, as further described in Note (13), “Preferred Stock,” PHI entered into a Subscription Agreement with Exelon dated April 29, 2014 (the Subscription Agreement), pursuant to which PHI issued to Exelon 9,000 originally issued shares of non-voting, non-convertible and non-transferable Series A preferred stock, par value $0.01 per share (the Preferred Stock), for a purchase price of $90 million on April 30, 2014. Exelon also committed, pursuant to the

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Subscription Agreement, to purchase 1,800 originally issued shares of Preferred Stock for a purchase price of $18 million at the end of each 90-day period following the date of the Subscription Agreement until the Merger closes or is terminated, up to a maximum of 18,000 shares of Preferred Stock for a maximum aggregate consideration of $180 million. In accordance with the Subscription Agreement, on each of July 29, 2014, October 27, 2014, January 26, 2015, April 27, 2015 and July 24, 2015, an additional 1,800 shares of Preferred Stock were issued by PHI to Exelon for an aggregate purchase price of $90 million.

The Merger Agreement provides for certain termination rights for each of PHI and Exelon, and further provides that, upon termination of the Merger Agreement under certain specified circumstances, PHI will be required to pay Exelon a termination fee of $259 million or reimburse Exelon for its expenses up to $40 million (which reimbursement of expenses shall reduce on a dollar for dollar basis any termination fee subsequently payable by PHI), provided, however, that if the Merger Agreement is terminated in connection with an acquisition proposal made under certain circumstances by a person who made an acquisition proposal between April 1, 2014 and the date of the Merger Agreement, the termination fee will be $293 million plus reimbursement of Exelon for its expenses up to $40 million (not subject to offset). In addition, if the Merger Agreement is terminated under certain circumstances due to the failure to obtain required regulatory approvals with respect to the Merger or the breach by Exelon of its obligations in respect of obtaining such regulatory approvals (a Regulatory Termination), PHI will be able to redeem any issued and outstanding Preferred Stock at par value, and in that case, Exelon will be required to pay all documented out-of-pocket expenses incurred by PHI in connection with the Merger Agreement or the transactions contemplated thereby, up to $40 million. If the Merger Agreement is terminated, other than for a Regulatory Termination, PHI will be required to redeem the Preferred Stock at the purchase price of $10,000 per share, plus any unpaid accrued and accumulated dividends thereupon.

Consummation of the Merger is subject to the satisfaction or waiver of specified closing conditions, including (i) the approval of the Merger by the holders of a majority of the outstanding shares of common stock of PHI; (ii) the receipt of regulatory approvals required to consummate the Merger, including approvals from the Federal Energy Regulatory Commission (FERC), the Federal Communications Commission (FCC), the Delaware Public Service Commission (DPSC), the District of Columbia Public Service Commission (DCPSC), the Maryland Public Service Commission (MPSC), the New Jersey Board of Public Utilities (NJBPU) and the Virginia State Corporation Commission (VSCC); (iii) the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (the HSR Act); and (iv) other customary closing conditions, including (a) the accuracy of each party’s representations and warranties (subject to customary materiality qualifiers) and (b) each party’s compliance with its obligations and covenants contained in the Merger Agreement (including covenants that may limit, restrict or prohibit PHI and its subsidiaries from taking specified actions during the period between the date of the Merger Agreement and the closing of the Merger or the termination of the Merger Agreement). In addition, the obligations of Exelon and Merger Sub to consummate the Merger are subject to the required regulatory approvals not imposing terms, conditions, obligations or commitments, individually or in the aggregate, that constitute a burdensome condition (as defined in the Merger Agreement). For additional discussion, see Note (7), “Regulatory Matters – Merger Approval Proceedings.”

On September 23, 2014, the stockholders of PHI approved the Merger, on October 7, 2014, the VSCC approved the Merger, and on November 20, 2014, FERC approved the Merger. In addition, the transfer of control of certain communications licenses held by certain of PHI’s subsidiaries has been approved by the FCC. The NJBPU approved the Merger on February 11, 2015 and, on October 15, 2015, voted to extend the effectiveness of its approval until June 30, 2016. The DPSC approved the Merger on May 19, 2015.

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The waiting period expired under the HSR Act on December 2, 2015, which allows for the closing of the Merger at any time on or before December 1, 2016.

On May 15, 2015, the MPSC approved the Merger, with conditions, including conditions that modify and supplement those originally proposed. On May 18, 2015, PHI and Exelon announced that they had committed to fulfill the modified, more stringent conditions and package of customer benefits imposed by the MPSC. In connection with these proceedings, the Maryland Office of People’s Counsel and several other parties to the Merger proceedings filed motions in the Circuit Court for Queen Anne’s County, Maryland, requesting a stay of the MPSC order. On August 7, 2015, the Circuit Court for Queen Anne’s County denied the motions for stay. On January 8, 2016, the Circuit Court affirmed the MPSC’s order in all respects. On January 20 and 22, 2016, respectively, the Maryland Office of People’s Counsel and environmental groups filed notices of appeal of the Circuit Court’s order to the Maryland Court of Special Appeals. Unless a motion to stay is filed and then granted by the court, the MPSC order will remain in effect during the appeals process.

On August 27, 2015, the DCPSC issued a written order denying the application seeking approval of the Merger. On September 28, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, filed an application for reconsideration with the DCPSC requesting reconsideration of the DCPSC order related to the Merger.

On October 6, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, entered into a Nonunanimous Full Settlement Agreement and Stipulation (the DC Settlement Agreement) with the District of Columbia Government, the Office of the People’s Counsel and other parties, which DC Settlement Agreement contains commitments from Exelon and PHI above those contained in their original merger application.

Also on October 6, 2015, PHI, Exelon and Merger Sub entered into a Letter Agreement (the Letter Agreement), setting forth the terms and conditions under which the parties will file with the DCPSC (a) a Motion of Joint Applicants to Reopen the Record in Formal Case No. 1119 to Allow for Consideration of the DC Settlement Agreement (the Motion to Reopen), or (b) if the Motion to Reopen is not granted, a new merger application, requesting approval of the Merger on the terms and commitments agreed to in the DC Settlement Agreement. Pursuant to the Letter Agreement, PHI and Exelon each agrees, among other things, that neither party will exercise the termination rights each may have under the Merger Agreement on or after October 29, 2015, unless: (i) the DCPSC does not, by November 20, 2015, set a procedural schedule which allows for a final order for approval of the Merger by March 4, 2016, (ii) the DCPSC sets a schedule for action which does not allow for a final order for approval of the Merger by March 4, 2016, (iii) the DCPSC fails to issue a final order approving the Merger and the DC Settlement Agreement as filed without condition or modification by March 4, 2016, (iv) the DCPSC issues a final order denying approval of the Merger or the DC Settlement Agreement or adds conditions or makes modifications to the DC Settlement Agreement, (v) the DC Settlement Agreement is terminated for any reason, or (vi) after March 4, 2016 a condition to closing of the Merger has not been satisfied or waived (other than those conditions that by their nature are to be satisfied at the closing). The Letter Agreement also provides that, subject to certain conditions, Exelon may, following receipt of all regulatory approvals consistent with the DC Settlement Agreement, delay closing of the Merger for up to 30 days to engage in capital markets transactions to raise additional funds required to consummate the Merger.

On October 6, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, filed with the DCPSC the Motion to Reopen requesting consideration of the DC Settlement Agreement and approval of the Merger on such terms and conditions set forth in the DC Settlement Agreement, without condition or modification, and to stay further proceedings on the application for reconsideration filed by the parties on September 28, 2015 and suspend the time period for reconsideration pending the DCPSC’s consideration of the DC Settlement Agreement.

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On October 28, 2015, the DCPSC approved the Motion to Reopen and set a procedural schedule for its review of this matter. Upon completion of the public input and evidentiary hearings, the record was closed as of December 23, 2015. Although District of Columbia law does not impose any time limit on the DCPSC’s review of the Merger, the parties requested a decision by March 4, 2016.

Power Delivery

Each of Pepco, DPL and ACE is a regulated public utility in the jurisdictions that comprise its service territory. Each utility owns and operates a network of wires, substations and other equipment that is classified as transmission facilities, distribution facilities or common facilities (which are used for both transmission and distribution). Transmission facilities are high-voltage systems that carry wholesale electricity into, or across, the utility’s service territory. Distribution facilities are low-voltage systems that carry electricity to end-use customers in the utility’s service territory.

Each utility is responsible for the distribution of electricity, and in the case of DPL, the distribution and supply of natural gas, in its service territory, for which it is paid tariff rates established by the applicable local public service commissions. Each utility also supplies electricity at regulated rates to retail customers in its service territory who do not elect to purchase electricity from a competitive energy supplier. The regulatory term for this supply service is Standard Offer Service (SOS) in Delaware, the District of Columbia and Maryland, and Basic Generation Service in New Jersey. These supply service obligations are referred to generally as Default Electricity Supply.

Pepco Energy Services

Pepco Energy Services is engaged in the following businesses:

• Energy savings performance contracting: designing, constructing and operating energy efficiency projects and distributed generation equipment, including combined heat and power plants, principally for federal, state and local government customers;

• Underground transmission and distribution: providing underground transmission and distribution construction and maintenance services for electric utilities in North America; and

• Thermal: providing steam and chilled water under long-term contracts through systems owned and operated by Pepco Energy Services, primarily to hotels and casinos in Atlantic City, New Jersey.

During 2012, Pepco Energy Services deactivated its Buzzard Point and Benning Road oil-fired generation facilities. Pepco Energy Services completed demolition of the Benning Road generation facility in July 2015 and recognized the scrap metal salvage value of the facility as a reduction in its demolition expenses over the life of the project.

Corporate and Other

Corporate and Other includes the remaining operations of the former Other Non-Regulated segment, certain parent company transactions (including interest expense on parent company debt and incremental external merger-related costs) and inter-company eliminations.

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Discontinued Operations

Cross-Border Energy Lease Investments

Through its subsidiary PCI, PHI held a portfolio of cross-border energy lease investments. During 2013, PHI completed the termination of its interest in its cross-border energy lease investments and, as a result, these investments have been accounted for as discontinued operations.

Pepco Energy Services

In December 2009, PHI announced the wind-down of the retail energy supply component of the Pepco Energy Services business which was comprised of the retail electric and natural gas supply businesses. Pepco Energy Services implemented the wind-down by not entering into any new retail electric or natural gas supply contracts while continuing to perform under its existing retail electric and natural gas supply contracts through their respective expiration dates. On March 21, 2013, Pepco Energy Services entered into an agreement whereby a third party assumed all the rights and obligations of the remaining retail natural gas supply customer contracts, and the associated supply obligations, inventory and derivative contracts. The transaction was completed on April 1, 2013. In addition, Pepco Energy Services completed the wind-down of its retail electric supply business in the second quarter of 2013 by terminating its remaining customer supply and wholesale purchase obligations beyond June 30, 2013.

The operations of Pepco Energy Services’ retail electric and natural gas supply businesses have been classified as discontinued operations and are no longer a part of the Pepco Energy Services segment for financial reporting purposes.

(2) SIGNIFICANT ACCOUNTING POLICIES

Consolidation Policy

The accompanying consolidated financial statements include the accounts of Pepco Holdings and its wholly owned subsidiaries. All material intercompany balances and transactions between subsidiaries have been eliminated. Pepco Holdings uses the equity method to report investments, corporate joint ventures, partnerships, and affiliated companies in which it holds an interest and can exercise significant influence over the operations and policies of the entity. Certain transmission and other facilities currently held are consolidated in proportion to PHI’s percentage interest in the facility.

Consolidation of Variable Interest Entities

PHI assesses its contractual arrangements with variable interest entities (VIEs) to determine whether it is the primary beneficiary and thereby has to consolidate the entities in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 810. The guidance addresses conditions under which an entity should be consolidated based upon variable interests rather than voting interests. See Note (17), “Variable Interest Entities,” for additional information.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the consolidated financial statements and accompanying notes. Although Pepco Holdings believes that its estimates and assumptions are reasonable, they are based upon information available to management at the time the estimates are made. Actual results may differ significantly from these estimates.

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Significant matters that involve the use of estimates include the assessment of contingencies, the calculation of future cash flows and fair value amounts for use in asset and goodwill impairment calculations, fair value calculations for derivative instruments, pension and other postretirement benefit assumptions, the assessment of the adequacy of the allowance for uncollectible accounts, the assessment of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of unbilled revenue, recognition of changes in network service transmission rates for prior service year costs, accrual of loss contingency liabilities for general litigation and auto and other liability claims, accrual of interest related to income taxes, the recognition of lease income and income tax benefits for investments in finance leases held in trust associated with PHI’s former cross-border energy lease investments (see Note (20), “Discontinued Operations – Cross-Border Energy Lease Investments”), and income tax provisions and reserves. Additionally, PHI is subject to legal, regulatory and other proceedings and claims that arise in the ordinary course of its business. PHI records an estimated liability for these proceedings and claims when it is probable that a loss has been incurred and the loss is reasonably estimable.

Revenue Recognition

Regulated Revenue

Power Delivery recognizes revenue upon distribution of electricity and natural gas to its customers, including unbilled revenue for services rendered but not yet billed. PHI’s unbilled revenue was $139 million and $172 million as of December 31, 2015 and 2014, respectively, and these amounts are included in Accounts receivable. PHI’s utility subsidiaries calculate unbilled revenue using an output-based methodology. This methodology is based on the supply of electricity or natural gas intended for distribution to customers. The unbilled revenue process requires management to make assumptions and judgments about input factors such as customer sales mix, temperature and estimated line losses (estimates of electricity and natural gas expected to be lost in the process of its transmission and distribution to customers). The assumptions and judgments are inherently uncertain and susceptible to change from period to period, and if the actual results differ from the projected results, the impact could be material.

Taxes related to the consumption of electricity and natural gas by the utility customers, such as fuel, energy, or other similar taxes, are components of the tariff rates charged by PHI’s utility subsidiaries and, as such, are billed to customers and recorded in Operating revenue. Accruals for the remittance of these taxes are recorded in Other taxes.

Pepco Energy Services Revenue

Revenue for Pepco Energy Services’ energy savings performance construction business and certain construction contracts in its underground transmission and distribution business is recognized using the percentage-of-completion method which recognizes revenue as work is completed and costs are incurred on its contracts. Under this method, Pepco Energy Services recognizes these contractual revenues based on the percentage of incurred costs relative to the estimated costs to complete a contract. Revenues from its operation and maintenance activities and measurement and verification activities in its energy savings business and certain construction contracts in its underground transmission and distribution business are recognized when earned.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in PHI’s gross revenues were $322 million, $321 million and $346 million for the years ended December 31, 2015, 2014 and 2013, respectively.

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Accounting for Derivatives

PHI and its subsidiaries may use derivative instruments primarily to manage risk associated with commodity prices and interest rates. Risk management policies are determined by PHI’s Corporate Risk Management Committee (CRMC). The CRMC monitors interest rate fluctuation, commodity price fluctuation and credit risk exposure, and sets risk management policies that establish limits on unhedged risk.

PHI accounts for its derivative activities in accordance with FASB guidance on derivatives and hedging. Derivatives are recorded on the consolidated balance sheets as Derivative assets or Derivative liabilities and measured at fair value.

Changes in the fair value of derivatives held by DPL that do not qualify for hedge accounting or are not designated as hedges are presented on the consolidated statements of income (loss) as Fuel and purchased energy expense or Operating revenue, respectively. Changes in the fair value of derivatives held by DPL are deferred as regulatory assets or liabilities under the accounting guidance for regulated operations.

The gain or loss on a derivative that qualifies as a cash flow hedge of an exposure to variable cash flows of a forecasted transaction is initially recorded in accumulated other comprehensive loss (AOCL) (a separate component of equity) to the extent that the hedge is effective and is subsequently reclassified into earnings, in the same category as the item being hedged, when the gain or loss from the forecasted transaction occurs. If it is probable that a forecasted transaction will not occur, the deferred gain or loss in AOCL is immediately reclassified to earnings. Gains or losses related to any ineffective portion of cash flow hedges are also recognized in earnings immediately.

Changes in the fair value of derivatives designated as fair value hedges, as well as changes in the fair value of the hedged asset, liability or firm commitment, are recorded in the consolidated statements of income (loss).

The impact of derivatives that are marked to market through current earnings, the ineffective portion of cash flow hedges, and the portion of fair value hedges that flows to current earnings are presented on a net basis in the consolidated statements of income (loss) as Operating revenue or as Fuel and purchased energy expense. When a hedging gain or loss is realized, it is presented on a net basis in the same line item as the underlying item being hedged. Unrealized derivative gains and losses are presented gross on the consolidated balance sheets except where contractual netting agreements are in place with individual counterparties.

The fair value of derivatives is determined using quoted exchange prices where available. For instruments that are not traded on an exchange, pricing services and external broker quotes may also be used to determine fair value. For some custom and complex instruments, internal models use market-based information when external broker quotes are not available. For certain long-dated instruments, broker or exchange data are extrapolated, or capacity prices are forecasted, for future periods where information is limited. Models are also used to estimate volumes for certain transactions.

PHI may enter into master netting arrangements to mitigate credit risk related to its derivatives. Under FASB guidance on offsetting of balance sheet accounts (ASC 210-20), amounts recognized for derivative assets and liabilities and the fair value amounts recognized for any related collateral positions executed with the same counterparty under such master netting agreements are offset.

See Note (14), “Derivative Instruments and Hedging Activities,” for more information about the types of derivatives employed by PHI, the components of any unrealized and realized gains and losses and Note (15), “Fair Value Disclosures,” for the methodologies used to value them.

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Stock-Based Compensation

PHI recognizes compensation expense for stock-based awards, modifications or cancellations based on the grant-date fair value. Compensation expense is recognized over the requisite service period. A deferred tax asset and deferred tax benefit are also recognized concurrently with compensation expense for the tax effect of the deduction of stock options, restricted stock and restricted stock unit awards, which are deductible only upon exercise and/or vesting.

Historically, PHI’s compensation awards had included both time-based restricted stock awards that vest over a three-year service period and performance-based restricted stock and restricted stock units that were earned based on performance over a three-year period. Beginning in 2011, stock-based compensation awards have been granted primarily in the form of restricted stock units. Since May 2012, the Board of Directors have been granted an annual time-based restricted stock unit award that vests over one year as part of their compensation. The compensation expense associated with these awards is calculated based on the estimated fair value of the awards at the grant date and is recognized over the service or performance period.

PHI estimates the fair value of performance-based restricted stock unit awards using the Monte Carlo valuation model. These awards include performance conditions based upon PHI’s total stockholder return (TSR) versus a select group of peer companies over a three-year period. The effect of market conditions is considered in determining the awards’ fair value. This model values the specific features of employee share-based awards, including market-based performance conditions.

PHI’s current policy is to issue new shares to satisfy vested awards of restricted stock units.

Income Taxes

PHI and the majority of its subsidiaries file a consolidated federal income tax return. Federal income taxes are allocated among PHI and the subsidiaries included in its consolidated group pursuant to a written tax sharing agreement, which was approved by the Securities and Exchange Commission (SEC) in 2002 in connection with the establishment of PHI as a public utility holding company. Under this tax sharing agreement, PHI’s consolidated federal income tax liability is allocated based upon PHI’s and its subsidiaries’ separate taxable income or loss amounts.

The consolidated financial statements include current and deferred income taxes. Current income taxes represent the amount of tax expected to be reported on PHI’s and its subsidiaries’ federal and state income tax returns. Deferred income tax assets and liabilities represent the tax effects of temporary differences between the financial statement basis and tax basis of existing assets and liabilities, and they are measured using presently enacted tax rates. See Note (11), “Income Taxes,” for a listing of primary deferred tax assets and liabilities. The portions of Pepco’s, DPL’s and ACE’s deferred tax liabilities applicable to their utility operations that have not been recovered from utility customers represent income taxes recoverable in the future and are included in Regulatory Assets on the consolidated balance sheets. See Note (7), “Regulatory Matters – Regulatory Assets and Regulatory Liabilities,” for additional information.

PHI recognizes interest on underpayments and overpayments of income taxes, interest on uncertain tax positions and tax-related penalties in income tax expense. Deferred income tax expense generally represents the net change during the reporting period in the net deferred tax liability and deferred recoverable income taxes.

Investment tax credits are amortized to income over the useful lives of the related property.

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Cash and Cash Equivalents

Cash and cash equivalents include cash on hand, cash invested in money market funds and commercial paper held with original maturities of three months or less.

Restricted Cash Equivalents

The Restricted cash equivalents included in Current assets and the Restricted cash equivalents included in Other assets consist of (i) cash held as collateral that is restricted from use for general corporate purposes and (ii) cash equivalents that are specifically segregated based on management’s intent to use such cash equivalents for a particular purpose. The classification as current or non-current conforms to the classification of the related liabilities.

Accounts Receivable and Allowance for Uncollectible Accounts

PHI’s Accounts receivable balances primarily consist of customer accounts receivable arising from the sale of goods and services to customers within PHI’s service territories, other accounts receivable, and accrued unbilled revenue. Accrued unbilled revenue represents revenue earned in the current period but not billed to the customer until a future date (usually within one month after the receivable is recorded).

PHI maintains an allowance for uncollectible accounts and changes in the allowance are recorded as an adjustment to Other operation and maintenance expense in the consolidated statements of income (loss). PHI determines the amount of the allowance based on specific identification of material amounts at risk by customer and maintains a reserve based on its historical collection experience. The adequacy of this allowance is assessed on a quarterly basis by evaluating all known factors, such as the aging of the receivables, historical collection experience, the economic and competitive environment and changes in the creditworthiness of its customers. Accounts receivable are written off in the period in which the receivable is deemed uncollectible and collection efforts have been exhausted. Recoveries of Accounts receivable previously written off are recorded when received. Although PHI believes its allowance is adequate, it cannot anticipate with any certainty the changes in the financial condition of its customers. As a result, PHI records adjustments to the allowance for uncollectible accounts in the period in which the new information that requires an adjustment to the reserve becomes known.

Inventories

PHI utilizes the weighted average cost method of accounting for inventory items. Under this method, an average price is determined for the quantity of units acquired at each price level and is applied to the ending quantity to calculate the total ending inventory balance. Materials and supplies are recorded in Inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed.

The cost of natural gas, including transportation costs, is included in Inventory when purchased and charged to Fuel and Purchased Energy expense when used.

Goodwill

Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired at the acquisition date. PHI tests its goodwill for impairment annually as of November 1 and whenever an event occurs or circumstances change in the interim that would more likely than not (that is, a greater than 50% chance) reduce the estimated fair value of a reporting unit below the carrying amount of its net assets. Factors that may result in an interim impairment test include, but are not limited to: a change in the identified reporting units; an adverse change in business conditions; a protracted decline in PHI’s stock price causing market capitalization to fall significantly below book value; an adverse regulatory action; or an impairment of long-lived assets in the reporting unit. PHI performed its most recent annual impairment test as of November 1, 2015, and its goodwill was not impaired as described in Note (6), “Goodwill.”

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Regulatory Assets and Regulatory Liabilities

The operations of Pepco are regulated by the DCPSC and the MPSC. The operations of DPL are regulated by the DPSC and the MPSC. DPL’s interstate transportation and wholesale sale of natural gas are regulated by FERC. The operations of ACE are regulated by the NJBPU. The transmission of electricity by Pepco, DPL and ACE is regulated by FERC.

The FASB guidance on regulated operations (ASC 980) applies to Power Delivery. It allows regulated entities, in appropriate circumstances, to defer the income statement impact of certain costs that are expected to be recovered in future rates through the establishment of regulatory assets and defer certain revenues that are expected to be refunded to customers through the establishment of regulatory liabilities. Management’s assessment of the probability of recovery of regulatory assets requires judgment and interpretation of laws, regulatory commission orders and other factors. If management subsequently determines, based on changes in facts or circumstances, that a regulatory asset is not probable of recovery, then the regulatory asset would be eliminated through a charge to earnings.

Effective June 2007, the MPSC approved a bill stabilization adjustment (BSA) mechanism for retail customers of Pepco and DPL. Effective November 2009, the DCPSC approved a BSA for Pepco’s retail customers. For customers to whom the BSA applies, Pepco and DPL recognize distribution revenue based on an approved distribution charge per customer. From a revenue recognition standpoint, the BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during that period. Pursuant to this mechanism, Pepco and DPL recognize either (i) a positive adjustment equal to the amount by which revenue from Maryland and the District of Columbia retail distribution sales falls short of the revenue that Pepco and DPL are entitled to earn based on the approved distribution charge per customer, or (ii) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that Pepco and DPL are entitled to earn based on the approved distribution charge per customer (a Revenue Decoupling Adjustment). A net positive Revenue Decoupling Adjustment is recorded as a regulatory asset and a net negative Revenue Decoupling Adjustment is recorded as a regulatory liability.

Leasing Activities

Pepco Holdings’ lease transactions include plant, office space, equipment, software, vehicles and elements of power purchase agreements (PPAs). In accordance with FASB guidance on leases (ASC 840), these leases are classified as either leveraged leases, operating leases or capital leases.

Leveraged Leases

Income from investments in leveraged lease transactions, in which PHI was an equity participant, was accounted for using the financing method. In accordance with the financing method, investments in leased property were recorded as a receivable from the lessee to be recovered through the collection of future rentals. Income was recognized over the life of the lease at a constant rate of return on the positive net investment. Each quarter, PHI reviewed the carrying value of each lease, which included a review of the underlying financial assumptions, the timing and collectibility of cash flows, and the credit quality of the lessee. Changes to the underlying assumptions, if any, were accounted for in accordance with FASB guidance on leases and reflected in the carrying value of the lease effective for the quarter within which they occurred.

Operating Leases

An operating lease in which PHI or a subsidiary is the lessee generally results in a level income statement charge over the term of the lease, reflecting the rental payments required by the lease agreement. If rental payments are not made on a straight-line basis, PHI’s policy is to recognize rent expense on a straight-line basis over the lease term unless another systematic and rational allocation basis is more representative of the time pattern in which the leased property is physically employed.

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Capital Leases

For ratemaking purposes, capital leases in which PHI or a subsidiary is the lessee are treated as operating leases; therefore, in accordance with FASB guidance on regulated operations (ASC 980), the amortization of the leased asset is based on the recovery of rental payments through customer rates. Investments in equipment under capital leases are stated at cost, less accumulated depreciation. Depreciation is recorded on a straight-line basis over the equipment’s estimated useful life.

Arrangements Containing a Lease

PPAs are deemed to contain a lease if the arrangement conveys the right to control the use of property, plant or equipment. If so, PHI determines the appropriate lease accounting classification.

Property, Plant and Equipment

Property, plant and equipment is recorded at original cost, including labor, materials, asset retirement costs and other direct and indirect costs including capitalized interest. The carrying value of Property, plant and equipment is evaluated for impairment whenever circumstances indicate the carrying value of those assets may not be recoverable. Upon retirement, the cost of regulated property, net of salvage, is charged to Accumulated depreciation. For non-regulated property, the cost and accumulated depreciation of the property, plant and equipment retired or otherwise disposed of are removed from the related accounts and included in the determination of any gain or loss on disposition.

The annual provision for depreciation on electric and natural gas property, plant and equipment is computed on a straight-line basis using composite rates by classes of depreciable property. Non-operating and other property is generally depreciated on a straight-line basis over the useful lives of the assets. The table below provides system-wide composite annual depreciation rates for the years ended December 31, 2015, 2014 and 2013.

	Transmission and Distribution									Generation
	2015			2014			2013			2015			2014			2013
Pepco		2.3	%		2.3	%		2.2	%		—			—			—
DPL		2.6	%		2.6	%		2.6	%		—			—			—
ACE		2.6	%		2.6	%		2.8	%		—			—			—
Pepco Energy Services		—			—			—			0.6	%		1.2	%		0.4	%

In 2010, subsidiaries of PHI received awards from the U.S. Department of Energy (DOE) under the American Recovery and Reinvestment Act of 2009. Pepco was awarded $149 million from DOE to fund a portion of the costs incurred for the implementation of an advanced metering infrastructure (AMI) system (a system that collects, measures and analyzes energy usage data from advanced digital meters known as smart meters), direct load control, distribution automation and communications infrastructure in its Maryland and District of Columbia service territories. ACE was awarded $19 million from DOE to fund a portion of the costs incurred for the implementation of direct load control, distribution automation and communications infrastructure in its New Jersey service territory. PHI elected to recognize the award proceeds as a reduction in the carrying value of the assets acquired rather than grant income over the service period.

Long-Lived Asset Impairment Evaluation

PHI evaluates long-lived assets to be held and used, such as generating property and equipment, and real estate, for impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. Examples of such events or changes include a significant decrease in the market price of a long-lived asset or a significant adverse change in the manner in which an asset is being used or its physical condition. A long-lived asset to be held and used is written down to its estimated fair value if the expected future undiscounted cash flow from the asset is less than its carrying value.

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For long-lived assets held for sale, an impairment loss is recognized to the extent that the asset’s carrying value exceeds its estimated fair value including costs to sell.

Capitalized Interest and Allowance for Funds Used During Construction

In accordance with FASB guidance on regulated operations (ASC 980), PHI’s utility subsidiaries may capitalize the capital costs of financing the construction of plant and equipment as allowance for funds used during construction (AFUDC). This results in the debt portion of AFUDC being recorded as a reduction of Interest expense and the equity portion of AFUDC being recorded as an increase to Other income in the accompanying consolidated statements of income (loss).

Pepco Holdings recorded AFUDC for borrowed funds of $8 million, $7 million and $7 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Pepco Holdings recorded amounts for the equity component of AFUDC of $14 million, $13 million and $11 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Amortization of Debt Issuance and Reacquisition Costs

Pepco Holdings defers and amortizes debt issuance costs and long-term debt premiums and discounts over the lives of the respective debt issuances. When PHI utility subsidiaries refinance existing debt or redeem existing debt, any unamortized premiums, discounts and debt issuance costs, as well as debt redemption costs, are classified as regulatory assets and are amortized over the life of the original or new issue.

Asset Removal Costs

In accordance with FASB guidance on regulated operations (ASC 980), asset removal costs are recorded by PHI utility subsidiaries as Regulatory liabilities. At December 31, 2015 and 2014, $211 million and $250 million, respectively, of asset removal costs are included in Regulatory liabilities in the accompanying consolidated balance sheets.

Pension and Postretirement Benefit Plans

PHI sponsors a non-contributory, defined benefit pension plan that covers substantially all employees of Pepco, DPL, ACE and certain employees of other PHI subsidiaries (the PHI Retirement Plan). PHI also provides supplemental retirement benefits to certain eligible executives and key employees through nonqualified retirement plans and provides certain postretirement health care and life insurance benefits for eligible retired employees. Most employees hired after January 1, 2005 will not have retiree health care coverage.

Net periodic benefit cost is included in Other operation and maintenance expense, net of the portion of the net periodic benefit cost capitalized as part of the cost of labor for internal construction projects. After intercompany allocations, the three utility subsidiaries are responsible for substantially all of the total PHI net periodic benefit cost.

PHI accounts for the PHI Retirement Plan, the nonqualified retirement plans, and the retirement health care and life insurance benefit plans in accordance with FASB guidance on retirement benefits (ASC 715).

See Note (9), “Pension and Other Postretirement Benefits,” for additional information.

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Reclassifications

Certain prior period amounts have been reclassified in order to conform to the current period presentation.

(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Discontinued Operations (ASC 205)

In April 2014, the FASB issued new guidance on the reporting of discontinued operations that is effective for dispositions that occur after January 1, 2015. In order for dispositions to be presented as discontinued operations, the dispositions must represent a strategic shift that will have a major effect on an entity’s operations and financial results. Adoption of this guidance during the first quarter of 2015 did not have an impact on PHI’s consolidated financial statements.

Business Combinations (ASC 805)

In November 2014, the FASB issued new recognition and disclosure requirements related to pushdown accounting. The new recognition requirements grant an acquired entity (or its subsidiaries) the option to elect whether and when a new accounting and reporting basis (pushdown accounting) will be applied when an acquirer obtains control of the acquired entity. This election may be made by the acquired entity (or its subsidiaries) for future change-in-control events or for its most recent change-in-control event, and the acquired entity will be required to determine whether pushdown accounting will be applied in the reporting period in which the change-in-control event occurs or in a subsequent reporting period.

The new required disclosures include information that enables financial statement users to evaluate the effects of pushdown accounting. Disclosures are required to be made in the period in which pushdown accounting is applied and are expected to include both qualitative and quantitative information.

The new recognition and disclosure requirements became effective on a prospective basis on November 18, 2014. PHI currently anticipates it may be affected by the new guidance if its Merger with Exelon is consummated.

Fair Value Measurement (ASC 820)

In May 2015, the FASB issued new disclosure requirements for investment fair values. Under the new requirements, investment fair values based on net asset value (NAV) per share will continue to be disclosed, however, a level will not be assigned to those investment fair values. The new requirements are effective for PHI beginning January 1, 2016, and are required to be implemented on a retrospective basis for all periods presented; however, early adoption is permitted. PHI has elected to early adopt the new guidance and implement the change in accounting principle in the fourth quarter of 2015. The impact of this guidance effected the presentation of certain investments that use NAV per share as a practical expedient in Note (9), “Pension and Other Postretirement Benefits” and had no impact to Note (15), “Fair Value Disclosure,” as the financial instruments measured at fair value on a recurring basis and other financial instruments are not based on NAV.

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Presentation of Debt Issuance Costs (ASC 835)

In April 2015, the FASB issued new guidance for the presentation of debt issuance costs on the balance sheet. Debt issuance costs are currently required to be presented on the balance sheet as assets. However, under the new requirements, these debt issuance costs will be offset against the debt to which the costs relate. The new requirements are effective for PHI beginning January 1, 2016, and are required to be implemented on a retrospective basis for all periods presented; however, early adoption is permitted. PHI has elected to early adopt the new guidance in the fourth quarter of 2015. The table below illustrates the effects of the retrospective application on reported balances in PHI’s consolidated balance sheet as of December 31, 2014.

	December 31, 2014 As Filed		Reclassification ASC 835			December 31, 2014 As Adjusted
	(millions of dollars)
Other (within other assets)	$	166	$	(45	)	$	121
Long-term debt		4,441		(44	)		4,397
Transition bonds issued by ACE Funding		171		(1	)		170

Balance Sheet Classification of Deferred Taxes (ASC 740)

In November 2015, the FASB issued new requirements for the balance sheet classification of deferred taxes. Entities are currently required to present a current and noncurrent deferred tax balance on the balance sheet. Under the new requirements, deferred taxes will only be presented as noncurrent. The new requirements are effective for PHI beginning January 1, 2017, and may be implemented on either a prospective or retrospective basis; however, early adoption is permitted. PHI has elected to early adopt the new guidance on a retrospective basis in the fourth quarter of 2015. The table below illustrates the effects of the retrospective application on reported balances in PHI’s consolidated balance sheet as of December 31, 2014.

	December 31, 2014 As Filed		Reclassification ASC 740			December 31, 2014 As Adjusted
	(millions of dollars)
Deferred income taxes, net (within current assets)	$	50	$	(50	)	$	—
Deferred income taxes, net (within other assets)		—		17			17
Other (within current liabilities)		314		(9	)		305
Deferred income tax liabilities, net		3,266		(24	)		3,242

(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Revenue from Contracts with Customers (ASC 606)

In May 2014, the FASB issued new recognition and disclosure requirements for revenue from contracts with customers, which supersedes the existing revenue recognition guidance. The new recognition requirements focus on when the customer obtains control of the goods or services, rather than the current risks and rewards model of recognition. The core principle of the new standard is that an entity will recognize revenue when it transfers goods or services to its customers in an amount that reflects the consideration an entity expects to be entitled to for those goods or services. The new disclosure requirements will include information intended to communicate the nature, amount, timing and any uncertainty of revenue and cash flows from applicable contracts, including any significant judgments and changes in judgments and assets recognized from the costs to obtain or fulfill a contract. Entities will generally be required to make more estimates and use more judgment under the new standard.

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The new requirements will be effective for PHI beginning January 1, 2018, and may be implemented either retrospectively for all periods presented, or as a cumulative-effect adjustment as of January 1, 2018. Early adoption is permitted, but not before January 1, 2017. PHI is currently evaluating the potential impact of this new guidance on its consolidated financial statements and which implementation approach to select.

Business Combination (ASC 805)

In September 2015, the FASB issued new guidance on adjustments to provisional amounts recognized in a business combination, which are currently recognized on a retrospective basis. Under the new requirements, adjustments will be recognized in the reporting period in which the adjustments are determined. The effects of changes in depreciation, amortization, or other income arising from changes to the provisional amounts, if any, are included in earnings of the reporting period in which the adjustments to the provisional amounts are determined. An entity is also required to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The new requirements will be effective for PHI beginning January 1, 2016, and are required to be implemented on a prospective basis. Early adoption is permitted. PHI currently anticipates it may be affected by the new guidance if its Merger with Exelon is consummated.

(5) SEGMENT INFORMATION

Pepco Holdings’ management has identified its operating segments at December 31, 2015 as Power Delivery and Pepco Energy Services. In the tables below, the Corporate and Other column is included to reconcile the segment data with consolidated data and includes unallocated Pepco Holdings’ (parent company) capital costs, such as financing costs. During 2013, PHI completed the termination of its interests in its cross-border energy lease investments that had been maintained by PHI through its wholly- owned subsidiary, PCI. As a result, the cross-border energy lease investments, which comprised substantially all of the operations of the former Other Non-Regulated segment, have been accounted for as discontinued operations. The remaining operations of the former Other Non-Regulated segment, which no longer meet the definition of a separate segment for financial reporting purposes, have been included in Corporate and Other. Segment financial information for continuing operations at and for the years ended December 31, 2015, 2014 and 2013, is as follows:

	Year Ended December 31, 2015
	Power Delivery			Pepco Energy Services			Corporate and Other (a)			PHI Consolidated
	(millions of dollars)
Operating Revenue	$	4,805		$	223		$	(5	)	$	5,023
Operating Expenses (b)		4,124	(c)		224			2			4,350
Operating Income (Loss)		681			(1	)		(7	)		673
Interest Expense		238			—			42			280
Other Income		36			1			17	(d)		54
Income Tax Expense (Benefit) (e)		177			(4	)		(44	)		129
Net Income from Continuing Operations		302			4			12			318
Total Assets		14,413			221			1,692			16,326
Construction Expenditures	$	1,196		$	3		$	31		$	1,230

(a) Total Assets in this column includes Pepco Holdings’ goodwill balance of $1.4 billion, all of which is allocated to Power Delivery for purposes of assessing impairment. Total assets also include capital expenditures related to certain hardware and software expenditures which primarily benefit Power Delivery. These expenditures are recorded as incurred in Corporate and Other and are allocated to Power Delivery once the assets are placed in service. Corporate and Other includes intercompany amounts of $(5) million for Operating Revenue, $(4) million for Operating Expenses and $(5) million for Interest Expense.

(b) Includes depreciation and amortization expense of $651 million, consisting of $606 million for Power Delivery, $4 million for Pepco Energy Services and $41 million for Corporate and Other.

(c) Includes $46 million ($27 million after-tax) related to gains on sales of land at Pepco.

(d) Includes $15 million ($10 million after-tax) increase in fair value of preferred stock derivative.

(e) Includes tax benefit of $3 million for Power Delivery, $1 million for Pepco Energy Services and $43 million for Corporate and Other associated with the Global Tax Settlement.

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	Year Ended December 31, 2014
	Power Delivery		Pepco Energy Services			Corporate and Other (a)			PHI Consolidated
	(millions of dollars)
Operating Revenue	$	4,607	$	278		$	(7	)	$	4,878
Operating Expenses (b)		3,916		354	(c)		4			4,274
Operating Income (Loss)		691		(76	)		(11	)		604
Interest Expense		226		1			41			268
Other Income		40		2			2			44
Income Tax Expense (Benefit)		185		(36	)		(11	)		138
Net Income (Loss) from Continuing Operations		320		(39	)		(39	)		242
Total Assets		13,636		249			1,704			15,589
Construction Expenditures	$	1,144	$	3		$	76		$	1,223

(a) Total Assets in this column includes Pepco Holdings’ goodwill balance of $1.4 billion, all of which is allocated to Power Delivery for purposes of assessing impairment. Total assets also include capital expenditures related to certain hardware and software expenditures which primarily benefit Power Delivery. These expenditures are recorded as incurred in Corporate and Other and are allocated to Power Delivery once the assets are placed in service. Corporate and Other includes intercompany amounts of $(7) million for Operating Revenue, $(7) million for Operating Expenses and $(4) million for Interest Expense.

(b) Includes depreciation and amortization expense of $549 million, consisting of $511 million for Power Delivery, $7 million for Pepco Energy Services and $31 million for Corporate and Other.

(c) Includes impairment losses of $81 million ($48 million after-tax) associated with Pepco Energy Services’ combined heat and power thermal generating facilities and operations in Atlantic City.

	Year Ended December 31, 2013
	Power Delivery		Pepco Energy Services			Corporate and Other (a)			PHI Consolidated
	(millions of dollars)
Operating Revenue	$	4,472	$	203		$	(9	)	$	4,666
Operating Expenses (b)		3,828		201	(c)		(31	)		3,998
Operating Income		644		2			22			668
Interest Expense		228		1			44			273
Other Income		28		3			3			34
Income Tax Expense (d)		155		1			163	(e)		319
Net Income (Loss) from Continuing Operations		289		3			(182	)		110
Total Assets		12,868		337			1,573			14,778
Construction Expenditures	$	1,194	$	4		$	112		$	1,310

(a) Total Assets in this column includes Pepco Holdings’ goodwill balance of $1.4 billion, all of which is allocated to Power Delivery for purposes of assessing impairment. Total assets also include capital expenditures related to certain hardware and software expenditures which primarily benefit Power Delivery. These expenditures are recorded as incurred in Corporate and Other and are allocated to Power Delivery once the assets are placed in service. Corporate and Other includes intercompany amounts of $(10) million for Operating Revenue, $(9) million for Operating Expenses and $(5) million for Interest Expense.

(b) Includes depreciation and amortization expense of $473 million, consisting of $439 million for Power Delivery, $6 million for Pepco Energy Services and $28 million for Corporate and Other.

(c) Includes impairment losses of $4 million ($3 million after-tax) associated with Pepco Energy Services’ landfill gas-fired electric generation facility.

(d) Includes after-tax interest associated with uncertain and effectively settled tax positions allocated to each member of the consolidated group, including a $12 million interest benefit for Power Delivery and interest expense of $66 million for Corporate and Other.

(e) Includes non-cash charges of $101 million representing the establishment of valuation allowances against certain deferred tax assets of PCI included in Corporate and Other.

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(6) GOODWILL

Substantially all of PHI’s goodwill balance as of December 31, 2015 and 2014 was generated by Pepco’s acquisition of Conectiv (now Conectiv, LLC, to be referred to herein as Conectiv) in 2002 and is allocated entirely to the Power Delivery reporting unit based on the aggregation of its regulated public utility company components for purposes of assessing impairment under FASB guidance on goodwill and other intangibles (ASC 350).

PHI performs an annual impairment assessment as of November 1 each year, or more frequently if indicators of potential impairment exist, to determine whether it is more likely than not that the fair value of a reporting unit to which goodwill relates is less than its carrying value. In evaluating goodwill for impairment, PHI first assesses qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. For reporting units in which PHI concludes that it is more likely than not that the fair value is more than its carrying value, goodwill is not considered impaired and PHI is not required to perform the two-step goodwill impairment test. Qualitative factors considered in this assessment include industry and market considerations, including the price per share of PHI common stock, overall financial performance, lack of significant changes in any key inputs to the prior year impairment test, including the discount rate and forecasted cash flows, and other relevant events and factors affecting the reporting unit.

For reporting units in which PHI concludes that it is more likely than not that the fair value is less than its carrying value, PHI performs the first step of the goodwill impairment test, which compares the fair value of the reporting unit to its carrying value. If the fair value of the reporting unit exceeds the carrying value of the net assets assigned to that unit, goodwill is not considered impaired and PHI is not required to perform additional testing. If the carrying value of the net assets assigned to the reporting unit exceeds the fair value of the reporting unit, then PHI must perform the second step of the goodwill impairment test to determine the implied fair value of the reporting unit’s goodwill. If PHI determines during this second step that the carrying value of a reporting unit’s goodwill exceeds its implied fair value, PHI records an impairment loss equal to the difference.

For the annual impairment assessment in 2015, PHI qualitatively determined for its Power Delivery reporting unit that it was more likely than not that fair value exceeded carrying value. As a result, PHI did not perform the two-step goodwill impairment test on the Power Delivery reporting unit.

As of December 31, 2015 and 2014, PHI’s goodwill balance was $1,406 million and $1,407 million, respectively, which is net of accumulated impairment losses of $12 million and $18 million, respectively.

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(7) REGULATORY MATTERS

Regulatory Assets and Regulatory Liabilities

The components of Pepco Holdings’ regulatory asset and liability balances at December 31, 2015 and 2014 are as follows:

	2015		2014
	(millions of dollars)
Regulatory Assets
Pension and other postretirement benefit costs	$	910	$	946
Demand-side management costs		403		329
Smart Grid costs		266		261
Recoverable income taxes		224		274
Securitized stranded costs		202		278
Incremental storm restoration costs		43		51
Deferred debt extinguishment costs		36		42
Deferred energy supply costs		32		73
Recoverable workers’ compensation and long-term disability costs		31		30
MAPP abandonment costs		7		33
Deferred losses on gas derivatives		2		4
Other		90		88
Total Regulatory Assets	$	2,246	$	2,409
Regulatory Liabilities
Asset removal costs	$	211	$	250
Reserves for FERC ROE transmission challenges		32		4
Federal and state tax benefits, related to securitized stranded costs		13		8
Deferred income taxes due to customers		12		44
Deferred energy supply costs		11		3
Other		29		34
Total Regulatory Liabilities	$	308	$	343

A description for each category of regulatory assets and regulatory liabilities follows:

Pension and OPEB Costs: Represents unrecognized net actuarial losses and prior service cost (credit) for Pepco Holdings’ defined benefit pension and other postretirement benefit (OPEB) plans that are expected to be recovered by Pepco, DPL and ACE in rates. The utilities have historically included these items as a part of its cost of service in its customer rates. This regulatory asset is adjusted at least annually when the funded status of Pepco Holdings’ defined benefit pension and OPEB plans are re-measured. See Note (9), “Pension and Other Postretirement Benefits,” for more information about the components of the unrecognized pension and OPEB costs. PHI does not earn a return on these regulatory assets.

Demand-Side Management Costs: Represents recoverable costs associated with customer direct load control and energy efficiency and conservation programs in all jurisdictions that are being recovered from customers. These programs are designed to reduce customers’ energy consumption. PHI earns a return on these regulatory assets.

Smart Grid Costs: Represents AMI costs associated with the installation of smart meters and the early retirement of legacy meters throughout Pepco’s and DPL’s service territories that are recoverable from customers. AMI has not been approved by the NJBPU for ACE in New Jersey. PHI generally is deferring carrying charges on these regulatory assets.

Recoverable Income Taxes: Represents amounts recoverable from Power Delivery’s customers for tax benefits applicable to utility operations of Pepco, DPL and ACE previously recognized in income tax

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expense before the companies were ordered to record the tax benefits as deferred income taxes. As the temporary differences between the financial statement basis and tax basis of assets reverse, the deferred recoverable balances are reversed.

Securitized Stranded Costs: Certain contract termination payments under a contract between ACE and an unaffiliated non-utility generator (NUG) and costs associated with the regulated operations of ACE’s electricity generation business are no longer recoverable through customer rates (collectively referred to as “stranded costs”). The stranded costs are amortized over the life of Transition Bonds issued by Atlantic City Electric Transition Funding LLC (ACE Funding) (Transition Bonds) to securitize the recoverability of these stranded costs. These bonds mature between 2016 and 2023. A customer surcharge is collected by ACE to fund principal and interest payments on the Transition Bonds. PHI earns a return on these regulatory assets.

Incremental Storm Restoration Costs: Represents total incremental storm restoration costs incurred for repair work due to major storm events in 2015, 2012 and 2011, including the June 2015 storm (for DPL and ACE), Hurricane Sandy, the June 2012 derecho, Hurricane Irene and the 2011 severe winter storm (for Pepco), that are recoverable from customers in the Maryland and New Jersey jurisdictions. Pepco’s and DPL’s costs related to Hurricane Sandy, the June 2012 derecho, Hurricane Irene and Pepco’s costs related to the 2011 severe winter storm are being amortized and recovered from customers, each over a five-year period. ACE’s costs related to Hurricane Sandy, the June 2012 derecho and Hurricane Irene are being amortized and recovered from customers, each over a three-year period. PHI does not earn a return on these regulatory assets.

Deferred Debt Extinguishment Costs: Represents deferred costs of debt extinguishment of Pepco, DPL and ACE that are amortized to interest expense and recovered from customers. PHI generally earns a return on these regulatory assets.

Deferred Energy Supply Costs: The regulatory asset represents primarily deferred costs associated with a net under-recovery of Default Electricity Supply costs incurred by Pepco, DPL and ACE that are being or are expected to be recovered from customers. PHI generally earns a return on these regulatory assets. The regulatory liability represents primarily deferred costs associated with a net over-recovery of Default Electricity Supply costs incurred that will be refunded by Pepco, DPL and ACE to customers.

Recoverable Workers’ Compensation and Long-Term Disability Costs: Represents accrued workers’ compensation and long-term disability costs for Pepco, which are recoverable from customers when actual claims are paid to employees. PHI does not earn a return on these regulatory assets.

MAPP Abandonment Costs: Represents abandonment costs incurred in connection with the Mid-Atlantic Power Pathway (MAPP) transmission line construction project which was terminated by PJM Interconnection, LLC (PJM) on August 24, 2012. These regulatory assets are being amortized and recovered in transmission rates through May 2016. PHI generally does not earn a return on these regulatory assets.

Deferred Losses on Gas Derivatives: Represents losses associated with hedges of natural gas purchases that are recoverable from customers through the Gas Cost Rate (GCR) approved by the DPSC. PHI does not earn a return on these regulatory assets.

Other: Represents miscellaneous regulatory assets that generally are being amortized over 1 to 20 years.

Asset Removal Costs: The depreciation rates for Pepco and DPL include a component for removal costs, as approved by the relevant federal and state regulatory commissions. Accordingly, Pepco and DPL have recorded regulatory liabilities for their estimate of the difference between incurred removal costs and the amount of removal costs recovered through depreciation rates.

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Reserves for FERC ROE Transmission Challenges: Represents reserves established under a settlement agreement filed with FERC for the resolution of certain challenges filed by a group of complainants of the base return on equity (ROE) currently authorized by FERC for the transmission service that PHI’s utilities provide.

Federal and State Tax Benefits, Related to Securitized Stranded Costs: Securitized stranded costs include a portion attributable to the future tax benefit expected to be realized when the higher tax basis of the generating facilities divested by ACE is deducted for New Jersey state income tax purposes, as well as the future benefit to be realized through the reversal of federal excess deferred taxes. To account for the possibility that these tax benefits may be given to ACE’s customers through lower rates in the future, ACE established a regulatory liability. The regulatory liability related to federal excess deferred taxes will remain until such time as the Internal Revenue Service (IRS) issues its final regulations with respect to normalization of these federal excess deferred taxes.

Deferred Income Taxes Due to Customers: Represents the portions of deferred income tax assets applicable to utility operations of Pepco and DPL that have not been reflected in current customer rates for which future payment to customers is probable. As the temporary differences between the financial statement basis and tax basis of assets reverse, deferred recoverable income taxes are amortized.

Other: Represents miscellaneous regulatory liabilities.

Rate Proceedings

As further described in Note (1), “Organization,” on April 29, 2014, PHI entered into the Merger Agreement with Exelon and Merger Sub. Subject to certain exceptions, prior to the Merger or the termination of the Merger Agreement, PHI and its subsidiaries may not, without the consent of Exelon, initiate, file or pursue any rate cases, other than pursuing the conclusion of certain proceedings, as described below. To date, PHI has not requested such consent from Exelon and has not filed any new distribution base rate cases since entering into the Merger Agreement.

Bill Stabilization Adjustment

Each of PHI’s utility subsidiaries proposed in each of its respective jurisdictions the adoption of a mechanism to decouple retail distribution revenue from the amount of power delivered to retail customers. A decoupling mechanism, the BSA, was approved and implemented for Pepco and DPL electric service in Maryland and for Pepco electric service in the District of Columbia. None of the other jurisdictions have to date adopted decoupling proposals.

Delaware

Electric Distribution Base Rates

In March 2013, DPL submitted an application with the DPSC to increase its electric distribution base rates. The application sought approval of an annual rate increase of approximately $42 million (adjusted by DPL to approximately $39 million on September 20, 2013), based on a requested ROE of 10.25%. The requested rate increase sought to recover expenses associated with DPL’s ongoing investments in reliability enhancement improvements and efforts to maintain safe and reliable service. In August 2014, the DPSC issued a final order in this proceeding providing for an annual increase in DPL’s electric distribution base rates of approximately $15.1 million, based on an ROE of 9.70%. The new rates became effective on May 1, 2014.

In September 2014, DPL filed an appeal with the Delaware Superior Court of the DPSC’s August 2014 order in this proceeding, seeking the court’s review of the DPSC’s decision relating to the recovery of costs associated with one component of employee compensation, certain retirement benefits and credit facility expenses. The Division of the Public Advocate filed a cross-appeal in September 2014, pertaining

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to the treatment of a prepaid pension expense and other postretirement benefit obligations in base rates. Under the settlement agreement related to the Merger described below in “Merger Approval Proceedings – Delaware,” the parties agreed to suspend the appeal and, if the Merger is completed, to the withdrawal of the appeal and the cross-appeal with prejudice.

Forward Looking Rate Plan

In October 2013, DPL filed a multi-year rate plan, referred to as the Forward Looking Rate Plan (FLRP). As proposed, the FLRP would provide for annual electric distribution base rate increases over a four-year period in the aggregate amount of approximately $56 million. The FLRP as proposed provides the opportunity to achieve estimated earned ROEs of 7.41% and 8.80% in years one and two, respectively, and 9.75% in both years three and four of the plan.

In addition, DPL proposed that as part of the FLRP, in order to provide a higher minimum required standard of reliability for DPL’s customers than that to which DPL is currently subject, the standards by which DPL’s reliability is measured would be made more stringent in each year of the FLRP. DPL has also offered to refund an aggregate of $500,000 to customers in each year of the FLRP that it fails to meet the proposed stricter minimum reliability standards.

In October 2013, the DPSC opened a docket for the purpose of reviewing the details of the FLRP, but stated that it would not address the FLRP until the electric distribution base rate case discussed above was concluded. Although the rate case has been concluded, a schedule for the FLRP docket has not yet been established.

Under the Merger Agreement, DPL is permitted to pursue this matter; however, under the settlement agreement related to the Merger described below in “Merger Approval Proceedings – Delaware,” DPL agreed to withdraw the FLRP if the Merger is completed, without prejudice to the right to make future filings with the DPSC proposing alternative regulatory methodologies that could include, but are not limited to, a multi-year rate plan.

Gas Cost Rates

DPL makes an annual GCR filing with the DPSC for the purpose of allowing DPL to recover natural gas procurement costs through customer rates. In August 2015, DPL made its 2015 GCR filing. The rates proposed in the 2015 GCR filing would result in a GCR decrease of approximately 26%, primarily reflecting lower natural gas prices. On September 22, 2015, the DPSC issued an order allowing DPL to place the new rates into effect on November 1, 2015, subject to refund and pending final DPSC approval.

Under the Merger Agreement, DPL is permitted to continue to file its required annual GCR cases in Delaware.

Maryland

Pepco Electric Distribution Base Rates

2011 Base Rate Proceeding

In December 2011, Pepco submitted an application with the MPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $68.4 million (subsequently adjusted by Pepco to approximately $66.2 million), based on a requested ROE of 10.75%. In July 2012, the MPSC issued an order approving an annual rate increase of approximately $18.1 million, based on an ROE of 9.31%. Among other things, the order also authorized Pepco to recover the actual cost of AMI meters installed during the 2011 test year, stating that cost recovery for AMI deployment will be allowed in future rate cases in which Pepco demonstrates that the system is cost effective. The new rates became effective on July 20, 2012. The Maryland Office of People’s Counsel has sought rehearing on the portion of the order allowing Pepco to recover the costs of AMI meters installed during the test year; that motion remains pending.

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2012 Base Rate Proceeding – Phase I

In November 2012, Pepco submitted an application with the MPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $60.8 million, based on a requested ROE of 10.25%. In July 2013, the MPSC issued an order in this proceeding approving an annual rate increase of approximately $27.9 million, based on an ROE of 9.36%. The order excludes the cost of AMI meters from Pepco’s rate base until such time as Pepco demonstrates the cost effectiveness of the AMI system; as a result, costs for AMI meters incurred with respect to the 2012 test year and beyond will be treated as other incremental AMI costs incurred in conjunction with the deployment of the AMI system that are deferred and on which a carrying charge is deferred, but only until such cost effectiveness has been demonstrated and such costs are included in rates. However, MPSC’s July 2012 order issued in connection with Pepco’s 2011 base rate proceeding, which allowed Pepco to recover the costs of meters installed during the 2011 test year for that case, remains in effect.

The July 2013 order also approved a Grid Resiliency Charge, which went into effect on January 1, 2014, for recovery of costs totaling approximately $24.0 million associated with Pepco’s proposed plan to accelerate investments related to certain priority feeders, provided that, before implementing the surcharge, Pepco (i) provides additional information to the MPSC related to performance objectives, milestones and costs, and (ii) makes annual filings with the MPSC thereafter concerning this project, which will permit the MPSC to establish the applicable Grid Resiliency Charge rider for each following year. These conditions have been met. The MPSC rejected certain other cost recovery mechanisms, including Pepco’s proposed reliability performance-based mechanism. The new rates were effective on July 12, 2013.

In July 2013, Pepco filed a notice of appeal of the July 2013 order in the Circuit Court for Baltimore City. Other parties also filed notices of appeal, which were consolidated with Pepco’s appeal. In its appeal, Pepco asserted that the MPSC erred in failing to grant Pepco an adequate ROE, denying a number of other cost recovery mechanisms and limiting Pepco’s test year data to no more than four months of forecasted data in future rate cases. The other parties primarily asserted that the MPSC erred or acted arbitrarily and capriciously in allowing the recovery of certain costs by Pepco, in approving the Grid Resiliency Charge, and in refusing to reduce Pepco’s rate base by known and measurable accumulated depreciation. In November 2014, the Circuit Court issued an order reversing the MPSC’s decision on Pepco’s ROE and directing the MPSC to make more specific findings regarding the impact of improved service reliability and the BSA in calculating Pepco’s ROE. On all other issues that were the subject of an appeal, the Circuit Court affirmed the MPSC’s July 2013 order.

Other parties to this proceeding filed notices of appeal of the Circuit Court’s decision to the Maryland Court of Special Appeals. On December 15, 2015, the Court of Special Appeals issued its decision in this matter (i) affirming the Circuit Court’s decision upholding the MPSC’s decision to approve the use of the Grid Resiliency Charge for Pepco, and (ii) reversing the Circuit Court on the ROE issue, finding that the MPSC’s original ROE of 9.36% was within the zone of reasonableness. Because none of the parties to the proceeding, including Pepco, appealed this Court of Special Appeals decision, the MPSC decision is now final.

2013 Base Rate Proceeding – Phase I

In December 2013, Pepco submitted an application with the MPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $43.3 million (adjusted by Pepco to approximately $37.4 million on April 15, 2014), based on a requested ROE of 10.25%. The requested rate increase sought to recover expenses associated with Pepco’s ongoing investments in reliability enhancement improvements and efforts to maintain safe and reliable service. In July 2014, the

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MPSC issued an order approving an annual rate increase of approximately $8.75 million, based on an ROE of 9.62%. The new rates became effective on July 4, 2014. In July 2014, Pepco filed a petition for rehearing seeking reconsideration of the recovery of certain expenses, which the MPSC denied by its order issued in November 2014 (described below). In December 2014, Pepco filed a petition for judicial review of this MPSC order with the Circuit Court for Baltimore City. On August 7, 2015, the Circuit Court for Baltimore City affirmed the MPSC’s decision and denied Pepco’s appeal. Pepco has elected not to appeal the decision of the Circuit Court.

2012 and 2013 Base Rate Proceedings – Phase II

In August 2014, the MPSC issued an order establishing a Phase II proceeding in the 2012 base rate case described above (the 2012 Phase II proceeding) to address the tax implications of Pepco’s net operating loss carryforward (NOLC), which had impacted certain of Pepco’s rate adjustments in the 2012 base rate proceeding. Pepco filed a motion to dismiss the 2012 Phase II proceeding, asserting that the MPSC no longer has jurisdiction over the 2012 base rate case due to appeals having been filed by numerous parties. In September 2014, the MPSC issued an order staying the 2012 Phase II proceeding until further notice. In a similar Phase II proceeding in the 2013 base rate case described above, the MPSC issued an order in November 2014 upholding Pepco’s treatment of the NOLC. Although Pepco believes the November 2014 MPSC order should be dispositive of the issues raised in the 2012 Phase II proceeding, the 2012 Phase II proceeding has remained open pending the resolution of all appeals of the 2012 base rate proceeding. Now that the MPSC decision in that proceeding is final, the MPSC will have authority to act on Phase II.

New Jersey

Update and Reconciliation of Certain Under-Recovered Balances

In March 2015, ACE submitted its 2015 annual petition with the NJBPU seeking to reconcile and update (i) charges related to the recovery of above-market costs associated with ACE’s long-term power purchase contracts with the NUGs, and (ii) costs related to surcharges for the New Jersey Societal Benefit Program (a statewide public interest program that is intended to benefit low income customers and address other public policy goals) and for ACE’s uncollected accounts. As filed, the net impact of the proposed changes would have been an annual rate increase of approximately $52.0 million (revised to an increase of approximately $33.9 million on April 17, 2015, based upon updates for actual data through March 31, 2015). On May 19, 2015, the NJBPU approved a stipulation of settlement entered into by the parties providing for a provisional overall annual rate increase of $33.9 million effective June 1, 2015. On September 11, 2015, the NJBPU approved a stipulation of settlement in this proceeding, which made final the provisional rates that were placed into effect as of June 1, 2015, with an adjustment that decreased the rate applicable to the residential class by $1.3 million. This rate increase of approximately $32.6 million will have no effect on ACE’s operating income, since these revenues provide for recovery of deferred costs under an approved deferral mechanism.

On February 1, 2016, ACE submitted its 2016 annual petition with the NJBPU seeking to reconcile and update the same categories of charges and costs described in (i) and (ii) in the above paragraph. The net impact of adjusting the charges as proposed is an overall annual rate increase of approximately $8.8 million, including New Jersey Sales and Use Tax. The matter is pending at the NJBPU and will be updated for January through March 2016 actual data. ACE has requested that the NJBPU place the new rates into effect by June 1, 2016.

Service Extension Contributions Refund Order

In July 2013, in compliance with a 2012 Superior Court of New Jersey Appellate Division (Appellate Division) court decision, the NJBPU released an order requiring utilities to issue refunds to persons or entities that paid non-refundable contributions for utility service extensions to certain areas described as “Areas Not Designated for Growth.” The order is limited to eligible contributions paid between March 20, 2005 and December 20, 2009. ACE is processing the refund requests that meet the eligibility criteria

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established in the order as they are received. Although ACE estimates that it received approximately $11 million of contributions between March 20, 2005 and December 20, 2009, it is currently unable to reasonably estimate the amount that it may be required to refund using the eligibility criteria established by the order. Since the July 2013 order was released, ACE has paid less than $1 million in refund claims, the validity of each of which is investigated by ACE prior to making any such refunds. In September 2014, the NJBPU commenced a rulemaking proceeding to further implement the directives of the Appellate Division decision. In November 2015, the NJBPU adopted new regulations that remove provisions distinguishing between growth areas and not-for-growth areas and provide formulae for allocating extension costs. At this time, ACE does not expect the amount it is ultimately required to refund will have a material effect on its consolidated financial condition, results of operations or cash flows, as the amount refunded will generally increase the value of ACE’s property, plant and equipment and may ultimately be recovered through depreciation expense and cost of service in future electric distribution base rate cases.

Generic Consolidated Tax Adjustment Proceeding

In January 2013, the NJBPU initiated a generic proceeding to examine whether a consolidated tax adjustment (CTA) should continue to be used, and if so, how it should be calculated in determining a utility’s cost of service. Under the NJBPU’s current policy, when a New Jersey utility is included in a consolidated group income tax return, an allocated amount of any reduction in the consolidated group’s taxes as a result of losses by affiliates is used to reduce the utility’s rate base, upon which the utility earns a return. This policy has negatively impacted ACE’s electric distribution base rate case outcomes and ACE’s position is that the CTA should be eliminated. In an order issued in October 2014, the NJBPU determined that it is appropriate for affected consolidated groups to continue to include a CTA in New Jersey base rate filings, but that the CTA calculation will be modified to limit the look-back period for the calculation to five years, exclude transmission assets from the calculation, and allocate 25 percent of the final CTA amount as a reduction to the distribution revenue requirement. ACE anticipates that this revised methodology will significantly reduce the negative effects of the CTA in future base rate cases. In November 2014, the New Jersey Division of Rate Counsel filed an appeal of the NJBPU’s CTA order in the Appellate Division. No stay of the October 2014 CTA order was requested in connection with the appeal. As such, barring an adverse finding by the Appellate Division, the order is in effect. The appeal remains pending.

FERC Transmission ROE Challenges

In February 2013, the public service commissions and public advocates of the District of Columbia, Maryland, Delaware and New Jersey, as well as the Delaware Municipal Electric Corporation, Inc., filed a joint complaint at FERC against Pepco, DPL and ACE, as well as Baltimore Gas and Electric Company (BGE). The complainants challenged the base ROE and certain protocols regarding the formula rate process associated with the transmission service that the utilities provide. The complainants support an ROE within a zone of reasonableness of 6.78% and 10.33%, and have argued for a base ROE of 8.7%. The base ROE currently authorized by FERC for PHI’s utilities is (i) 11.3% for facilities placed into service after January 1, 2006, and (ii) 10.8% for facilities placed into service prior to 2006. The 10.8% base ROE for facilities placed into service prior to 2006 receives a 50-basis-point incentive adder for being a member of a regional transmission organization. In August 2014, FERC issued an order setting the matters in this proceeding for hearing, but holding the hearing in abeyance pending settlement discussions. The order also (i) directed that the evidence and analysis presented concerning ROE be guided by the new ROE methodology adopted by FERC in another proceeding (discussed below), and (ii) set a 15-month refund period that commenced on February 27, 2013, should a refund result from this proceeding. After settlement discussions among the parties in this matter reached an impasse, the settlement judge, in November 2014, issued an order terminating the settlement discussions and referring the matter to a presiding administrative law judge.

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In June 2014, FERC issued an order in a proceeding in which the PHI utilities were not involved, in which it adopted a new ROE methodology for electric utilities. This new methodology replaces the existing one-step discounted cash flow analysis (which incorporates only short-term growth rates) traditionally used to derive ROE for electric utilities with the two-step discounted cash flow analysis (which incorporates both short-term and long-term measures of growth) used for natural gas and oil pipelines. As a result of the August 2014 FERC order discussed in the preceding paragraph, Pepco, DPL and ACE applied an estimated ROE based on the two-step methodology announced by FERC for the 15-month period over which each of their transmission revenues would be subject to refund as a result of the challenge, and recorded estimated reserves for the entire 15-month refund period in the second quarter of 2014.

On December 8, 2014, the parties that filed the February 2013 complaint filed a second complaint against Pepco, DPL, ACE, as well as BGE, regarding the base transmission ROE, seeking a reduction from 10.8% to 8.8%. By order issued on February 9, 2015, FERC established a hearing on the second complaint and established a second 15-month refund period that commenced on December 8, 2014. Consistent with the prior challenge, Pepco, DPL and ACE applied an estimated ROE based on the two-step methodology described above, and in the fourth quarter of 2014 and in the first, second and third quarters of 2015 established reserves for the estimated refund based on the effective date of the second refund period of December 8, 2014. On February 20, 2015, the chief judge issued an order consolidating the two complaint proceedings and established an initial decision issuance deadline of February 29, 2016. On March 2, 2015, the presiding administrative law judge issued an order establishing a procedural schedule for the consolidated proceedings that provided for the hearing to commence on October 20, 2015.

Also during the third quarter of 2015, PHI further evaluated the reserves established for each of the two refund periods and, based on an updated assessment of market conditions, developments in other cases before FERC, litigation risk and other factors, increased its reserves to reflect management’s best estimate of the refund that is expected to result from these consolidated proceedings. A settlement entered into by the parties regarding the protocols (but not the ROE) raised in the February 2013 complaint was submitted to FERC on July 31, 2015 and was approved by FERC in November 2015.

On November 6, 2015, the parties filed a settlement agreement with FERC regarding the ROE. This settlement agreement provides for (i) a base ROE of 10.0%, effective March 8, 2016, to which a 50-basis-point incentive adder will be applied for being a member of a regional transmission organization, and (ii) customer refunds in the amount of approximately $9.5 million, $11.9 million, and $14.2 million for ACE, DPL and Pepco, respectively, covering the two 15-month refund periods described above. In addition, under this settlement agreement, no party may file to change the base ROE or any incentives prior to June 1, 2018. The parties have requested that FERC approve this settlement agreement by March 16, 2016, in order to incorporate the new ROE and applicable refunds into each utility’s 2016 transmission formula rate update. As of December 31, 2015, PHI’s reserves for both of the refund periods totaled $32 million as required under the settlement agreement.

MPSC New Generation Contract Requirement

In April 2012, the MPSC issued an order that requires Maryland electric distribution companies (EDCs) Pepco, DPL and BGE (collectively, the Contract EDCs) to negotiate and enter into a contract with the winning bidder of a competitive bidding process to build one new power plant in the range of 650 to 700 megawatts (MWs) beginning in 2015, in amounts proportional to their relative SOS loads. Under the terms of the order, the winning bidder was to construct a 661 MW natural gas-fired combined cycle generation plant in Waldorf, Maryland, with an originally expected commercial operation date of June 1, 2015 (which is now deferred pending the outcome of the proceedings discussed below), and each of the Contract EDCs was to recover its costs associated with the contract through surcharges on its respective SOS customers.

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In response to a complaint filed by a group of generating companies in the PJM region, in September 2013, the U.S. District Court for the District of Maryland (the Federal District Court) issued a ruling that the MPSC’s April 2012 order violated the Supremacy Clause of the U.S. Constitution by attempting to regulate wholesale prices. In contrast, in October 2013, in response to appeals filed by the Contract EDCs and other parties, the Maryland Circuit Court for Baltimore City (the Maryland Circuit Court) upheld the MPSC’s orders requiring the Contract EDCs to enter into the contracts.

In October 2013, the Federal District Court issued an order ruling that the contracts are illegal and unenforceable. The Contract EDCs, the Maryland Office of People’s Counsel and one generating company have appealed the Maryland Circuit Court’s decision to the Maryland Court of Special Appeals. In addition, in November 2013 both the winning bidder and the MPSC appealed the Federal District Court decision to the U.S. Court of Appeals for the Fourth Circuit, which affirmed the decision. In November 2014, the winning bidder and the MPSC each petitioned the U.S. Supreme Court to consider hearing an appeal of the Fourth Circuit decision and, on October 19, 2015, the U.S. Supreme Court agreed to review that decision.

Assuming the contracts, as currently written, become effective following the satisfaction of all relevant conditions, including the completion of the proceedings discussed above, PHI continues to believe that Pepco and DPL may be required to record their proportional share of the contracts as derivative instruments at fair value and record related regulatory assets of approximately the same amount because Pepco and DPL would be entitled to recover any payments under the contracts from SOS customers. PHI, Pepco and DPL have concluded that any accounting for these contracts would not be required until all legal proceedings related to these contracts and the actions of the MPSC in the related proceeding have been resolved.

ACE Standard Offer Capacity Agreements

In April 2011, ACE entered into three Standard Offer Capacity Agreements (SOCAs) by order of the NJBPU, each with a different generation company. ACE entered into the SOCAs under protest, as did the other EDCs in New Jersey, arguing that the EDCs were denied due process and that the SOCAs violated certain of the requirements of the New Jersey law under which the SOCAs were established (the NJ SOCA Law). In October 2013, in light of the decision of the U.S. District Court for the District of New Jersey described below, the state appeals of the NJBPU implementation orders filed by the EDCs and generators were dismissed without prejudice, subject to the parties exercising their appellate rights in the Federal courts.

In February 2011, ACE joined other plaintiffs in an action filed in the U.S. District Court for the District of New Jersey challenging the NJ SOCA Law on the grounds that it violates the Commerce Clause and the Supremacy Clause of the U.S. Constitution. In October 2013, the Federal district court ruled that the NJ SOCA Law is preempted by the Federal Power Act (FPA) and violates the Supremacy Clause, and is therefore null and void. In October 2013, the Federal district court issued an order ruling that the SOCAs are void, invalid and unenforceable, which order was affirmed by the U.S. Court of Appeals for the Third Circuit in September 2014. In November 2014 and December 2014, respectively, one of the generation companies and the NJBPU petitioned the U.S. Supreme Court to consider hearing an appeal of the Third Circuit decision. Although the U.S. Supreme Court agreed to review the Fourth Circuit decision discussed above under “MPSC New Generation Contract Requirement,” it has not yet agreed to review the Third Circuit decision and the petitions for such review remain pending.

ACE terminated one of the three SOCAs effective July 1, 2013 due to the occurrence of an event of default on the part of the generation company counterparty. ACE terminated the remaining two SOCAs effective November 19, 2013, in response to the October 2013 Federal district court decision.

In response to the October 2013 Federal district court order, ACE, in the fourth quarter of 2013, derecognized both the derivative assets (liabilities) for the estimated fair value of the SOCAs and the related regulatory liabilities (assets) that it had established with respect to the SOCAs.

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District of Columbia Power Line Undergrounding Initiative

In May 2014, the Council of the District of Columbia enacted the Electric Company Infrastructure Improvement Financing Act of 2014 (the Improvement Financing Act), which provides enabling legislation for the District of Columbia Power Line Undergrounding (DC PLUG) initiative. This $1 billion initiative seeks to selectively place underground some of the District of Columbia’s most outage-prone power lines, which lines and surrounding conduit would be owned and maintained by Pepco.

The Improvement Financing Act provides that: (i) Pepco is to fund approximately $500 million of the estimated cost to complete the DC PLUG initiative, recovering those costs through a surcharge on the electric bills of Pepco District of Columbia customers; (ii) $375 million of the DC PLUG initiative cost is to be financed by the District of Columbia’s issuance of securitized bonds, which bonds will be repaid through a surcharge on the electric bills of Pepco District of Columbia customers that Pepco will collect on behalf of and remit to the District of Columbia; and (iii) the remaining costs up to $125 million are to be covered by the existing capital projects program of the District of Columbia Department of Transportation (DDOT). Pepco will not earn a return on or a return of the cost of the assets funded with the proceeds of the securitized bonds or assets that are constructed by DDOT under its capital projects program, but ownership and responsibility for the operation and maintenance of such assets will be transferred to Pepco for a nominal amount.

In June 2014, Pepco and DDOT filed a Triennial Plan related to the construction of selected underground feeders in the District of Columbia and recovery of Pepco’s investment through a volumetric surcharge (the Triennial Plan), all in accordance with the Improvement Financing Act. In August 2014, Pepco filed an application for the issuance of a financing order to provide for the issuance of the District’s bonds and a volumetric surcharge for the District of Columbia to recover the costs associated with the bond issuance (the DDOT surcharge).

In November 2014, the DCPSC issued an order approving the Triennial Plan, including Pepco’s volumetric surcharge, and issued the financing order, including approval of the DDOT surcharge. Together these orders permit (i) Pepco and DDOT to commence proposed construction under the Triennial Plan; (ii) the District of Columbia to issue the necessary bonds to fund the District of Columbia’s portion of the DC PLUG initiative; and (iii) the establishment of the customer surcharges contemplated by the Improvement Financing Act. In December 2014, a party to the proceeding sought reconsideration from the DCPSC of both decisions. Final decisions denying both requests for reconsideration were issued by the DCPSC on January 22, 2015 and February 2, 2015, respectively.

In March 2015, a party to the DCPSC proceedings filed with the District of Columbia Court of Appeals a petition for review of the order approving the Triennial Plan and the issuance of the financing order. On January 14, 2016, the District of Columbia Court of Appeals affirmed the orders of the DCPSC. On January 27, 2016, the original petitioning party sought rehearing of the District of Columbia Court of Appeals decision. A determination whether the Court of Appeals will rehear the case is still pending.

Separately, in June 2015, an agency of the federal government served by Pepco asserted that the DDOT surcharge constitutes a tax on end users from which the federal government is immune. PHI is currently evaluating the assertion and the resolution of this matter will likely delay implementation of the DC PLUG initiative.

Merger Approval Proceedings

Delaware

On June 18, 2014, Exelon, PHI and DPL, and certain of their respective affiliates, filed an application with the DPSC seeking approval of the Merger. Delaware law requires the DPSC to approve the Merger when it determines that the transaction is in accordance with law, for a proper purpose, and is consistent

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with the public interest. The DPSC must further find that the successor will continue to provide safe and reliable service, will not terminate or impair existing collective bargaining agreements and will engage in good faith bargaining with organized labor. On February 13, 2015, Exelon, DPL, the DPSC staff, the Division of the Public Advocate and certain other parties filed a settlement agreement with the DPSC, which was amended in April 2015. The DPSC approved the amended settlement agreement at its meeting held on May 19, 2015, memorializing this decision by written order issued on June 2, 2015. The specific grounds for the DPSC’s approval of the Merger, as well as the specific conditions, will be included in an order to be issued by the DPSC after the Merger closes.

District of Columbia

On June 18, 2014, Exelon, PHI and Pepco, and certain of their respective affiliates, filed an application with the DCPSC seeking approval of the Merger. To approve the Merger, the DCPSC must find that the Merger is in the public interest. In an order issued August 22, 2014, the DCPSC stated that to make the determination of whether the transaction is in the public interest, it will analyze the transaction in the context of seven factors to determine whether the transaction balances the interests of shareholders and investors with ratepayers and the community, whether the benefits to shareholders do or do not come at the expense of the ratepayers, and whether the transaction produces a direct and tangible benefit to ratepayers. The seven factors identified by the DCPSC are the effects of the transaction on: (i) ratepayers, shareholders, the financial health of the utility standing alone and as merged, and the local economy; (ii) utility management and administrative operations; (iii) the public safety and the safety and reliability of services; (iv) risks associated with all of the affiliated non-jurisdictional business operations, including nuclear operations, of the applicants; (v) the DCPSC’s ability to regulate the utility effectively following the Merger; (vi) competition in the local retail and wholesale markets that impacts the District and District ratepayers; and (vii) conservation of natural resources and preservation of environmental quality. District of Columbia law does not impose any time limit on the DCPSC’s review of the Merger. The DCPSC held evidentiary hearings in March and April of 2015 and the record was closed on May 27, 2015.

On August 27, 2015, the DCPSC issued a written order denying the application seeking approval of the Merger. On September 28, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, filed an application for reconsideration before the DCPSC. Following the DCPSC’s decision on reconsideration, Exelon and Pepco Holdings have the option of filing further appeals with the DC Court of Appeals.

On October 6, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, entered into the DC Settlement Agreement with the District of Columbia Government, the Office of the People’s Counsel and other parties. Also on October 6, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates filed with the DCPSC the Motion to Reopen requesting consideration of the DC Settlement Agreement and approval of the Merger on such terms and conditions set forth in the DC Settlement Agreement, without condition or modification, and to stay further proceedings on the application for reconsideration filed by the parties on September 28, 2015, and suspend the time period for reconsideration pending the DCPSC’s consideration of the DC Settlement Agreement.

On October 28, 2015, the DCPSC approved the Motion to Reopen and set a procedural schedule for its review of this matter. Upon completion of the public input and evidentiary hearings, the record was closed as of December 23, 2015. Although District of Columbia law does not impose any time limit on the DCPSC’s review of the Merger, the parties requested a decision by March 4, 2016.

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Maryland

On August 19, 2014, Exelon, PHI, Pepco, DPL and certain of their respective affiliates, filed an application with the MPSC seeking approval of the Merger. Maryland law requires the MPSC to approve a merger subject to its review if it finds that the merger is consistent with the public interest, convenience and necessity, including its benefits to and impact on consumers. Evidentiary hearings were held beginning on January 26, 2015. On March 10, 2015, Exelon, PHI, Pepco, DPL and certain of their respective affiliates, filed with the MPSC a settlement agreement entered into with one of the stakeholder groups participating in the MPSC approval proceeding. On March 16, 2015, Exelon, PHI, Pepco, DPL and certain of their respective affiliates, filed with the MPSC a settlement agreement entered into with Montgomery and Prince George’s Counties in Maryland, and a number of other parties. On May 15, 2015, the MPSC approved the Merger, with conditions, including conditions that modify and supplement those originally proposed. On May 18, 2015, Pepco Holdings and Exelon announced that they had completed their review of the MPSC’s order approving the Merger and have committed to fulfill the modified, more stringent conditions and package of customer benefits imposed by the MPSC.

Multiple parties have filed petitions for judicial review of the MPSC order by the Circuit Court of Queen Anne’s County, Maryland, seeking to appeal the MPSC order. In connection with these proceedings, the Maryland Office of People’s Counsel and several other parties to the Merger proceedings filed motions in the Circuit Court for Queen Anne’s County, Maryland, requesting a stay of the MPSC order. On August 7, 2015, the Circuit Court for Queen Anne’s County denied the motions for stay. On January 8, 2016, the Circuit Court affirmed the MPSC’s order in all respects. On January 20 and 22, 2016, respectively, the Maryland Office of People’s Counsel and environmental groups filed notices of appeal of the Circuit Court’s order to the Maryland Court of Special Appeals. Unless a motion to stay is filed and then granted by the court, the MPSC order will remain in effect during the appeals process.

New Jersey

On June 18, 2014, Exelon, PHI and ACE, and certain of their respective affiliates, filed a petition with the NJBPU seeking approval of the Merger. To approve the Merger, the NJBPU must find the Merger is in the public interest, and consider the impact of the Merger on (i) competition, (ii) rates of ratepayers affected by the Merger, (iii) ACE’s employees, and (iv) the provision of safe and reliable service at just and reasonable rates. On January 14, 2015, PHI, ACE, Exelon, certain of Exelon’s affiliates, the Staff of the NJBPU, and the Independent Energy Producers of New Jersey filed a stipulation of settlement (the Stipulation) with the NJBPU in this proceeding. On February 11, 2015, the NJBPU approved the Stipulation and the Merger and on March 6, 2015, the NJBPU issued a written order approving the Stipulation.

The NJBPU order states that the Merger must be closed by November 1, 2015 unless extended by the NJBPU. On October 15, 2015, the NJBPU voted to extend the effectiveness of its Merger approval until June 30, 2016.

Virginia

On June 3, 2014, Exelon, PHI, Pepco and DPL, and certain of their respective affiliates, filed an application with the VSCC seeking approval of the Merger. Virginia law provides that, if the VSCC determines, with or without hearing, that adequate service to the public at just and reasonable rates will not be impaired or jeopardized by granting the application for approval, then the VSCC shall approve a merger with such conditions that the VSCC deems to be appropriate in order to satisfy this standard. On October 7, 2014,

the VSCC issued an order approving the Merger.

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Federal Energy Regulatory Commission

On May 30, 2014, Exelon, PHI, Pepco, DPL and ACE, and certain of their respective affiliates, submitted to FERC a Joint Application for Authorization of Disposition of Jurisdictional Assets and Merger under Section 203 of the FPA. Under that section, FERC shall approve a merger if it finds that the proposed transaction will be consistent with the public interest. On November 20, 2014, FERC issued an order approving the Merger.

Hart-Scott-Rodino Act

The HSR Act, which is the U.S. federal pre-merger notification statute, and its related rules and regulations provide that acquisition transactions that meet the HSR Act’s coverage thresholds may not be completed until a Notification and Report Form has been furnished to the Department of Justice (DOJ) and the Federal Trade Commission (FTC), and that the waiting period required by the HSR Act has been terminated or has expired. Pursuant to the HSR Act requirements, Pepco Holdings and Exelon filed the required Notification and Report Forms with the DOJ and the FTC, and the waiting period under the HSR Act expired on December 2, 2015, which allows for the closing of the Merger at any time on or before December 1, 2016.

(8) PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment is comprised of the following:

	Original Cost		Accumulated Depreciation		Net Book Value
	(millions of dollars)
At December 31, 2015
Generation	$	23	$	19	$	4
Distribution		10,051		3,161		6,890
Transmission		3,554		962		2,592
Gas		546		163		383
Construction work in progress		604		—		604
Non-operating and other property		1,440		609		831
Total	$	16,218	$	4,914	$	11,304
At December 31, 2014
Generation	$	104	$	100	$	4
Distribution		9,527		3,021		6,506
Transmission		3,252		934		2,318
Gas		511		153		358
Construction work in progress		688		—		688
Non-operating and other property		1,383		751		632
Total	$	15,465	$	4,959	$	10,506

The non-operating and other property amounts include balances for general plant, intangible plant, distribution plant and transmission plant held for future use as well as other property held by non-utility subsidiaries. Utility plant is generally subject to a first mortgage lien.

Pepco Holdings’ utility subsidiaries use separate depreciation rates for each electric plant account. The rates vary from jurisdiction to jurisdiction.

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Jointly Owned Plant

PHI’s consolidated balance sheets include its proportionate share of assets and liabilities related to jointly owned plant. At December 31, 2015 and 2014, PHI’s subsidiaries had a net book value ownership interest of $16 million and $15 million, respectively, in transmission and other facilities in which various parties also have ownership interests. PHI’s share of the operating and maintenance expenses of the jointly owned plant is included in the corresponding expenses in the consolidated statements of income (loss). PHI is responsible for providing its share of the financing for the above jointly owned facilities.

Capital Leases

Pepco leases its consolidated control center, which is an integrated energy management center used by Pepco to centrally control the operation of its transmission and distribution systems. This lease is accounted for as a capital lease and was initially recorded at the present value of future lease payments, which totaled $152 million. The lease requires semi-annual payments of approximately $8 million over a 25-year period that began in December 1994, and provides for transfer of ownership of the system to Pepco for $1 at the end of the lease term. Under FASB guidance on regulated operations, the amortization of leased assets is modified so that the total interest expense charged on the obligation and amortization expense of the leased asset is equal to the rental expense allowed for rate-making purposes. The amortization expense is included within Depreciation and amortization in the consolidated statements of income (loss). This lease is treated as an operating lease for rate-making purposes.

Capital lease assets recorded within Property, Plant and Equipment at December 31, 2015 and 2014 are comprised of the following:

	Original Cost		Accumulated Amortization		Net Book Value
	(millions of dollars)
At December 31, 2015
Transmission	$	76	$	51	$	25
Distribution		76		51		25
Total	$	152	$	102	$	50
At December 31, 2014
Transmission	$	76	$	46	$	30
Distribution		76		46		30
Total	$	152	$	92	$	60

The approximate annual commitments under all capital leases are $15 million in each of the years 2016 through 2018 and $16 million in 2019.

Gains on Sales of Land

Since 2002, Pepco has owned a 3.5 acre parcel of unimproved land (held as non-utility property) in the Buzzard Point area of southeast Washington, D.C. On July 2, 2015, Pepco entered into a purchase and sale agreement with the District of Columbia to sell the 3.5-acre parcel with a carrying value of $2 million at a purchase price of $39 million. The transaction was consummated on November 10, 2015 resulting in a $37 million pre-tax gain ($22 million after-tax) which was recorded in the fourth quarter of 2015.

Since 2003, Pepco has owned a 3.8 acre parcel of unimproved land (held as non-utility property) in the NoMa area of northeast Washington, D.C. On October 16, 2015, Pepco entered into a purchase and sale agreement with a third party to sell a two-acre parcel of the unimproved land with an allocated carrying value of $5 million at a purchase price of $14 million. The transaction was consummated on December 31, 2015 resulting in a $9 million pre-tax gain ($5 million after-tax) which was recorded in the fourth quarter of 2015. The purchase and sale agreement also provided the third party with a 90-day option to purchase the remaining 1.8-acre land parcel with an allocated carrying value of $4 million at a purchase price of $13 million.

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Deactivation of Pepco Energy Services’ Generating Facilities

During 2012, Pepco Energy Services deactivated its Buzzard Point and Benning Road oil-fired generation facilities. Pepco Energy Services completed demolition of the Benning Road generation facility in July 2015 and recognized the scrap metal salvage value of the facility as a reduction in its demolition expenses over the life of the project.

Long-Lived Asset Impairment

During 2014, PHI recorded impairment losses of $81 million ($48 million after-tax) at Pepco Energy Services associated with its combined heat and power thermal generating facilities and operations in Atlantic City, which reduced the carrying amount of its long lived assets in Atlantic City from $83 million to $2 million at December 31, 2014. PHI performed long-lived asset impairment tests on asset groups comprising substantially all of the long-lived assets in Atlantic City as a result of significant adverse changes in the financial condition of its customers and the business climate in Atlantic City. The assets were written down to their estimated fair values because the future estimated undiscounted cash flows from the asset groups were significantly lower than their carrying value. PHI estimated the fair values of the asset groups from a market participant’s perspective by calculating the present value of estimated future cash flows over the useful lives of the assets using an appropriate discount rate. Both the estimated future cash flows and the discount rate were based on primarily unobservable, Level 3 inputs. The estimated future cash flows were probability weighted based on several potential outcomes regarding forecasted revenues and expenses associated with each asset group. Forecasted revenues and expenses were, in part, based on estimated future commodity prices from an external valuation specialist. In addition, PHI forecasted customer usage volumes and the associated operations and maintenance expenses and capital expenditures. A 10 percent change in the estimated cash flows would not have a significant impact on the estimated fair value of the assets. PHI also selected a discount rate that would reflect a market return on the estimated cash flows. PHI considered a range of discount rates between 10 percent and 16 percent. A one percent change in the discount rate assumptions would not have a significant impact on the estimated fair value of the assets.

During 2013, PHI recorded impairment losses of $4 million ($3 million after-tax) at Pepco Energy Services associated primarily with its investments in landfill gas-fired electric generation facilities. PHI performed a long-lived asset impairment test on the landfill generation facilities of Pepco Energy Services as a result of a sustained decline in energy prices and recent production levels. The asset value of the facilities was written down to the estimated fair value because the future expected cash flows of the facilities were not sufficient to provide recovery of the facilities’ carrying value. PHI estimated the fair value of the facilities by calculating the present value of expected future cash flows using an appropriate discount rate. Both the expected future cash flows and the discount rate used primarily unobservable inputs.

Asset Retirement Obligations

PHI recognizes liabilities related to the retirement of long-lived assets in accordance with ASC 410. As of December 31, 2015, PHI had an asset retirement obligation of $7 million on its consolidated balance sheet related to the Edge Moor coal ash landfill site. The asset retirement obligation reflects estimates of the costs for PHI to close the landfill and provide post-closure operations, maintenance and monitoring services.

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(9) PENSION AND OTHER POSTRETIREMENT BENEFITS

The following table shows changes in the benefit obligation and plan assets for the years ended December 31, 2015 and 2014:

	Pension Benefits						Other Postretirement Benefits
	2015			2014			2015			2014
	(millions of dollars)
Change in Benefit Obligation
Benefit obligation as of January 1	$	2,638		$	2,238		$	632		$	574
Service cost		57			44			7			7
Interest cost		109			109			24			26
Actuarial loss (gain)		(151	)		401			(61	)		59
Benefits paid		(163	)		(154	)		(39	)		(34	)
Benefit obligation as of December 31	$	2,490		$	2,638		$	563		$	632
Change in Plan Assets
Fair value of plan assets as of January 1	$	2,236		$	2,116		$	367		$	368
Actual return on plan assets		(61	)		268			1			21
Company and participant contributions		6			6			5			6
Benefits paid by plan		(163	)		(154	)		(25	)		(28	)
Fair value of plan assets as of December 31	$	2,018		$	2,236		$	348		$	367
Funded Status at end of year (plan assets less plan obligations)	$	(472	)	$	(402	)	$	(215	)	$	(265	)

At December 31, 2015 and 2014, the PHI Retirement Plan’s accumulated benefit obligation was approximately $2.3 billion and $2.4 billion, respectively. The accumulated benefit obligation differs from the pension benefit obligation presented in the table above in that the accumulated benefit obligation includes no assumption about future compensation levels.

The following table provides the amounts recorded in PHI’s consolidated balance sheets as of December 31, 2015 and 2014:

	Pension Benefits						Other Postretirement Benefits
	2015			2014			2015			2014
	(millions of dollars)
Regulatory asset	$	870		$	871		$	40		$	75
Current liabilities		(6	)		(6	)		—			—
Pension benefit obligation		(466	)		(396	)		—			—
Other postretirement benefit obligations		—			—			(215	)		(265	)
Deferred income tax liabilities		(162	)		(193	)		70			77
Accumulated other comprehensive loss, net of tax		28			37			—			—
Net amount recorded	$	264		$	313		$	(105	)	$	(113	)

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Amounts included in AOCL (pre-tax) and Regulatory assets at December 31, 2015 and 2014 consist of:

	Pension Benefits				Other Postretirement Benefits
	2015		2014		2015			2014
	(millions of dollars)
Unrecognized net actuarial loss	$	910	$	925	$	128		$	176
Unamortized prior service cost (credit)		6		8		(88	)		(101	)
Total	$	916	$	933	$	40		$	75
Accumulated other comprehensive loss ($28 million and $37 million, net of tax, at December 31, 2015 and 2014, respectively)	$	46	$	62	$	—		$	—
Regulatory assets		870		871		40			75
Total	$	916	$	933	$	40		$	75

Under FASB guidance on regulated operations, a portion of actuarial gains and losses and prior service costs (credits) are included in Regulatory assets (liabilities) in the consolidated balance sheets to reflect expected regulatory recovery of such amounts, which otherwise would be recorded to AOCL. The table below provides the changes in plan assets and benefit obligations recognized in AOCL and Regulatory assets for the years ended December 31, 2015, 2014 and 2013:

	Pension Benefits									Other Postretirement Benefits
	2015			2014			2013			2015			2014			2013
	(millions of dollars)
Amounts amortized during the year:
Amortization of prior service (cost) credit	$	(2	)	$	(2	)	$	(2	)	$	13		$	13		$	11
Amortization of net actuarial loss		(65	)		(45	)		(67	)		(8	)		(3	)		(12	)
Amounts arising during the year:
Current year prior service cost (credit)		—			—			3			—			—			(124	)
Current year actuarial loss (gain)		50			276			(218	)		(39	)		62			(109	)
Total recognized in AOCL and Regulatory assets for the year ended December 31	$	(17	)	$	229		$	(284	)	$	(34	)	$	72		$	(234	)

The estimated net actuarial loss and prior service cost for the defined benefit pension plans that will be amortized from AOCL or Regulatory assets into net periodic benefit cost over the next reporting year are $63 million and $1 million, respectively. The estimated net actuarial loss and prior service credit for the OPEB plan that will be amortized from AOCL or Regulatory assets into net periodic benefit cost over the next reporting year are $7 million and $13 million, respectively.

The table below provides the components of net periodic benefit costs recognized for the years ended December 31, 2015, 2014 and 2013:

	Pension Benefits									Other Postretirement Benefits
	2015			2014			2013			2015			2014			2013
	(millions of dollars)
Service cost	$	57		$	44		$	53		$	7		$	7		$	8
Interest cost		109			109			100			24			26			29
Expected return on plan assets		(140	)		(141	)		(145	)		(22	)		(24	)		(20	)
Amortization of prior service cost (credit)		2			2			2			(13	)		(13	)		(11	)
Amortization of net actuarial loss		65			45			67			8			3			12
Net periodic benefit cost	$	93		$	59		$	77		$	4		$	(1	)	$	18

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The table below provides the split of the combined pension and other postretirement net periodic benefit costs among subsidiaries for the years ended December 31, 2015, 2014 and 2013:

	2015		2014		2013
	(millions of dollars)
Pepco	$	30	$	22	$	34
DPL		15		7		18
ACE		15		13		17
Other subsidiaries		37		16		26
Total	$	97	$	58	$	95

The following weighted average assumptions were used to determine the benefit obligations at December 31, 2015 and 2014:

	Pension Benefits						Other Postretirement Benefits
	2015			2014			2015			2014
Discount rate		4.65% /4.55	% (a)		4.20	%		4.55	%		4.15	%
Rate of compensation increase		5.00	%		5.00	%		5.00	%		5.00	%
Health care cost trend rate assumed for current year – pre 65		—			—			6.33	%		6.67	%
Health care cost trend rate assumed for current year – post 65		—			—			5.40	%		5.50	%
Rate to which the cost trend rate is assumed to decline for all eligible retirees (the ultimate trend rate)		—			—			5.00	%		5.00	%
Year that the cost trend rate reaches the ultimate trend rate		—			—			2020			2020

(a) The discount rate for the qualified and nonqualified pension plans was 4.65% and 4.55%, respectively.

Assumed health care cost trend rates may have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects, in millions of dollars:

	1-Percentage- Point Increase		1-Percentage- Point Decrease
Increase (decrease) in total service and interest cost	$	1	$	(1	)
Increase (decrease) in postretirement benefit obligation	$	15	$	(18	)

The following weighted average assumptions were used to determine the net periodic benefit cost for the years ended December 31, 2015, 2014 and 2013:

	Pension Benefits									Other Postretirement Benefits
	2015			2014			2013			2015			2014			2013
Discount rate		4.20	%		5.05	%		4.15	%		4.15	%		5.00	%		4.10%/4.95	% (a)
Expected long-term return on plan assets		6.50	%		7.00	%		7.00	%		6.75	%		7.25	%		7.00	%
Rate of compensation increase		5.00	%		5.00	%		5.00	%		5.00	%		5.00	%		5.00	%
Health care cost trend rate		—			—			—			6.67	%		7.00	%		7.50	%

(a) The discount rate was updated for remeasurement to 4.95% on July 1, 2013.

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PHI utilizes an analytical tool developed by its actuaries to select the discount rate. The analytical tool utilizes a high-quality bond portfolio with cash flows that match the benefit payments expected to be made under the plans.

PHI uses a building block approach to estimate the expected rate of return on plan assets. Under this approach, the percentage of plan assets in each asset class according to PHI’s target asset allocation, at the beginning of the year, is applied to the expected asset return for the related asset class. PHI incorporates long-term assumptions for real returns, inflation expectations, volatility and correlations among asset classes to determine expected returns for a given asset allocation. The pension and postretirement benefit plan assets consist of equity, fixed income, real estate and private equity investments. PHI periodically reviews its asset mix and rebalances assets to the target allocation.

The average remaining service periods for participating employees of the benefit plans was approximately 11 years for both 2015 and 2014. PHI utilizes plan census data to estimate these average remaining service periods. PHI uses mortality tables and mortality improvement scales issued by the Society of Actuaries to estimate participants’ life expectancy. In 2014, the Society of Actuaries issued updated mortality tables and mortality improvement scales which PHI applied in determining its benefit obligations as of December 31, 2014. In 2015, the Society of Actuaries modified the tables issued in 2014 to reflect updated mortality improvement experience. PHI applied these modified tables in determining its benefit obligations as of December 31, 2015.

Benefit Plan Modifications

During 2013, PHI approved two amendments to its other postretirement benefits plan. These amendments impacted the retiree health care and the retiree life insurance benefits, and were effective on January 1, 2014. As a result of the amendments, which were cumulatively significant, PHI remeasured its accumulated postretirement benefit obligation for other postretirement benefits as of July 1, 2013. The remeasurement resulted in a $193 million reduction of the accumulated postretirement benefit obligation, which included recording a prior service credit of $124 million, which will be amortized over approximately ten years, and a $69 million reduction from a change in the discount rate from 4.10% as of December 31, 2012 to 4.95% as of July 1, 2013. The remeasurement resulted in a $19 million reduction in net periodic benefit cost for other postretirement benefits during 2014, when compared to 2013. Approximately 36% of net periodic other postretirement benefit costs were capitalized in 2014.

Plan Assets

Investment Policies and Strategies

In developing its allocation policy for the assets in the PHI Retirement Plan and the other postretirement benefit plan, PHI examined projections of asset returns and volatility over a long-term horizon. In connection with this analysis, PHI evaluated the risk and return tradeoffs of alternative asset classes and asset mixes given long-term historical relationships as well as prospective capital market returns. PHI also conducted an asset-liability study to match projected asset growth with projected liability growth to determine whether there is sufficient liquidity for projected benefit payments. PHI developed its asset mix guidelines by incorporating the results of these analyses with an assessment of its risk posture, and taking into account industry practices. PHI periodically evaluates its investment strategy to ensure that plan assets are sufficient to meet the benefit obligations of the plans. As part of the ongoing evaluation, PHI may make changes to its targeted asset allocations and investment strategy.

PHI’s pension investment strategy is designed to meet the following investment objectives:

• Generate investment returns that, in combination with funding contributions from PHI, provide adequate funding to meet all current and future benefit obligations of the plan,

• Provide investment results that meet or exceed the assumed long-term rate of return, while maintaining the funded status of the plan at acceptable levels,

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• Improve funded status over time, and

• Decrease contribution and expense volatility as funded status improves.

To achieve these investment objectives, PHI’s investment strategy divides the pension program into two primary portfolios:

Return-Seeking Assets - These assets are intended to provide investment returns in excess of pension liability growth and reduce existing deficits in the funded status of the plan. The category includes a diversified mix of U.S. large and small cap equities, non-U.S. developed and emerging market equities, real estate, and private equity.

Liability-Hedging Assets - These assets are intended to reflect the sensitivity of the plan’s liabilities to changes in discount rates. This category includes a diversified mix of long duration, primarily investment grade credit and U.S. treasury securities.

PHI follows an asset-liability management strategy for PHI Retirement Plan assets in order to reduce the effects of future volatility of the fair value of its pension plan assets relative to its pension plan liabilities. For example, in 2015, this strategy uses a 68% target allocation to fixed income investments, primarily in high quality, longer-maturity fixed income securities. The PHI Retirement Plan asset allocations at December 31, 2015 and 2014, by asset category, were as follows:

Asset Category	Plan Assets at December 31,						Target Plan Asset Allocation
	2015			2014			2015			2014
Equity		28	%		28	%		27	%		27	%
Fixed Income		66	%		65	%		68	%		68	%
Other (real estate, private equity)		6	%		7	%		5	%		5	%
Total		100	%		100	%		100	%		100	%

PHI’s other postretirement benefit plan asset allocations at December 31, 2015 and 2014, by asset category, were as follows:

Asset Category	Plan Assets at December 31,						Target Plan Asset Allocation
	2015			2014			2015			2014
Equity		63	%		64	%		60	%		60	%
Fixed Income		34	%		34	%		35	%		35	%
Cash		3	%		2	%		5	%		5	%
Total		100	%		100	%		100	%		100	%

PHI will rebalance the plan asset portfolios when the actual allocations fall outside the ranges outlined in the investment policy or as funded status improves over a reasonable period of time.

Risk Management

Pension and other postretirement benefit plan assets may be invested in separately managed accounts in which there is ownership of individual securities, shares of commingled funds or mutual funds, or limited partnerships. Commingled funds and mutual funds are subject to detailed policy guidelines set forth in the fund’s prospectus or fund declaration, and limited partnerships are subject to the terms of the partnership agreement.

Separate account investment managers are responsible for achieving a level of diversification in their portfolio that is consistent with their investment approach and their role in PHI’s overall investment structure. Separate account investment managers must follow risk management guidelines established by PHI unless authorized in writing by PHI.

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Derivative instruments are permissible in an investment portfolio to the extent they comply with policy guidelines and are consistent with risk and return objectives. Under no circumstances may such instruments be used speculatively or to leverage the portfolio. Separately managed accounts are prohibited from holding securities issued by the following firms:

• PHI and its subsidiaries,

• PHI’s pension plan trustee, its parent or its affiliates,

• PHI’s pension plan consultant, its parent or its affiliates, and

• PHI’s pension plan investment manager, its parent or its affiliates.

Fair Value of Plan Assets

As defined in the FASB guidance on fair value measurement (ASC 820), fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The FASB’s fair value framework includes a hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1) and the lowest priority to unobservable inputs (level 3). If the inputs used to measure the financial instruments fall within different levels of the hierarchy, the categorization is based on the lowest level input that is significant to the fair value measurement of the instrument. Investments are classified within the fair value hierarchy as follows:

Level 1: Investments are valued using quoted prices in active markets for identical instruments.

Level 2: Investments are valued using other significant observable inputs (e.g., quoted prices for similar investments, interest rates, credit risks, etc).

Level 3: Investments are valued using significant unobservable inputs, including internal assumptions.

There were no significant transfers between level 1 and level 2 during the years ended December 31, 2015 and 2014.

In accordance with new FASB guidance on fair value measurement, certain investments that are measured at fair value using the NAV per share as a practical expedient are no longer classified within the fair value hierarchy and are no longer assigned a level. The fair value measurements table at December 31, 2014, was reclassified to conform to the current year presentation, see Note (3), “Newly Adopted Accounting Standards,” for additional information.

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The following tables present the fair values of PHI’s pension and other postretirement benefit plan assets by asset category included in and excluded from the fair value hierarchy levels, as of December 31, 2015 and 2014:

			Fair Value Measurements at December 31, 2015
	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
Asset Category
Pension Plan Assets:
Equity:
Domestic (a)	$	311	$	120	$	191	$	—
International (b)		216		215		—		1
Fixed Income (c)		820		—		810		10
Cash Equivalents (d)		50		50		—		—
		1,397	$	385	$	1,001	$	11
Investments measured at fair value using net asset value as a practical expedient:
Equity:
Domestic (a)		33
Fixed Income (c)		504
Other:
Private Equity		38
Real Estate		46
Pension Plan Assets Total	$	2,018
Other Postretirement Plan Assets:
Equity (e)	$	197	$	197	$	—	$	—
Fixed Income (f)		120		120		—		—
Cash Equivalents		9		9		—		—
		326	$	326	$	—	$	—
Investments measured at fair value using net asset value as a practical expedient:
Equity (e)		22
Postretirement Plan Assets Total	$	348

(a) Domestic equity assets predominantly include domestic common stock and commingled funds.

(b) International equity assets predominantly include foreign common and preferred stock and warrants.

(c) Fixed income assets predominantly include corporate bonds, government bonds, municipal/provincial bonds, collateralized mortgage obligations and commingled funds.

(d) Cash equivalents predominantly include cash investments in short-term investment funds.

(e) Equity assets include domestic and international commingled funds.

(f) Fixed income assets include fixed income commingled funds.

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			Fair Value Measurements at December 31, 2014
	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
Asset Category
Pension Plan Assets:
Equity:
Domestic (a)	$	341	$	128	$	213	$	—
International (b)		255		254		—		1
Fixed Income (c)		916		—		905		11
Cash Equivalents (d)		45		45		—		—
		1,557	$	427	$	1,118	$	12
Investments measured at fair value using net asset value as a practical expedient:
Equity:
Domestic (a)		35
Fixed Income (c)		543
Other:
Private Equity		47
Real Estate		54
Pension Plan Assets Total	$	2,236
Other Postretirement Plan Assets:
Equity (e)	$	208	$	208	$	—	$	—
Fixed Income (f)		126		126		—		—
Cash Equivalents		6		6		—		—
		340	$	340	$	—	$	—
Investments measured at fair value using net asset value as a practical expedient:
Equity (e)		27
Postretirement Plan Assets Total	$	367

(a) Domestic equity assets predominantly include domestic common stock and commingled funds.

(b) International equity assets predominantly include foreign common and preferred stock and warrants.

(c) Fixed income assets predominantly include corporate bonds, government bonds, municipal/provincial bonds, collateralized mortgage obligations and commingled funds.

(d) Cash equivalents predominantly include cash investments in short-term investment funds.

(e) Equity assets include domestic and international commingled funds.

(f) Fixed income assets include fixed income commingled funds.

There were no significant concentrations of risk in pension and OPEB plan assets at December 31, 2015 and 2014.

Valuation Techniques Used to Determine Fair Value

Equity

Equity securities are primarily comprised of securities issued by public companies in domestic and foreign markets plus investments in commingled funds, which are valued on a daily basis. PHI can exchange shares of the publicly traded securities and the fair values are primarily sourced from the closing prices on stock exchanges where there is active trading, therefore they would be classified as level 1 investments. If there is less active trading, then the publicly traded securities would typically be priced using observable data, such as bid/ask prices, and these measurements would be classified as level 2 investments. Investments that are not publicly traded and valued using unobservable inputs would be classified as level 3 investments. Investments that are measured at fair value using the NAV per share as a practical expedient are not classified within the fair value hierarchy.

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Commingled funds with publicly quoted prices and active trading are classified as level 1 investments. For commingled funds that are not publicly traded and have ongoing subscription and redemption activity or have redemption restrictions, the fair value of the investment is the NAV per fund share, derived from the underlying securities’ quoted prices in active markets, and are not classified within the fair value hierarchy.

Fixed Income

Fixed income investments are primarily comprised of fixed income securities and fixed income commingled funds. The prices for direct investments in fixed income securities are generated on a daily basis. Like the equity securities, fair values generated from active trading on exchanges are classified as level 1 investments. Prices generated from less active trading with wider bid/ask prices are classified as level 2 investments. If prices are based on uncorroborated and unobservable inputs, then the investments are classified as level 3 investments. Investments that are measured at fair value using the NAV per share as a practical expedient are not classified within the fair value hierarchy.

Commingled funds with publicly quoted prices and active trading are classified as level 1 investments. For commingled funds that are not publicly traded and have ongoing subscription and redemption activity or redemption restrictions, the fair value of the investment is the NAV per fund share, derived from the underlying securities’ quoted prices in active markets, and are not classified within the fair value hierarchy.

Other – Private Equity and Real Estate

Investments in private equity and real estate funds are primarily invested in privately held real estate investment properties, trusts and partnerships, as well as equity and debt issued by public or private companies. As a practical expedient, PHI’s interest in the fund or partnership is estimated at NAV. PHI’s interest in these funds cannot be readily redeemed due to the inherent lack of liquidity and the primarily long-term nature of the underlying assets. Distribution is made through the liquidation of the underlying assets. PHI views these investments as part of a long-term investment strategy. These investments are valued by each investment manager based on the underlying assets. The majority of the underlying assets are valued using significant unobservable inputs and often require significant management judgment or estimation based on the best available information. Market data includes observations of the trading multiples of public companies considered comparable to the private companies being valued. The funds utilize valuation techniques consistent with the market, income and cost approaches to measure the fair value of certain real estate investments. In accordance with FASB guidance on fair value measurement, PHI does not classify these investments within the fair value hierarchy.

The investments in private equity and real estate funds require capital commitments, which may be called over a specific number of years. Unfunded capital commitments as of December 31, 2015 and 2014 totaled $9 million and $11 million, respectively.

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Reconciliations of the beginning and ending balances of PHI’s fair value measurements using significant unobservable inputs (level 3) for investments in the pension plan for the years ended December 31, 2015 and 2014 are shown below:

	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Equity		Fixed Income			Total Level 3
			(millions of dollars)
Balance as of January 1, 2015	$	1	$	11		$	12
Transfer in (out) of Level 3		—		—			—
Purchases		—		—			—
Sales		—		—			—
Settlements		—		(1	)		(1	)
Unrealized gain (loss)		—		—			—
Realized gain		—		—			—
Balance as of December 31, 2015	$	1	$	10		$	11
	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Equity		Fixed Income			Total Level 3
			(millions of dollars)
Balance as of January 1, 2014	$	1	$	11		$	12
Transfer in (out) of Level 3		—		—			—
Purchases		—		—			—
Sales		—		—			—
Settlements		—		—			—
Unrealized gain (loss)		—		—			—
Realized gain		—		—			—
Balance as of December 31, 2014	$	1	$	11		$	12

Cash Flows

Contributions - PHI Retirement Plan

PHI’s funding policy with regard to the PHI Retirement Plan is to maintain a funding level that is at least equal to the target liability as defined under the Pension Protection Act of 2006, as modified by subsequent legislation. During 2015 and 2014, PHI, Pepco, DPL and ACE did not make any discretionary tax-deductible contributions to the PHI Retirement Plan as its assets met or exceeded the funding target level for 2015 and 2014.

Contributions - Other Postretirement Benefit Plan

In 2015 and 2014, Pepco contributed $2 million and $1 million, respectively, DPL made no contributions in either year, and ACE contributed $3 million and $3 million, respectively, to the other postretirement benefit plan. In 2015 and 2014, no contributions were made by PHI’s other subsidiaries.

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Expected Benefit Payments

Estimated future benefit payments to participants in PHI’s pension and other postretirement benefit plans, which reflect expected future service as appropriate, are as follows:

Years	Pension Benefits		Other Postretirement Benefits
	(millions of dollars)
2016	$	143	$	38
2017		143		38
2018		148		38
2019		153		38
2020		158		38
2021 through 2025		836		189

Pepco Holdings Retirement Savings Plan

Pepco Holdings has a defined contribution retirement savings plan. Participation in the plan is voluntary. All participants are 100% vested and have a nonforfeitable interest in their own contributions and in the Pepco Holdings’ company matching contributions, including any earnings or losses thereon. Pepco Holdings’ matching contributions were $14 million, $13 million and $12 million for the years ended December 31, 2015, 2014 and 2013, respectively.

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(10) DEBT

Long-Term Debt

The components of long-term debt are shown in the table below:

		At December 31,
Interest Rate	Maturity	2015		2014
		(millions of dollars)
First Mortgage Bonds
Pepco:
3.05%	2022	$	200	$	200
6.20% (a)(b)	2022		110		110
3.60%	2024		400		400
5.75% (c)(d)	2034		100		100
5.40% (c)(d)	2035		175		175
6.50% (a)(c)	2037		500		500
7.90%	2038		250		250
4.15%	2043		450		250
4.95%	2043		150		150
ACE:
7.68% (e)	2015 - 2016		2		17
7.75%	2018		250		250
6.80% (d)(f)	2021		39		39
4.35%	2021		200		200
3.375%	2024		150		150
3.50%	2025		150		—
4.875% (a)(f)	2029		23		23
5.80% (d)(g)	2034		120		120
5.80% (d)(g)	2036		105		105
DPL:
5.22% (h)	2016		100		100
3.50%	2023		500		500
4.00%	2042		250		250
4.15%	2045		200		—
Total First Mortgage Bonds			4,424		3,889
Unsecured Tax-Exempt Bonds
DPL:
5.40%	2031		78		78
Total Unsecured Tax-Exempt Bonds			78		78

NOTE: Schedule is continued on next page.

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		At December 31,
Interest Rate	Maturity	2015			2014
		(millions of dollars)
Medium-Term Notes (unsecured)
DPL:
7.56% - 7.58%	2017	$	14		$	14
6.81%	2018		4			4
7.61%	2019		12			12
7.72%	2027		10			10
Total Medium-Term Notes (unsecured)			40			40
Notes (secured)
Pepco Energy Services:
6.70% - 7.46%	2015-2018		3			4
Notes (unsecured)
PHI:
2.70%	2015		—			250
5.90%	2016		190			190
6.125%	2017		81			81
7.45%	2032		185			185
DPL:
5.00%	2015		—			100
Total Notes (unsecured)			456			806
Total Long-Term Debt			5,001			4,817
Net unamortized discount			(2	)		(10	)
Unamortized debt issuance costs			(49	)		(44	)
Current portion of long-term debt			(294	)		(366	)
Total Net Long-Term Debt		$	4,656		$	4,397

(a) Represents a series of Collateral First Mortgage Bonds which must be cancelled and released as security for the issuer’s obligations under the corresponding series of issuer notes or tax-exempt bonds, at such time as the issuer does not have any first mortgage bonds outstanding (other than its Collateral First Mortgage Bonds), except that the issuer may not permit such release of collateral unless the issuer substitutes comparable obligations for such collateral.

(b) Represents a series of Collateral First Mortgage Bonds securing a series of senior notes issued by Pepco, which in turn secures a series of tax-exempt bonds issued for the benefit of Pepco.

(c) Represents a series of Collateral First Mortgage Bonds (as defined herein) securing a series of senior notes issued by Pepco.

(d) Represents a series of Collateral First Mortgage Bonds which must be cancelled and released as security for the issuer’s obligations under the corresponding series of issuer notes (as defined herein) or tax-exempt bonds, at such time as the issuer does not have any first mortgage bonds outstanding (other than its Collateral First Mortgage Bonds).

(e) Represents a series of Collateral First Mortgage Bonds securing a series of medium-term notes issued by ACE.

(f) Represents a series of Collateral First Mortgage Bonds securing a series of tax-exempt bonds issued for the benefit of ACE.

(g) Represents a series of Collateral First Mortgage Bonds securing a series of senior notes issued by ACE.

(h) Represents a series of Collateral First Mortgage Bonds securing a series of debt securities issued by DPL.

The outstanding first mortgage bonds issued by each of Pepco, DPL and ACE are issued under a mortgage and deed of trust and are secured by a first lien on substantially all of the issuing company’s property, plant and equipment, except for certain property excluded from the lien of the respective mortgage.

PHI’s long-term debt is subject to certain covenants. As of December 31, 2015, PHI and its subsidiaries were in compliance with all such covenants.

The table above does not separately identify $885 million, $100 million and $227 million in aggregate principal amount of senior notes, medium term notes and other debt securities (issuer notes) issued by each of Pepco, DPL and ACE, respectively, and $110 million and $62 million in aggregate principal amount of tax-exempt bonds issued for the benefit of Pepco and ACE, respectively. These issuer notes are secured by a like amount of first mortgage bonds (Collateral First Mortgage Bonds) of each respective

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issuer. In addition, these tax-exempt bonds are secured by a like amount of Collateral First Mortgage Bonds issued by the utility subsidiary for whose benefit the tax-exempt bonds were issued. The principal terms of each such series of issuer notes, or the issuer’s obligations in respect of each such series of tax-exempt bonds, are identical to the same terms of the corresponding series of Collateral First Mortgage Bonds. Payments of principal and interest made on a series of such issuer notes, or the satisfaction of the issuer’s obligations in respect of a series of such tax-exempt bonds, satisfy the corresponding obligations on the related series of Collateral First Mortgage Bonds. For these reasons, each such series of Collateral First Mortgage Bonds and the corresponding issuer notes and/or tax-exempt bonds together effectively represent a single financial obligation and are not identified in the table above separately.

Bond Issuances

During 2015, Pepco issued $200 million of 4.15% first mortgage bonds due March 15, 2043, with a 3.9% yield to maturity. Net proceeds from the issuance of the bonds, which included a premium of $8 million, were used by Pepco to repay outstanding commercial paper and for general corporate purposes.

During 2015, DPL issued $200 million of 4.15% first mortgage bonds due May 15, 2045. Net proceeds from the issuance of the bonds were used by DPL to repay outstanding commercial paper and for general corporate purposes.

During 2015, ACE issued $150 million of 3.50% first mortgage bonds due December 1, 2025 in a private placement. The net proceeds from the issuance of the bonds were used by ACE to repay outstanding commercial paper and for general corporate purposes.

Note Retirements

During 2015, ACE retired, at maturity, $15 million of its secured medium-term notes series C. The medium-term notes were secured by a like principal amount of its 7.68% first mortgage bonds due August 24, 2015, which under the mortgage and deed of trust were deemed to be satisfied when the medium-term notes were repaid.

During 2015, DPL retired, at maturity, $100 million of its 5.00% unsecured notes due June 1, 2015.

During 2015, PHI retired, at maturity, $250 million of its 2.70% unsecured notes due October 1, 2015.

Transition Bonds Issued by ACE Funding

The components of transition bonds are shown in the table below:

		At December 31,
Interest Rate	Maturity	2015			2014
		(millions of dollars)
4.91%	2017	$	—		$	17
5.05%	2020		39			51
5.55%	2023		132			147
Total Transition Bonds			171			215
Unamortized debt issuance costs			(1	)		(1	)
Current portion of long-term debt			(46	)		(44	)
Total Net Long-Term Transition Bonds		$	124		$	170

For a description of the Transition Bonds, see Note (17), “Variable Interest Entities – ACE Funding.”

Maturities of PHI’s Long-term Debt and Transition Bonds

Maturities of PHI’s long-term debt and Transition Bonds outstanding at December 31, 2015 are $340 million in 2016, $131 million in 2017, $285 million in 2018, $30 million in 2019, $20 million in 2020 and $4,366 million thereafter.

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Long-Term Project Funding

As of December 31, 2015 and 2014, Pepco Energy Services had total outstanding long-term project funding (including current maturities) of $5 million and $10 million, respectively, related to energy savings contracts performed by Pepco Energy Services. The aggregate amounts of maturities for the project funding debt outstanding at December 31, 2015 are $1 million in each of the years 2016 and 2017, zero in 2018, $1 million in 2019, $1 million in 2020, and $1 million thereafter.

Short-Term Debt

PHI and its regulated utility subsidiaries have traditionally used a number of sources to fulfill short-term funding needs, such as commercial paper, short-term notes, and bank lines of credit. Proceeds from short-term borrowings are used primarily to meet working capital needs, but may also be used to temporarily fund long-term capital requirements. The components of PHI’s short-term debt at December 31, 2015 and 2014 are as follows:

	2015		2014
	(millions of dollars)
Commercial paper	$	658	$	624
Variable rate demand bonds		105		105
Term loan		300		—
Total	$	1,063	$	729

Commercial Paper

PHI, Pepco, DPL and ACE maintain ongoing commercial paper programs to address short-term liquidity needs. As of December 31, 2015, the maximum capacity available under these programs was $875 million, $500 million, $500 million and $350 million, respectively, subject to available borrowing capacity under the credit facility.

PHI, Pepco, DPL and ACE had $484 million, $64 million, $105 million and $5 million, respectively, of commercial paper outstanding at December 31, 2015. The weighted average interest rate for commercial paper issued by PHI, Pepco, DPL and ACE during 2015 was 0.80%, 0.44%, 0.47% and 0.46%, respectively. The weighted average maturity of all commercial paper issued by PHI, Pepco, DPL and ACE during 2015 was ten, four, four and six days, respectively.

PHI, Pepco, DPL and ACE had $287 million, $104 million, $106 million and $127 million, respectively, of commercial paper outstanding at December 31, 2014. The weighted average interest rate for commercial paper issued by PHI, Pepco, DPL and ACE during 2014 was 0.57%, 0.28%, 0.26% and 0.27%, respectively. The weighted average maturity of all commercial paper issued by PHI, Pepco, DPL and ACE during 2014 was six, six, five and five days, respectively.

Variable Rate Demand Bonds

PHI’s utility subsidiary DPL has outstanding obligations in respect of Variable Rate Demand Bonds (VRDB). VRDBs are subject to repayment on the demand of the holders and, for this reason, are accounted for as short-term debt in accordance with GAAP. However, bonds submitted for purchase are remarketed by a remarketing agent on a best efforts basis. PHI expects that any bonds submitted for purchase will be remarketed successfully due to the creditworthiness of the issuer and, as applicable, the credit support, and because the remarketing resets the interest rate to the then-current market rate. The bonds may be converted to a fixed-rate, fixed-term option to establish a maturity which corresponds to the

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date of final maturity of the bonds. On this basis, PHI views VRDBs as a source of long-term financing. As of December 31, 2015, $105 million of VRDBs issued on behalf of DPL were outstanding (of which $72 million were secured by Collateral First Mortgage Bonds issued by DPL). During 2014, ACE retired, at maturity, its last remaining VRDBs in the amount of $18 million.

The VRDBs outstanding at December 31, 2015 mature as follows: 2017 ($26 million), 2024 ($33 million), 2028 ($16 million), and 2029 ($30 million). The weighted average interest rate for VRDBs outstanding on December 31, 2015 was 0.13% during 2015 and 0.19% during 2014.

PHI Term Loan Agreements

On January 13, 2016, PHI entered into a $500 million term loan agreement, pursuant to which PHI borrowed $500 million at a rate of interest equal to the prevailing Eurodollar rate, which is determined by reference to the London Interbank Offered Rate with respect to the relevant interest period, all as defined in the loan agreement, plus a margin of 0.90%. PHI used the net proceeds of the loan under the loan agreement to repay its outstanding commercial paper, and for general corporate purposes. All indebtedness incurred under the loan agreement is unsecured, and the aggregate principal amount of all loans, together with any accrued but unpaid interest due under the loan agreement, must be repaid in full on or before July 13, 2016. Pursuant to the term loan agreement, PHI may consummate the Merger and the subsequent conversion of PHI from a Delaware corporation to a Delaware limited liability company, provided that the Merger and subsequent conversion are consummated on or before October 29, 2015. PHI requested and obtained the consent of the lenders under the term loan to allow for completion of the Merger by June 30, 2016.

On July 30, 2015, PHI entered into a $300 million term loan agreement, pursuant to which PHI borrowed $300 million at a rate of interest equal to the prevailing Eurodollar rate, which is determined by reference to the LIBOR with respect to the relevant interest period, all as defined in the loan agreement, plus a margin of 0.95%. PHI used the net proceeds of the loan under the loan agreement to repay a portion of its outstanding commercial paper, and for general corporate purposes. All indebtedness incurred under the loan agreement is unsecured, and the aggregate principal amount of all loans, together with any accrued but unpaid interest due under the loan agreement, must be repaid in full on or before July 28, 2016. Pursuant to the term loan agreement, PHI may consummate the Merger and the subsequent conversion of PHI from a Delaware corporation to a Delaware limited liability company, provided that the Merger and subsequent conversion are consummated on or before October 29, 2015. PHI requested and obtained the consent of the lenders under the term loan to allow for completion of the Merger by June 30, 2016.

Credit Facility

PHI, Pepco, DPL and ACE maintain an unsecured syndicated credit facility to provide for their respective liquidity needs, including obtaining letters of credit, borrowing for general corporate purposes and supporting their commercial paper programs. On August 1, 2013, as permitted under the existing terms of the credit agreement, a request by PHI, Pepco, DPL and ACE to extend the credit facility termination date to August 1, 2018 was approved. All of the terms and conditions as well as pricing remained the same.

The aggregate borrowing limit under the amended and restated credit facility is $1.5 billion, all or any portion of which may be used to obtain loans and up to $500 million of which may be used to obtain letters of credit. The facility also includes a swingline loan sub-facility, pursuant to which each company may make same day borrowings in an aggregate amount not to exceed 10% of the total amount of the facility. Any swingline loan must be repaid by the borrower within fourteen days of receipt. The credit sublimit is $750 million for PHI and $250 million for each of Pepco, DPL and ACE. The sublimits may be increased or decreased by the individual borrower during the term of the facility, except that (i) the sum of all of the borrower sublimits following any such increase or decrease must equal the total amount of the facility and (ii) the aggregate amount of credit used at any given time by (a) PHI may not exceed $1.25 billion and (b) each of Pepco, DPL or ACE may not exceed the lesser of $500 million and the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the sublimit reallocations may not exceed eight per year during the term of the facility.

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The interest rate payable by each company on utilized funds is, at the borrowing company’s election, (i) the greater of the prevailing prime rate, the federal funds effective rate plus 0.5% and the one month London Interbank Offered Rate (LIBOR) plus 1.0%, or (ii) the prevailing Eurodollar rate, plus a margin that varies according to the credit rating of the borrower.

In order for a borrower to use the facility, certain representations and warranties must be true and correct, and the borrower must be in compliance with specified financial and other covenants, including (i) the requirement that each borrowing company maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the credit agreement, which calculation excludes from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) with certain exceptions, a restriction on sales or other dispositions of assets, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than permitted liens. The credit agreement contains certain covenants and other customary agreements and requirements that, if not complied with, could result in an event of default and the acceleration of repayment obligations of one or more of the borrowers thereunder. Each of the borrowers was in compliance with all covenants under this facility at December 31, 2015.

The absence of a material adverse change in PHI’s business, property, results of operations or financial condition is not a condition to the availability of credit under the credit agreement. The credit agreement does not include any rating triggers.

As of December 31, 2015 and December 31, 2014, the amount of cash plus unused borrowing capacity under the credit facility available to meet the future liquidity needs of PHI and its utility subsidiaries on a consolidated basis totaled $851 million and $875 million, respectively. PHI’s utility subsidiaries had combined cash and unused borrowing capacity under the credit facility of $576 million and $413 million at December 31, 2015 and December 31, 2014, respectively.

Credit Facility Amendment

During 2014, PHI, Pepco, DPL and ACE entered into an amendment of and consent with respect to the credit agreement (the Consent). PHI was required to obtain the consent of certain of the lenders under the credit facility in order to permit the consummation of the Merger. Pursuant to the Consent, certain of the lenders consented to the consummation of the Merger and the subsequent conversion of PHI from a Delaware corporation to a Delaware limited liability company, provided that the Merger and subsequent conversion are consummated on or before October 29, 2015. In addition, the Consent amends the definition of “Change in Control” in the credit agreement to mean, following consummation of the Merger, an event or series of events by which Exelon no longer owns, directly or indirectly, 100% of the outstanding shares of voting stock of Pepco Holdings. PHI requested and obtained an extension of the Consent to allow for completion of the Merger by June 30, 2016.

Other Financing Activities

Sale of Receivables

During 2015, Pepco, as seller, entered into a purchase agreement with a buyer to sell receivables from an energy savings project over a period of time pursuant to a task order. The purchase price to be received by Pepco is $5 million. Pursuant to the purchase agreement, following acceptance of the energy savings project by the buyer, the buyer is entitled to receive the contract payments under the task order payable by the customer over approximately 15 years. The energy savings project will be performed by Pepco Energy Services and is expected to be completed by the end of 2017.

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During 2014, Pepco, as seller, entered into a purchase agreement with a buyer to sell receivables from an energy savings project pursuant to a task order entered into under a General Services Administration area-wide agreement. The purchase price received by Pepco was $12 million, which was included in the Current portion of long-term debt and project funding at December 31, 2014. The energy savings project was performed by Pepco Energy Services and was completed in 2014. Pursuant to the purchase agreement, following acceptance of the energy savings project by the buyer, the buyer was entitled to receive the contract payments under the task order payable by the buyer over approximately 9 years. The energy savings project was accepted during the first quarter of 2015 and the amount was removed from the Current portion of long-term debt and project funding.

During 2013, Pepco Energy Services, as seller, entered into a purchase agreement with a buyer to sell receivables from an energy savings project over a period of time pursuant to a task order. The purchase price received by Pepco Energy Services was $7 million, which was included in the Current portion of long-term debt and project funding at December 31, 2014. Pursuant to the purchase agreement, following acceptance of the energy savings project by the buyer, the buyer is entitled to receive the contract payments under the task order payable by the customer over approximately 23 years. The energy savings project was accepted during the first quarter of 2015 and the amount was removed from the Current portion of long-term debt and project funding.

ACE Term Loan Agreement

On May 10, 2013, ACE entered into a $100 million term loan agreement, pursuant to which ACE borrowed $100 million at a rate of interest equal to the prevailing Eurodollar rate, which was determined by reference to the LIBOR with respect to the relevant interest period, all as defined in the loan agreement, plus a margin of 0.75%. On August 21, 2014, ACE repaid the term loan in full.

(11) INCOME TAXES

PHI and the majority of its subsidiaries file a consolidated federal income tax return. Federal income taxes are allocated among PHI and the subsidiaries included in its consolidated group pursuant to a written tax sharing agreement that was approved by the SEC in 2002 in connection with the establishment of PHI as a public utility holding company. Under this tax sharing agreement, PHI’s consolidated federal income tax liability is allocated based upon PHI’s and its subsidiaries’ separate taxable income or loss.

The provision for consolidated income taxes, reconciliation of consolidated income tax expense, and components of consolidated deferred tax liabilities (assets) are shown below.

Provision for Consolidated Income Taxes – Continuing Operations

	For the Year Ended December 31,
	2015			2014			2013
	(millions of dollars)
Current Tax (Benefit) Expense
Federal	$	(3	)	$	(137	)	$	(128	)
State and local		12			(26	)		(9	)
Total Current Tax Expense (Benefit)		9			(163	)		(137	)
Deferred Tax Expense (Benefit)
Federal		92			261			393
State and local		30			41			65
Investment tax credit amortization		(2	)		(1	)		(2	)
Total Deferred Tax Expense		120			301			456
Total Consolidated Income Tax Expense Related to Continuing Operations	$	129		$	138		$	319

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Reconciliation of Consolidated Income Tax Expense – Continuing Operations

	For the Year Ended December 31,
	2015					2014					2013
	(millions of dollars)
Income tax at Federal statutory rate	$	156		35.0	%	$	133		35.0	%	$	150		35.0	%
Increases (decreases) resulting from:
State income taxes, net of federal effect		27		6.0	%		23		6.1	%		27		6.3	%
Asset removal costs		(14	)	(3.1	)%		(12	)	(3.2	)%		(14	)	(3.3	)%
Change in estimates and interest related to uncertain and effectively settled tax positions		(46	)	(10.3	)%		—		—			56		13.1	%
Deferred tax basis adjustments		7		1.6	%		—		—			—		—
Establishment of valuation allowances related to deferred tax assets		—		—			—		—			101		23.5	%
Merger related costs		4		0.9	%		7		1.8	%		—		—
Other, net		(5	)	(1.2	)%		(13	)	(3.4	)%		(1	)	(0.2	)%
Consolidated Income Tax Expense Related to Continuing Operations	$	129		28.9	%	$	138		36.3	%	$	319		74.4	%

Global Tax Settlement

On November 18, 2015, PHI entered into a settlement with the IRS and the DOJ (the Global Tax Settlement) to provide for the resolution of the tax treatment of its previously held cross-border energy lease investments involving public utility assets located outside of the United States structured as sale-in, lease-out, or SILO, transactions. The Global Tax Settlement followed the acceptance by PHI on October 29, 2015 of IRS revenue agent reports covering adjustments incorporated in the terms of the Global Tax Settlement, as well as adjustments for all other tax matters in dispute with the IRS. Also, on November 18, 2015, the DOJ accepted PHI’s offer letter for the settlement of litigation related to the SILO transactions discussed further in Note (16), “Commitments and Contingencies – PHI’s Cross-Border Energy Lease Investments.” The Global Tax Settlement and the revenue agent reports, together, effectively close all years open to examination of federal income tax liabilities for PHI through 2011, and all matters associated with the cross-border energy lease investments through 2013.

The Global Tax Settlement, which resolves tax matters related to the cross-border energy lease investments and avoids the costs associated with continued litigation, provides that all depreciation and interest deductions in excess of rental income related to the cross-border energy lease investments were disallowed. The Global Tax Settlement also required PHI to recognize original issue discount income for tax purposes associated with the recharacterization of each of the leases as a loan transaction. Pursuant to the Global Tax Settlement, interest will be assessed with respect to tax underpayments in the relevant years; however, no penalties were assessed against PHI. The Global Tax Settlement provides for the same treatment of the cross-border energy lease investments for the tax years 2012 and 2013 as described above. The last of PHI’s cross-border energy lease investments was terminated in 2013. As a result of the Global Tax Settlement, PHI and the DOJ filed stipulations of dismissal regarding the litigation in the U.S. Court of Federal Claims. The Court dismissed the complaint on November 20, 2015.

As a result of the Global Tax Settlement, PHI recorded in the fourth quarter of 2015 a tax benefit of $56 million, including $47 million associated with continuing operations and $9 million associated with discontinued operations. The $47 million benefit associated with continuing operations is included above in Change in estimates and interest related to uncertain and effectively settled tax positions. Included in

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the tax benefit of $47 million associated with continuing operations was a $21 million after-tax interest benefit representing the anticipated reduction in previously recorded interest expense that was allocated to PHI’s continuing operations associated with PHI’s uncertain tax positions. The remaining tax benefit recorded of $26 million primarily represents uncertain tax positions associated with PHI’s continuing operations that were settled in favor of PHI in the Global Tax Settlement.

Also during the fourth quarter of 2015, PHI completed its annual reconciliation of its deferred income tax accounts and corrected prior period errors by recording an after-tax charge of $7 million which is included above in Deferred tax basis adjustments. Management has determined that these errors, individually or in the aggregate, were not material to the current or prior periods.

Other Tax Matters

During 2015 and 2014, PHI recorded tax benefits of $6 million and $5 million, respectively, related to certain energy efficiency tax deductions associated with Pepco Energy Services’ energy savings performance contracting services. Theses tax benefits are included above in Other, net.

In connection with the proposed Merger (as further described in Note (1), “Organization”), PHI incurred certain merger-related costs in 2015 and 2014 which are not tax-deductible.

During 2013, PHI recorded a $56 million charge for a change in estimates and interest related to uncertain and effectively settled tax positions, primarily representing the anticipated additional interest expense on estimated federal and state income tax obligations that was allocated to PHI’s continuing operations resulting from a change in assessment of tax benefits associated with the former cross-border energy lease investments of PCI in the first quarter of 2013.

Also, in 2013, PHI established valuation allowances of $101 million related to deferred tax assets. Between 1990 and 1999, PCI, through various subsidiaries, entered into certain transactions involving investments in aircraft and aircraft equipment, railcars and other assets. In connection with these transactions, PCI recorded deferred tax assets in prior years of $101 million in the aggregate. Following events that took place during the first quarter of 2013, which included (i) court decisions in favor of the IRS with respect to other taxpayers’ cross-border lease and other structured transactions (as discussed in Note (20), “Discontinued Operations – Cross-Border Energy Lease Investments”), (ii) the change in PHI’s tax position with respect to the tax benefits associated with its cross-border energy leases, and (iii) PHI’s decision in March 2013 to begin to pursue the early termination of its remaining cross-border energy lease investments (which represented a substantial portion of the remaining assets within PCI) without the intent to reinvest these proceeds in income-producing assets, management evaluated the likelihood that PCI would be able to realize the $101 million of deferred tax assets in the future. Based on this evaluation, PCI established valuation allowances against these deferred tax assets totaling $101 million in the first quarter of 2013. Further, during the fourth quarter of 2013, in light of additional court decisions in favor of the IRS involving other taxpayers, and after consideration of all relevant factors, management determined that it would abandon the further pursuit of these deferred tax assets, and these assets totaling $101 million were charged off against the previously established valuation allowances.

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Components of Consolidated Deferred Tax Liabilities (Assets)

	At December 31,
	2015			2014
	(millions of dollars)
Deferred Tax Liabilities (Assets)
Depreciation and other basis differences related to plant and equipment	$	3,273		$	2,962
Deferred electric service and electric restructuring liabilities		43			67
Federal and state net operating losses		(446	)		(400	)
Valuation allowances on state net operating losses		63			61
Pension and other postretirement benefits		92			116
Deferred taxes on amounts to be collected through future rates		86			94
Other		267			325
Total Deferred Tax Liabilities, net		3,378			3,225
Deferred tax assets included in Other Assets		15			17
Total Consolidated Deferred Tax Liabilities, net	$	3,393		$	3,242

The net deferred tax liability represents the tax effect, at presently enacted tax rates, of temporary differences between the financial statement basis and tax basis of assets and liabilities. The portion of the net deferred tax liability applicable to PHI’s utility operations, which has not been reflected in current service rates, represents income taxes recoverable through future rates, net, and is recorded as a Regulatory asset on the balance sheet. Federal and state net operating losses generally expire over 20 years from 2029 to 2034.

The Tax Reform Act of 1986 repealed the investment tax credit for property placed in service after December 31, 1985, except for certain transition property. Investment tax credits previously earned on Pepco’s, DPL’s and ACE’s property continue to be amortized to income over the useful lives of the related property.

Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits

	2015			2014			2013
	(millions of dollars)
Balance as of January 1,	$	850		$	831		$	200
Tax positions related to current year:
Additions		—			4			3
Reductions		—			(2	)		—
Tax positions related to prior years:
Additions		13			27			646	(b)
Reductions		(201	)(a)		(10	)		(12	)
Settlements		(628	)(a)		—			(6	)
Balance as of December 31,	$	34		$	850		$	831

(a) Reductions and settlements in 2015 resulted from the Global Tax Settlement. Settlements represent unrecognized tax benefits that were satisfied with cash or use of net operating losses and tax credits. The majority of the settlements were associated with the treatment of the former cross-border energy lease investments of PCI.

(b) These additions of unrecognized tax benefits in 2013 primarily relate to the former cross-border energy lease investments of PCI.

Unrecognized Benefits That, If Recognized, Would Affect the Effective Tax Rate

Unrecognized tax benefits are related to tax positions that have been taken or are expected to be taken in tax returns that are not recognized in the financial statements because management has either measured the tax benefit at an amount less than the benefit claimed or expected to be claimed, or has concluded that

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it is not more likely than not that the tax position will be ultimately sustained. For the majority of these tax positions, the ultimate deductibility is highly certain, but there is uncertainty about the timing of such deductibility. Unrecognized tax benefits at December 31, 2015 included $22 million that, if recognized, would lower the effective tax rate.

Interest and Penalties

PHI recognizes interest and penalties relating to its uncertain tax positions as an element of income tax expense. For the years ended December 31, 2015, 2014 and 2013, PHI recognized $35 million of pre-tax interest income ($21 million after-tax), less than $1 million of pre-tax interest expense, and $125 million of pre-tax interest expense ($75 million after-tax), respectively, as a component of income tax expense related to continuing and discontinued operations. As of December 31, 2015, 2014 and 2013, PHI had accrued interest payable of $2 million, accrued interest receivable of $2 million and accrued interest receivable of $2 million, respectively, related to effectively settled and uncertain tax positions.

Possible Changes to Unrecognized Tax Benefits

It is reasonably possible that the amount of unrecognized tax benefits with respect to PHI’s uncertain tax positions will significantly increase or decrease within the next 12 months. At this time, it is estimated that there will be a $6 million to $10 million decrease in unrecognized tax benefits within the next 12 months.

Tax Years Open to Examination

As a result of the Global Tax Settlement, PHI’s federal income tax liabilities for PHI and Pepco legacy companies for all years through 2011, and for all matters associated with the cross-border energy lease investments for all years through 2013, have been determined by the IRS, subject to adjustment to the extent of any net operating loss or other loss or credit carrybacks from subsequent years. The open tax years for the significant states where PHI files state income tax returns (District of Columbia, Maryland, Delaware, New Jersey, Pennsylvania and Virginia) are the same as for the Federal returns.

Changes to the District of Columbia Tax Law

On February 26, 2015, the District of Columbia Fiscal Year 2015 Budget Support Act of 2014 became law, effective January 1, 2015. The law revised the apportionment methodology for corporate tax and included a phase-down of the corporate tax rate from 9.975% to 8.25% by fiscal year 2019. The change in law required PHI and Pepco to remeasure their net deferred tax liabilities in the first and fourth quarters of 2015. This remeasurement resulted in Pepco reducing its deferred tax liabilities by $23 million in the first quarter of 2015 to reflect the initial reduction in the tax rate from 9.975% to 9.4% on January 1, 2015 and $2 million in the fourth quarter of 2015 to reflect the subsequent reduction in the tax rate from 9.4% to 9.2% on January 1, 2016. These reductions to the deferred tax liabilities were offset by corresponding decreases to Pepco’s regulatory assets. Further reductions to the corporate tax rate in future years will depend upon the achievement of future revenue projections for the District of Columbia.

Final IRS Regulations on Repair of Tangible Property

In August 2011, the IRS issued Revenue Procedure 2011-43 providing a safe harbor method of tax accounting for repair costs associated with electric transmission and distribution property. In September 2012, with the filing of its 2011 tax return, PHI adopted the safe harbor for the 2011 tax year. In September 2013, the IRS published final regulations regarding the tax treatment of costs incurred to acquire, produce or improve tangible property. In February 2014, the IRS issued revenue procedures that describe how taxpayers should implement the final regulations. The final repair regulations and the related revenue procedures did not modify the guidance set forth in Revenue Procedure 2011-43 that the Unit of Property for electric transmission and distribution network assets is determined by the taxpayer’s particular facts and circumstances. The final regulations did not have a material impact on PHI’s consolidated financial statements.

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Other Taxes

Other taxes for continuing operations are shown below. The annual amounts include $421 million, $407 million and $422 million for the years ended December 31, 2015, 2014 and 2013, respectively, related to Power Delivery, which are recoverable through rates.

	2015		2014		2013
	(millions of dollars)
Gross Receipts/Delivery	$	124	$	123	$	133
Property		92		84		77
County Fuel and Energy		143		143		153
Environmental, Use and Other		68		63		65
Total	$	427	$	413	$	428

(12) STOCK-BASED COMPENSATION, DIVIDEND RESTRICTIONS, AND CALCULATIONS OF EARNINGS PER SHARE OF COMMON STOCK

Stock-Based Compensation

Pepco Holdings maintains the 2012 Long-Term Incentive Plan (2012 LTIP), the successor plan to the Long-Term Incentive Plan (LTIP), the objective of which is to increase shareholder value by providing long-term and equity incentives to reward officers, key employees and non-employee directors of Pepco Holdings and its subsidiaries and to increase the ownership of Pepco Holdings common stock by such individuals. Any officer, key employee or non-employee director of Pepco Holdings or its subsidiaries may be designated as a participant. Under these plans, awards to officers, key employees and non-employee directors may be in the form of restricted stock, restricted stock units, stock options, performance shares and/or units, stock appreciation rights, unrestricted stock and dividend equivalents. At inception, 10 million and 8 million shares of common stock were authorized for issuance under the LTIP and the 2012 LTIP, respectively. The LTIP expired in accordance with its terms in 2012 and no new awards may be granted thereunder.

Total stock-based compensation expense recorded in the consolidated statements of income (loss) for the years ended December 31, 2015, 2014 and 2013 was $13 million, $18 million and $12 million, respectively, all of which was associated with restricted stock and restricted stock unit awards.

No material amount of stock compensation expense was capitalized for the years ended December 31, 2015, 2014 and 2013.

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Restricted Stock and Restricted Stock Unit Awards

Description of Awards

A number of programs have been established under the LTIP and the 2012 LTIP involving the issuance of restricted stock and restricted stock unit awards, including awards of performance-based restricted stock and restricted stock units, and time-based restricted stock and restricted stock units. A summary of each of these programs is as follows:

• Under the performance-based program, performance criteria are selected and measured over the specified performance period. Depending on the extent to which the performance criteria are satisfied, the participants are eligible to earn shares of common stock at the end of the performance period, ranging from 25% to 200% of the target award, and dividend equivalents accrued thereon.

• Generally, time-based restricted stock and restricted stock unit award opportunities have a requisite service period of up to three years and, with respect to restricted stock awards, participants have the right to receive dividends on the shares during the vesting period. Under restricted stock unit awards, dividends are credited quarterly in the form of additional restricted stock units, which are paid when vested at the end of the service period.

• PHI granted a total of 22,901 and 21,138 time-based restricted stock units in 2015 and 2014, respectively, to its non-employee directors under the 2012 LTIP. These time-based restricted stock units vest over a service period which ends upon the first to occur of (i) one year after the date of grant or (ii) the date of the next annual meeting of stockholders. These awards represent the equity portion of the annual retainer paid to non-employee directors for their service as a director of PHI.

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Activity for the year

The 2015 activity for restricted stock, performance-based restricted stock, time-based restricted stock unit and performance-based restricted stock unit awards is summarized in the table below. For performance-based restricted stock and restricted stock unit awards, the table reflects awards projected, for purposes of computing the weighted average grant date fair value, to achieve 100% of targeted performance criteria for each outstanding award cycle.

	Number of Shares			Weighted Average Grant Date Fair Value
Balance as of January 1, 2015
Restricted stock		54,165		$	26.80
Performance-based restricted stock		70,276			27.01
Time-based restricted stock units		468,958			19.61
Performance-based restricted stock units		827,981			17.73
Total		1,421,380
Granted during 2015
Performance-based restricted stock		48,347			26.10
Time-based restricted stock units		450,203			27.40
Performance-based restricted stock units		6,188			26.08
Total		504,738
Vested during 2015
Performance-based restricted stock		(93,906	)		26.78
Time-based restricted stock units		(288,429	)		20.61
Performance-based restricted stock units		(424,705	)		17.05
Total		(807,040	)
Forfeited during 2015
Time-based restricted stock units		(2,218	)		27.00
Performance-based restricted stock units		(826	)		19.33
Total		(3,044	)
Balance as of December 31, 2015 (a)
Restricted stock		54,165			26.80
Performance-based restricted stock		24,717			26.10
Time-based restricted stock units		628,514			24.71
Performance-based restricted stock units		408,638			18.56
Total		1,116,034

(a) The balance as of December 31, 2015 does not include 36,110 shares of restricted stock, 113,385 time-based restricted stock units and 104,628 performance-based restricted stock units that were vested for executives and 30,784 time-based restricted stock units that were vested for directors but had not yet settled.

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Grants included in the table above reflect 2015 grants of restricted stock, performance-based restricted stock, time-based restricted stock unit and performance-based restricted stock unit awards. PHI recognizes compensation expense related to restricted stock, performance-based restricted stock, time-based restricted stock unit and performance-based restricted stock unit awards based on the fair value of the awards at date of grant. The fair value is based on the market value of PHI common stock at the date the award opportunity is granted. The estimated fair value of the performance-based awards is also a function of PHI’s projected future performance relative to established performance criteria and the resulting payout of shares based on the achieved performance levels. PHI employed a Monte Carlo simulation to forecast PHI’s performance relative to the performance criteria and to estimate the potential payout of shares under the performance-based awards.

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The following table provides the weighted average grant date fair value per share of those awards granted during each of the years ended December 31, 2015, 2014 and 2013:

	2015		2014		2013
Weighted average grant-date fair value of each restricted stock award granted during the year	$	—	$	26.80	$	—
Weighted average grant-date fair value of each performance-based restricted stock award granted during the year	$	26.10	$	27.01	$	—
Weighted average grant-date fair value of each time-based restricted stock unit award granted during the year	$	27.40	$	19.77	$	19.70
Weighted average grant-date fair value of each performance-based restricted stock unit award granted during the year	$	26.08	$	18.53	$	17.03

As of December 31, 2015, there was approximately $12 million of future compensation cost (net of estimated forfeitures) related to restricted stock unit awards granted under the LTIP and the 2012 LTIP that PHI expects to recognize over a weighted-average period of approximately two years.

Stock Options

Stock options to purchase shares of PHI’s common stock granted under the LTIP and the 2012 LTIP must have an exercise price at least equal to the fair market value of the underlying stock on the grant date. Stock options generally become exercisable on a specified vesting date or dates. All stock options must have an expiration date of no greater than ten years from the date of grant. No options have been granted under the LTIP or the 2012 LTIP since 2002.

Directors’ Deferred Compensation

Under the Pepco Holdings’ Executive and Director Deferred Compensation Plan, Pepco Holdings non-employee directors may elect to defer all or part of their cash retainer and meeting fees. Deferred retainer or meeting fees, at the election of the director, can be credited with interest at the prime rate or the return on selected investment funds or can be deemed invested in phantom shares of Pepco Holdings common stock on which dividend equivalent accruals are credited when dividends are paid on the common stock (or a combination of these options). All deferrals are settled in cash. The amount deferred by directors for the year ended December 31, 2015 was zero and was not material for each of the years ended December 31, 2014 and 2013.

Compensation expense recognized in respect of dividends and the increase in fair value was not material for each of the years ended December 31, 2015 and 2013, and $1 million for the year ended December 31, 2014. The deferred compensation balances under this program were approximately $2 million at December 31, 2015 and 2014.

A separate deferral option under the 2012 LTIP gives non-employee directors the right to elect to defer the receipt of common stock upon vesting of restricted stock unit awards.

Dividend Restrictions

PHI, on a stand-alone basis, generates no operating income of its own. Accordingly, its ability to pay dividends to its stockholders depends on dividends received from its subsidiaries. In addition to their future financial performance, the ability of PHI’s direct and indirect subsidiaries to pay dividends is subject to limits imposed by: (i) state corporate laws, which impose limitations on the funds that can be used to pay dividends and, in the case of ACE, the regulatory requirement that it obtain the prior approval of the NJBPU before dividends can be paid if its equity as a percent of its total capitalization, excluding securitization debt, falls below 30%; (ii) the prior rights of holders of mortgage bonds and other long-term debt issued by the subsidiaries, and any other restrictions imposed in connection with the incurrence of liabilities; and (iii) certain provisions of ACE’s charter that impose restrictions on payment of common

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stock dividends for the benefit of preferred stockholders. Pepco, DPL and ACE have no shares of preferred stock outstanding at December 31, 2015. Currently, the capitalization ratio limitation to which ACE is subject and the restriction in the ACE charter do not limit ACE’s ability to pay common stock dividends. As further described in Note (10), “Debt,” PHI, Pepco, DPL and ACE have restrictions on total indebtedness in relation to total capitalization under the credit facility.

PHI had approximately $617 million and $565 million of retained earnings free of restrictions at December 31, 2015 and 2014, respectively. These amounts represent the total retained earnings balances at those dates. The amount of restricted net assets for PHI’s consolidated subsidiaries at December 31, 2015 is $2,633 million.

For the years ended December 31, 2015, 2014 and 2013, dividends paid by PHI’s subsidiaries were as follows:

Subsidiary	2015		2014		2013
	(millions of dollars)
Pepco (paid to PHI)	$	146	$	86	$	46
DPL (paid to Conectiv)		92		100		30
ACE (paid to Conectiv)		12		26		60
Total	$	250	$	212	$	136

Equity Forward Transaction

During 2012, PHI entered into an equity forward transaction in connection with a public offering of PHI common stock. Pursuant to the terms of this transaction, a forward counterparty borrowed 17,922,077 shares of PHI’s common stock from third parties and sold them to a group of underwriters for $19.25 per share, less an underwriting discount equal to $0.67375 per share. Under the terms of the equity forward transaction, upon physical settlement thereof, PHI was required to issue and deliver shares of PHI common stock to the forward counterparty at the then applicable forward sale price. The forward sale price was initially determined to be $18.57625 per share at the time the equity forward transaction was entered into and was subject to reduction from time to time in accordance with the terms of the equity forward transaction. PHI believed that the equity forward transaction substantially eliminated future equity price risk because the forward sale price was determinable as of the date that PHI entered into the equity forward transaction and was only reduced pursuant to the contractual terms of the equity forward transaction through the settlement date, which reductions were not affected by a future change in the market price of the PHI common stock. On February 27, 2013, PHI physically settled the equity forward at the then applicable forward sale price of $17.39 per share. The proceeds of approximately $312 million were used to repay outstanding commercial paper, a portion of which had been issued in order to make capital contributions to the utilities, and for general corporate purposes.

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Calculations of Earnings per Share of Common Stock

The numerator and denominator for basic and diluted earnings per share of common stock calculations are shown below.

	For the Year Ended December 31,
	2015		2014		2013
	(millions of dollars, except per share data)
Income (Numerator):
Net income from continuing operations	$	318	$	242	$	110
Net income (loss) from discontinued operations		9		—		(322	)
Net income (loss)	$	327	$	242	$	(212	)
Shares (Denominator) (in millions):
Weighted average shares outstanding for basic computation:
Average shares outstanding		253		251		246
Adjustment to shares outstanding		—		—		—
Weighted Average Shares Outstanding for Computation of Basic Earnings Per Share of Common Stock		253		251		246
Net effect of potentially dilutive shares (a)		1		1		—
Weighted Average Shares Outstanding for Computation of Diluted Earnings Per Share of Common Stock		254		252		246
Basic earnings per share of common stock from continuing operations	$	1.25	$	0.96	$	0.45
Basic earnings (loss) per share of common stock from discontinued operations		0.04		—		(1.31	)
Basic earnings (loss) per share	$	1.29	$	0.96	$	(0.86	)
Diluted earnings per share of common stock from continuing operations	$	1.25	$	0.96	$	0.45
Diluted earnings (loss) per share of common stock from discontinued operations		0.04		—		(1.31	)
Diluted earnings (loss) per share	$	1.29	$	0.96	$	(0.86	)

(a) There were no options to purchase shares of common stock that were excluded from the calculation of diluted earnings per share for the years ended December 31, 2015, 2014 and 2013.

Direct Stock Purchase and Dividend Reinvestment Plan

PHI maintains a DRP through which participants may reinvest cash dividends. In addition, participants can make purchases of shares of PHI common stock through the investment of not less than $25 per purchase nor more than $300,000 each calendar year. Shares of common stock purchased through the DRP may be new shares, treasury shares held by PHI, or, at the election of PHI, shares purchased in the open market. Less than 1 million, approximately 1 million and 2 million new shares were issued and sold under the DRP in 2015, 2014 and 2013, respectively.

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Pepco Holdings Common Stock Reserved and Unissued

The following table presents Pepco Holdings’ common stock reserved and unissued at December 31, 2015:

Name of Plan	Number of Shares
DRP		4,584,077
Pepco Holdings Long-Term Incentive Plan (a)		6,946,614
Pepco Holdings 2012 Long-Term Incentive Plan		7,136,961
Pepco Holdings Retirement Savings Plan		3,456,261
Total		22,123,913

(a) No further awards will be made under this plan.

(13) PREFERRED STOCK

In connection with entering into the Merger Agreement (as further described in Note (1), “Organization”), PHI entered into a Subscription Agreement with Exelon, dated April 29, 2014, pursuant to which PHI issued to Exelon 9,000 originally issued shares of Preferred Stock for a purchase price of $90 million on April 30, 2014. In connection with these agreements, Exelon also committed to purchase 1,800 originally issued shares of Preferred Stock for a purchase price of $18 million at the end of each 90-day period following April 29, 2014, up to a maximum of 18,000 shares of Preferred Stock for a maximum aggregate consideration of $180 million. In accordance with the Subscription Agreement, on each of July 29, 2014, October 27, 2014, January 26, 2015, April 27, 2015 and July 24, 2015, an additional 1,800 shares of Preferred Stock were issued by PHI to Exelon for an aggregate purchase price of $90 million. If the Merger closes or terminates for any reason, no additional shares of Preferred Stock will be issued pursuant to the Subscription Agreement. The holders of the Preferred Stock will be entitled to receive a cumulative, non-participating cash dividend of 0.1% per annum, payable quarterly, when, as and if declared by PHI’s board of directors. The proceeds from the issuance of the Preferred Stock are not subject to restrictions and are intended to serve as a prepayment of any applicable reverse termination fee payable from Exelon to PHI. The Preferred Stock will be redeemable on the terms and in the circumstances set forth in the Merger Agreement and the Subscription Agreement.

If the Merger Agreement is terminated due to a Regulatory Termination, PHI will be able to redeem any issued and outstanding Preferred Stock at par value ($0.01 per share). If the Merger Agreement is terminated for any other reason, PHI will be required to redeem all issued and outstanding Preferred Stock at the purchase price of $10,000 per share, plus any unpaid accrued and accumulated dividends thereupon.

PHI has excluded the Preferred Stock from equity at December 31, 2015 and 2014, since the Preferred Stock contains conditions for redemption that are not solely within the control of PHI. Management determined that the Preferred Stock contains embedded features requiring separate accounting consideration to reflect the potential value to PHI that any issued and outstanding Preferred Stock could be called and redeemed at a nominal par value upon a Regulatory Termination. The embedded call and redemption features on the shares of the Preferred Stock in the event of a Regulatory Termination are separately accounted for as derivatives. These Preferred Stock derivatives are valued at each reporting date using quantitative and qualitative factors, including management’s assessment of the likelihood of a Regulatory Termination. As of December 31, 2015, the fair value of the remaining derivative related to the Preferred Stock was estimated to be $18 million based on management’s updated assessment. The estimated fair value of the derivatives related to the Preferred Stock at December 31, 2014 was $3 million and has been included in current assets (Prepaid expenses and other) with a corresponding increase in Preferred Stock on the consolidated balance sheet at December 31, 2014. The $15 million increase in the fair value of the derivative has been included in Other income for the year ended December 31, 2015.

(14) DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Derivative Instruments

DPL uses derivative instruments in the form of futures primarily to reduce natural gas commodity price volatility and to limit its customers’ exposure to increases in the market price of natural gas under a hedging program approved by the DPSC. DPL uses these derivatives to manage the commodity price risk associated with its physical natural gas purchase contracts. The natural gas purchase contracts qualify as

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normal purchases, which are not required to be recorded in the financial statements until settled. All premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all gains and losses related to hedging activities, are deferred under FASB guidance on regulated operations (ASC 980) until recovered from its customers through a fuel adjustment clause approved by the DPSC. In addition, included in derivative assets are PHI Preferred Stock derivatives which are further described in Note (13), “Preferred Stock.”

ACE was ordered to enter into the SOCAs by the NJBPU, and under the SOCAs, ACE would have received payments from or made payments to electric generation facilities based on (i) the difference between the fixed price in the SOCAs and the price for capacity that clears PJM and (ii) ACE’s annual proportion of the total New Jersey load relative to the other EDCs in New Jersey. ACE began applying derivative accounting to two of its SOCAs as of June 30, 2012 because these generators cleared the 2015-2016 PJM capacity auction in May 2012. The fair value of the derivatives embedded in these SOCAs were deferred as Regulatory assets or Regulatory liabilities because the NJBPU allowed full recovery from ACE’s distribution customers for any payments made by ACE, and ACE’s distribution customers would be entitled to payments received by ACE.

As further discussed in Note (7), “Regulatory Matters,” in light of a Federal district court order, which ruled that the SOCAs are void, invalid and unenforceable, and ACE’s subsequent termination of the SOCAs in the fourth quarter of 2013, ACE derecognized the derivative assets and derivative liabilities related to the SOCAs.

The tables below identify the balance sheet location and fair values of derivative instruments as of December 31, 2015 and 2014:

	As of December 31, 2015
Balance Sheet Caption	Derivatives Designated as Hedging Instruments		Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting		Net Derivative Instruments
						(millions of dollars)
Derivative assets (current assets)	$	—	$	18		$	18		$	—	$	18
Derivative liabilities (current liabilities)		—		(2	)		(2	)		2		—
Net derivative asset	$	—	$	16		$	16		$	2	$	18

	As of December 31, 2014
Balance Sheet Caption	Derivatives Designated as Hedging Instruments		Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting		Net Derivative Instruments
						(millions of dollars)
Derivative assets (current assets)	$	—	$	3		$	3		$	—	$	3
Derivative liabilities (current liabilities)		—		(4	)		(4	)		4		—
Net derivative (liability) asset	$	—	$	(1	)	$	(1	)	$	4	$	3

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All derivative assets and liabilities available to be offset under master netting arrangements were netted as of December 31, 2015 and 2014. The amount of cash collateral that was offset against these derivative positions is as follows:

	December 31, 2015		December 31, 2014
	(millions of dollars)
Cash collateral pledged to counterparties with the right to reclaim (a)	$	2	$	4

(a) Includes cash deposits on commodity brokerage accounts.

As of December 31, 2015 and 2014, all PHI cash collateral pledged related to derivative instruments accounted for at fair value was entitled to be offset under master netting agreements.

Derivatives Designated as Hedging Instruments

Cash Flow Hedges Included in Accumulated Other Comprehensive Loss

PHI also may use derivative instruments from time to time to mitigate the effects of fluctuating interest rates on debt issued in connection with the operation of its businesses. In June 2002, PHI entered into several treasury rate lock transactions in anticipation of the issuance of several series of fixed-rate debt commencing in August 2002. Upon issuance of the fixed-rate debt in August 2002, the treasury rate locks were terminated at a loss. The loss has been deferred in AOCL and is being recognized in interest expense over the life of the debt issued as interest payments are made.

The tables below provide details regarding terminated cash flow hedges included in PHI’s consolidated balance sheets as of December 31, 2015 and 2014. The data in the following tables indicate the cumulative net loss after-tax related to terminated cash flow hedges by contract type included in AOCL, the portion of AOCL expected to be reclassified to income during the next 12 months, and the maximum hedge or deferral term:

Contracts	As of December 31, 2015				Maximum Term
	Accumulated Other Comprehensive Loss After-tax		Portion Expected to be Reclassified to Income during the Next 12 Months
	(millions of dollars)
Interest rate	$	8	$	1		200 months

Contracts	As of December 31, 2014				Maximum Term
	Accumulated Other Comprehensive Loss After-tax		Portion Expected to be Reclassified to Income during the Next 12 Months
	(millions of dollars)
Interest rate	$	9	$	1		212 months

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Other Derivative Activity

DPL has certain derivatives that are not in hedge accounting relationships and are not designated as normal purchases or normal sales. These derivatives are recorded at fair value on the consolidated balance sheets with the gain or loss for changes in fair value recorded in income. In addition, in accordance with FASB guidance on regulated operations (ASC 980), regulatory liabilities or regulatory assets of the same amount are recorded on the consolidated balance sheets and the recognition of the derivative gain or loss is deferred because of the DPSC-approved fuel adjustment clause for DPL’s derivatives and the NJBPU order pertaining to the ACE SOCA derivatives. During 2012, ACE had recognized derivative assets and derivative liabilities in connection with the SOCAs referred to in Note (7), “Regulatory Matters.” In 2013, the Federal district court issued an order as described in Note (7), “Regulatory Matters” which caused ACE to derecognize the derivative assets and derivatives liabilities related to the SOCAs in the fourth quarter of 2013. The following table shows the net unrealized and net realized derivative gains and losses arising during the period associated with these derivatives that were recognized in the consolidated statements of income (loss) (through Fuel and purchased energy expense) and that were also deferred as regulatory liabilities and regulatory assets, respectively, for the years ended December 31, 2015, 2014 and 2013:

	For the Year Ended December 31,
	2015			2014			2013
	(millions of dollars)
Net unrealized (loss) gain arising during the period	$	(3	)	$	(3	)	$	4
Net realized (loss) gain recognized during the period		(5	)		2			(4	)

As of December 31, 2015 and 2014, the quantities and positions of DPL’s net outstanding natural gas commodity forward contracts that did not qualify for hedge accounting were:

	December 31, 2015			December 31, 2014
Commodity	Quantity		Net Position	Quantity		Net Position
DPL – Natural gas (one Million British Thermal Units)		4,190,000	Long		3,892,500	Long

In addition, PHI recorded derivative assets for the embedded call and redemption features on the shares of Preferred Stock as further described in Note (13), “Preferred Stock.” The net unrealized gain arising during 2015 related to these derivative assets was $15 million and has been included in Other income.

(15) FAIR VALUE DISCLOSURES

Financial Instruments Measured at Fair Value on a Recurring Basis

PHI applies FASB guidance on fair value measurement (ASC 820) that established a framework for measuring fair value and expanded disclosures about fair value measurements. As defined in the guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). PHI utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. Accordingly, PHI utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1) and the lowest priority to unobservable inputs (level 3).

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The following tables set forth, by level within the fair value hierarchy, PHI’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2015 and 2014. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. PHI’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Fair Value Measurements at December 31, 2015
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1) (a)		Significant Other Observable Inputs (Level 2) (a)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Derivative instruments
Preferred stock	$	18	$	—	$	—	$	18
Cash equivalents and restricted cash equivalents
Treasury fund		42		42		—		—
Executive deferred compensation plan assets
Money market funds and short-term investments		27		12		15		—
Life insurance contracts		46		—		27		19
Total	$	133	$	54	$	42	$	37
LIABILITIES
Derivative instruments (b)
Natural gas (c)	$	2	$	2	$	—	$	—
Executive deferred compensation plan liabilities
Life insurance contracts		30		—		30		—
Total	$	32	$	2	$	30	$	—

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2015.

(b) The fair values of derivative liabilities reflect netting by counterparty before the impact of collateral.

(c) Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.

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	Fair Value Measurements at December 31, 2014
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1) (a)		Significant Other Observable Inputs (Level 2) (a)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Derivative instruments
Preferred stock	$	3	$	—	$	—	$	3
Restricted cash equivalents
Treasury fund		38		38		—		—
Executive deferred compensation plan assets
Money market funds and short-term investments		35		14		21		—
Life insurance contracts		46		—		27		19
Total	$	122	$	52	$	48	$	22
LIABILITIES
Derivative instruments (b)
Natural gas (c)	$	4	$	4	$	—	$	—
Executive deferred compensation plan liabilities
Life insurance contracts		30		—		30		—
Total	$	34	$	4	$	30	$	—

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2014.

(b) The fair values of derivative liabilities reflect netting by counterparty before the impact of collateral.

(c) Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.

PHI classifies its fair value balances in the fair value hierarchy based on the observability of the inputs used in the fair value calculation as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis, such as the Intercontinental Exchange.

Level 2 – Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using broker quotes in liquid markets and other observable data. Level 2 also includes those financial instruments that are valued using methodologies that have been corroborated by observable market data through correlation or by other means. Significant assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

Executive deferred compensation plan assets and liabilities categorized as level 2 consist of life insurance policies and certain employment agreement obligations. The life insurance policies are categorized as level 2 assets because they are valued based on the assets underlying the policies, which consist of short-term cash equivalents and fixed income securities that are priced using observable market data and can be liquidated for the value of the underlying assets as of December 31, 2015. The level 2 liability associated with the life insurance policies represents a deferred compensation obligation, the value of which is tracked via underlying insurance sub-accounts. The sub-accounts are designed to mirror existing mutual funds and money market funds that are observable and actively traded.

The value of certain employment agreement obligations (which are included with life insurance contracts in the tables above) is derived using a discounted cash flow valuation technique. The discounted cash flow calculations are based on a known and certain stream of payments to be made over time that are discounted to determine their net present value. The primary variable input, the discount rate, is based on market-corroborated and observable published rates. These obligations have been classified as level 2 within the fair value hierarchy because the payment streams represent contractually known and certain amounts and the discount rate is based on published, observable data.

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Level 3 – Pricing inputs that are significant and generally less observable than those from objective sources. Level 3 includes those financial instruments that are valued using models or other valuation methodologies.

Derivative instruments classified as level 3 include embedded call and redemption features on the Preferred Stock as further discussed in Note (13), “Preferred Stock.”

Executive deferred compensation plan assets include certain life insurance policies that are valued using the cash surrender value of the policies, net of loans against those policies. The cash surrender values do not represent a quoted price in an active market; therefore, those inputs are unobservable and the policies are categorized as level 3. Cash surrender values are provided by third parties and reviewed by PHI for reasonableness.

Reconciliations of the beginning and ending balances of PHI’s fair value measurements using significant unobservable inputs (Level 3) for the years ended December 31, 2015 and 2014 are shown below:

	Year Ended December 31,
	2015					2014
	Preferred Stock		Life Insurance Contracts			Preferred Stock		Life Insurance Contracts
	(millions of dollars)
Balance as of January 1	$	3	$	19		$	—	$	19
Total gains (losses) (realized and unrealized):
Included in income		15		5			—		3
Included in accumulated other comprehensive loss		—		—			—		—
Included in regulatory liabilities		—		—			—		—
Purchases		—		—			—		—
Issuances		—		(3	)		3		(3	)
Settlements		—		(2	)		—		—
Transfers in (out) of level 3		—		—			—		—
Balance as of December 31	$	18	$	19		$	3	$	19

The breakdown of realized and unrealized gains on level 3 instruments included in income as a component of Other income or Other operation and maintenance expense for the periods below were as follows:

	Year Ended December 31,
	2015		2014
	(millions of dollars)
Total net gains included in income for the period	$	20	$	3
Change in unrealized gains relating to assets still held at reporting date	$	18	$	3

Other Financial Instruments

The estimated fair values of PHI’s Long-term debt instruments that are measured at amortized cost in PHI’s consolidated financial statements and the associated levels of the estimates within the fair value hierarchy as of December 31, 2015 and 2014 are shown in the tables below. As required by the fair value measurement guidance, debt instruments are classified in their entirety within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. PHI’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, which may affect the valuation of fair value debt instruments and their placement within the fair value hierarchy levels.

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The fair values of Long-term debt and Transition bonds categorized as level 2 are based on a blend of quoted prices for the debt and quoted prices for similar debt on the measurement date. The blend places more weight on current pricing information when determining the final fair value measurement. The fair value information is provided by brokers, and PHI reviews the methodologies and results.

The fair value of Long-term debt categorized as level 3 is based on a discounted cash flow methodology using observable inputs, such as the U.S. Treasury yield, and unobservable inputs, such as credit spreads, because quoted prices for the debt or similar debt in active markets were insufficient. The Long-term project funding represents debt instruments issued by Pepco and Pepco Energy Services related to its energy savings and construction contracts. Long-term project funding is categorized as level 3 because PHI concluded that the amortized cost carrying amounts for these instruments approximate fair value, which does not represent a quoted price in an active market.

	Fair Value Measurements at December 31, 2015
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	5,523	$	—	$	4,941	$	582
Transition Bonds (b)		185		—		185		—
Long-term project funding		5		—		—		5
Total	$	5,713	$	—	$	5,126	$	587

(a) The carrying amount for Long-term debt, net of unamortized discount, was $4,999 million as of December 31, 2015.

(b) The carrying amount for Transition Bonds, including amounts due within one year, was $171 million as of December 31, 2015.

	Fair Value Measurements at December 31, 2014
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	5,583	$	—	$	5,136	$	447
Transition Bonds (b)		235		—		235		—
Long-term project funding		28		—		—		28
Total	$	5,846	$	—	$	5,371	$	475

(a) The carrying amount for Long-term debt, net of unamortized discount, was $4,807 million as of December 31, 2014.

(b) The carrying amount for Transition Bonds, including amounts due within one year, was $215 million as of December 31, 2014.

The carrying amounts of all other financial instruments in the accompanying consolidated financial statements approximate fair value.

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(16) COMMITMENTS AND CONTINGENCIES

General Litigation

From time to time, PHI and its subsidiaries are named as defendants in litigation, usually relating to general liability or auto liability claims that resulted in personal injury or property damage to third parties. PHI and each of its subsidiaries are self-insured against such claims up to a certain self-insured retention amount and maintain insurance coverage against such claims at higher levels, to the extent deemed prudent by management. In addition, PHI’s contracts with its vendors generally require the vendors to name PHI and/or its subsidiaries as additional insureds for the amounts at least equal to PHI’s self-insured retention. Further, PHI’s contracts with its vendors require the vendors to indemnify PHI for various acts and activities that may give rise to claims against PHI. Loss contingency liabilities for both asserted and unasserted claims are recognized if it is probable that a loss will result from such a claim and if the amounts of the losses can be reasonably estimated. Although the outcome of the claims and proceedings cannot be predicted with any certainty, management believes that there are no existing claims or proceedings that are likely to have a material adverse effect on PHI’s or its subsidiaries’ financial condition, results of operations or cash flows. At December 31, 2015, PHI had recorded estimated loss contingency liabilities for general litigation totaling approximately $12 million.

Environmental Matters

PHI, through its subsidiaries, is subject to regulation by various federal, regional, state and local authorities with respect to the environmental effects of its operations, including air and water quality control, solid and hazardous waste disposal and limitations on land use. Although penalties assessed for violations of environmental laws and regulations are not recoverable from customers of PHI’s utility subsidiaries, environmental clean-up costs incurred by Pepco, DPL and ACE generally are included by each company in its respective cost of service for ratemaking purposes. The total accrued liabilities for the environmental contingencies described below of PHI and its subsidiaries at December 31, 2015 are summarized as follows:

				Legacy Generation
	Transmission and Distribution			Regulated			Non-Regulated		Total
				(millions of dollars)
Balance as of January 1	$	17		$	6		$	5	$	28
Accruals		7			3			—		10
Payments		(4	)		(1	)		—		(5	)
Balance as of December 31		20			8			5		33
Less amounts in Other Current Liabilities		3			1			—		4
Amounts in Other Deferred Credits	$	17		$	7		$	5	$	29

Conectiv Energy Wholesale Power Generation Sites

In July 2010, PHI sold the wholesale power generation business of Conectiv Energy Holdings, Inc. and substantially all of its subsidiaries (Conectiv Energy) to Calpine Corporation (Calpine). Under New Jersey’s Industrial Site Recovery Act (ISRA), the transfer of ownership triggered an obligation on the part of Conectiv Energy to remediate any environmental contamination at each of the nine Conectiv Energy generating facility sites located in New Jersey. Under the terms of the sale, Calpine has assumed responsibility for performing the ISRA-required remediation and for the payment of all related ISRA compliance costs up to $10 million. PHI is obligated to indemnify Calpine for any ISRA compliance remediation costs in excess of $10 million. According to PHI’s estimates, the costs of ISRA-required remediation activities at the nine generating facility sites located in New Jersey are in the range of approximately $7 million to $18 million. The amount accrued by PHI for the ISRA-required remediation activities at the nine generating facility sites is included in the table above in the column entitled “Legacy Generation – Non-Regulated.”

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In September 2011, PHI received a request for data from the U.S. Environmental Protection Agency (EPA) regarding operations at the Deepwater generating facility in New Jersey (which was included in the sale to Calpine) between February 2004 and July 1, 2010, to demonstrate compliance with the Clean Air Act’s new source review permitting program. PHI responded to the data request. Under the terms of the Calpine sale, PHI is obligated to indemnify Calpine for any failure of PHI, on or prior to the closing date of the sale, to comply with environmental laws attributable to the construction of new, or modification of existing, sources of air emissions. At this time, PHI does not expect that any financial consequences that could arise from this inquiry would have a material adverse effect on its consolidated financial condition, results of operations or cash flows.

Franklin Slag Pile Site

In November 2008, ACE received a general notice letter from EPA concerning the Franklin Slag Pile site in Philadelphia, Pennsylvania, asserting that ACE is a potentially responsible party (PRP) that may have liability for clean-up costs with respect to the site and for the costs of implementing an EPA-mandated remedy. EPA’s claims are based on ACE’s sale of boiler slag from the B.L. England generating facility, then owned by ACE, to MDC Industries, Inc. (MDC) during the period from June 1978 to May 1983. EPA claims that the boiler slag ACE sold to MDC contained copper and lead, which are hazardous substances under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA), and that the sales transactions may have constituted an arrangement for the disposal or treatment of hazardous substances at the site, which could be a basis for liability under CERCLA. The EPA letter also states that, as of the date of the letter, EPA’s expenditures for response measures at the site have exceeded $6 million. EPA’s feasibility study (FS) for this site conducted in 2007 identified a range of alternatives for permanent remedial measures with varying cost estimates, and the estimated cost of EPA’s preferred alternative is approximately $6 million.

ACE believes that the B.L. England boiler slag sold to MDC was a valuable material with various industrial applications and, therefore, the sale was not an arrangement for the disposal or treatment of any hazardous substances as would be necessary to constitute a basis for liability under CERCLA. ACE intends to contest any claims to the contrary made by EPA. In a May 2009 decision arising under CERCLA, which did not involve ACE, the U.S. Supreme Court rejected an EPA argument that the sale of a useful product constituted an arrangement for disposal or treatment of hazardous substances. While this decision supports ACE’s position, at this time ACE cannot predict how EPA will proceed with respect to the Franklin Slag Pile site, or what portion, if any, of the Franklin Slag Pile site response costs EPA would seek to recover from ACE. Costs to resolve this matter are not expected to be material and are expensed as incurred.

Peck Iron and Metal Site

EPA informed Pepco in a May 2009 letter that Pepco may be a PRP under CERCLA with respect to the cleanup of the Peck Iron and Metal site in Portsmouth, Virginia, and for costs EPA has incurred in cleaning up the site. The EPA letter states that Peck Iron and Metal purchased, processed, stored and shipped metal scrap from military bases, governmental agencies and businesses and that the Peck Iron and Metal scrap operations resulted in the improper storage and disposal of hazardous substances. EPA bases its allegation that Pepco arranged for disposal or treatment of hazardous substances sent to the site on information provided by former Peck Iron and Metal personnel, who informed EPA that Pepco was a customer at the site. Pepco has advised EPA by letter that its records show no evidence of any sale of scrap metal by Pepco to the site. Even if EPA has such records and such sales did occur, Pepco believes that any such scrap metal sales may be entitled to the recyclable material exemption from CERCLA liability. In September 2011, EPA initiated a remedial investigation/feasibility study (RI/FS) for the site using federal funds. Pepco cannot at this time estimate an amount or range of reasonably possible loss associated with this RI/FS, any remediation activities to be performed at the site or any other costs that EPA might seek to impose on Pepco.

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Benning Road Site

Contamination of Lower Anacostia River

In September 2010, PHI received a letter from EPA identifying the Benning Road site as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. A portion of the site was formerly the location of a Pepco Energy Services electric generating facility. That generating facility was deactivated in June 2012 and plant structure demolition was completed in July 2015. The remaining portion of the site consists of a Pepco transmission and distribution service center that remains in operation. The principal contaminants allegedly of concern are polychlorinated biphenyls and polycyclic aromatic hydrocarbons. In December 2011, the U.S. District Court for the District of Columbia approved a consent decree entered into by Pepco and Pepco Energy Services with the District of Columbia Department of Energy and Environment (DOEE) (formerly the District of Columbia Department of the Environment), which requires Pepco and Pepco Energy Services to conduct a RI/FS for the Benning Road site and an approximately 10 to 15 acre portion of the adjacent Anacostia River. The RI/FS will form the basis for the remedial actions for the Benning Road site and for the Anacostia River sediment associated with the site. The consent decree does not obligate Pepco or Pepco Energy Services to pay for or perform any remediation work, but it is anticipated that DOEE will look to Pepco and Pepco Energy Services to assume responsibility for cleanup of any conditions in the river that are determined to be attributable to past activities at the Benning Road site.

The initial remedial investigation field work began in January 2013 and was completed in December 2014. In addition, in conjunction with the power plant demolition activities, Pepco and Pepco Energy Services collected soil samples adjacent to and beneath the concrete basins for the dismantled cooling towers for the generating facility. This sampling showed localized areas of soil contamination associated with the cooling tower basins, and, beginning in the first quarter of 2016, Pepco and Pepco Energy Services expect to implement a plan approved by DOEE to remove contaminated soil in conjunction with the demolition and removal of the concrete basins. On April 30, 2015, Pepco and Pepco Energy Services submitted a draft Remedial Investigation (RI) Report to DOEE. After review, DOEE determined that additional field investigation and data analysis is required to complete the RI process (much of which is beyond the scope of the original DOEE-approved RI work plan). In the meantime, Pepco and Pepco Energy Services will revise the draft RI Report as appropriate to address DOEE’s comments and DOEE will make the draft RI available for public review during the first quarter of 2016. The additional field investigation and data analysis will proceed later in 2016 according to a schedule to be developed by Pepco and Pepco Energy Services and approved by DOEE. Once the additional RI work has been completed, Pepco and Pepco Energy Services will issue a draft “final” RI report for review and comment by DOEE and the public. Pepco and Pepco Energy Services will then proceed with an FS to evaluate possible remedial alternatives. This effort also may include a treatability study to evaluate the effectiveness of potential remedial options. Once the FS has been completed, Pepco and Pepco Energy Services will prepare and submit a draft FS Report for review and comment by DOEE and the public. Thereafter, Pepco and Pepco Energy Services will revise the draft FS Report as appropriate to address comments received and will submit a final FS Report to DOEE.

Upon DOEE’s approval of the final RI and FS Reports, Pepco and Pepco Energy Services will have satisfied their obligations under the consent decree. At that point, DOEE will prepare a Proposed Plan regarding further response actions based on the results of the RI/FS. After considering public comment on the Proposed Plan, DOEE will issue a Record of Decision identifying any further response actions determined to be necessary.

DOEE, Pepco and Pepco Energy Services must submit their next joint status report to the court regarding progress on the RI/FS by May 24, 2016.

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PHI, Pepco and Pepco Energy Services have determined that a loss associated with this matter for PHI, Pepco and Pepco Energy Services is probable and have estimated that the costs of remediation are in the range of approximately $9 million to $13 million.

The remediation costs accrued for this matter are included in the table above in the columns entitled “Transmission and Distribution,” “Legacy Generation – Regulated,” and “Legacy Generation – Non-Regulated.”

NPDES Permit Limit Exceedances

Pepco holds a National Pollutant Discharge Elimination System (NPDES) permit issued by EPA with a July 19, 2009 effective date, which authorizes discharges from the Benning Road site, including the Pepco Energy Services generating facility previously located on the site that was deactivated in 2012 and has been demolished. The 2009 permit for the first time imposed numerical limits on the allowable concentration of certain metals in storm water discharged from the site into the Anacostia River as determined by EPA to be necessary to meet the applicable District of Columbia surface water quality standards. The permit contemplated that Pepco would meet these limits over time through the use of best management practices (BMPs). As of December 2012, Pepco completed the implementation of the first two phases of BMPs identified in a plan approved by EPA (consisting principally of installing metal absorbing filters to capture contaminants at storm water inlets, removing stored equipment from areas exposed to the weather, covering and painting exposed metal pipes, and covering and cleaning dumpsters). These measures were effective in reducing metal concentrations in storm water discharges, but were not sufficient to meet all of the numerical limits for metals. Most of the quarterly monitoring results since the issuance of the permit have shown exceedances of the limits for copper and zinc, as well as occasional exceedances for iron and lead.

The NPDES permit was due to expire on June 19, 2014. Pepco submitted a permit renewal application on December 17, 2013. In November 2014, EPA advised Pepco that it will not renew the permit until the Benning Road site has come into compliance with the existing permit limits. The current permit remains in effect pending EPA’s action on the renewal application. In December 2014, Pepco submitted a plan to EPA to implement the third phase of BMPs recommended in the original permit compliance plan with the objective of achieving full compliance with the permit limits for metals by the end of 2015 and Pepco immediately began to implement the additional BMPs in accordance with the plan. On September 1, 2015, Pepco submitted a report to EPA on the status of implementation of the third phase of BMPs. As of that date, Pepco had fully implemented most of the elements of the Phase 3 plan, including installation of upgraded storm water inlet controls (filters and booms), enhanced inspection and maintenance of inlets, removal of materials and equipment from exposure to storm water, and removal of accumulated sediments from the underground storm drains. The sampling results from the third quarter of 2015 showed compliance with all of the permit limits. The sampling results from the fourth quarter of 2015 showed compliance with all but a single permit limit for metals; the concentration of copper was below the daily maximum limit but exceeded the monthly average limit. As confirmed by this latest sampling, because the permit limits are low and site conditions are subject to variation, Pepco has concluded that some form of storm water treatment prior to discharge will be necessary to ensure ongoing compliance with all permit limits and has begun the process of evaluating treatment options. The nature and scope of the necessary treatment system, and the amount of the associated capital expenditures, will not be known until Pepco has completed the evaluation and design process.

Pepco has been engaged in discussions with representatives from EPA and the DOJ regarding permit compliance. On October 30, 2015, EPA filed a Clean Water Act civil enforcement action against Pepco in federal district court. Pepco expects that this enforcement action will be resolved through a consent decree that will (i) establish further requirements to achieve compliance with the permit limits, including the design and installation of an appropriate storm water treatment system as noted above, and (ii) include civil penalties for past noncompliance. The amount of such penalties is not known or estimable at this time and Pepco does not expect the amount of such penalties to have a material adverse effect on PHI’s consolidated financial condition, results of operations or cash flows.

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Pepco and EPA are currently in discussions regarding the terms of the contemplated consent decree, and it is anticipated that the parties will finalize the consent decree during the first half of 2016. In response to a joint motion by the parties, the court has extended the deadline for Pepco to answer the complaint to May 16, 2016, to give the parties time to work towards agreement on the terms of a consent decree. The parties contemplate seeking a further extension if necessary to complete their negotiations. Once executed by the parties, the consent decree will be filed with the court for review and approval following a period for public comment.

Potomac River Mineral Oil Release

In January 2011, a coupling failure on a transformer cooler pipe resulted in a release of non-toxic mineral oil at Pepco’s Potomac River substation in Alexandria, Virginia. An overflow of an underground secondary containment reservoir resulted in approximately 4,500 gallons of mineral oil flowing into the Potomac River.

In March 2014, Pepco and DOEE entered into a consent decree to resolve a threatened DOEE enforcement action, the terms of which include a combination of a civil penalty and a Supplemental Environmental Project (SEP) with a total cost to Pepco of $875,000. The consent decree was approved and entered by the District of Columbia Superior Court on April 4, 2014. Pepco has paid the $250,000 civil penalty imposed under the consent decree and, pursuant to the consent decree, has made a one-time donation in the amount of $25,000 to the Northeast Environmental Enforcement Training Fund, Inc., a non-profit organization that funds scholarships for environmental enforcement training. The consent decree confirmed that no further actions are required by Pepco to investigate, assess or remediate impacts to the river from the mineral oil release. To implement the SEP, Pepco has entered into an agreement with Living Classrooms Foundation, Inc., a non-profit educational organization, pursuant to which Pepco will provide $600,000 to fund the design, installation and operation of a trash collection system at a storm water outfall that drains to the Anacostia River. DOEE approved the design for the trash collection system and efforts to secure necessary permits are in progress. Pepco expects that this system will be constructed and placed into operation by the end of 2016, which will satisfy Pepco’s obligations under the consent decree. On September 11, 2015, Pepco and DOEE filed a joint report with the D.C. Superior Court on the status of the trash cage project and other elements of the consent decree. The court accepted that report and scheduled the next status hearing in this matter for September 23, 2016.

The consent decree did not resolve potential claims under federal law for natural resource damages resulting from the mineral oil release. Pepco has engaged in separate discussions with DOEE and the federal resource trustees regarding the settlement of a possible natural resource damages claim under federal law. In July 2013, Pepco submitted a natural resource damage assessment to DOEE and the federal trustees that proposed monetary compensation for such damages in the range of $106,000 to $161,000. By letter dated September 16, 2015, the U.S. Department of Interior, on behalf of the trustees, made a confidential counter-proposal for settlement of the natural resource damage claim. Pepco has engaged in subsequent discussions with the trustees and believes that the parties are close to reaching an agreement to settle the claims. Based on the discussions to date, PHI and Pepco do not believe that the resolution of the natural resource damages claim will have a material adverse effect on their respective financial condition, results of operations or cash flows.

As a result of the mineral oil release, Pepco implemented certain interim operational changes to the secondary containment systems at the facility, which involve pumping accumulated storm water to an above-ground holding tank for off-site disposal. Pepco is continuing to use the above-ground holding tank to manage storm water from the secondary containment system while it evaluates other technical and regulatory options.

The amount accrued for this matter is included in the table above in the column entitled “Transmission and Distribution.”

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Metal Bank Site

In the first quarter of 2013, the National Oceanic and Atmospheric Administration (NOAA) contacted Pepco and DPL on behalf of itself and other federal and state trustees to request that Pepco and DPL execute a tolling agreement to facilitate settlement negotiations concerning natural resource damages allegedly caused by releases of hazardous substances, including polychlorinated biphenyls, at the Metal Bank Cottman Avenue Superfund Site located in Philadelphia, Pennsylvania. Pepco and DPL executed a tolling agreement, which has been extended to March 15, 2016, and will continue settlement discussions with the NOAA, the trustees and other PRPs.

The amount accrued for this matter is included in the table above in the column entitled “Transmission and Distribution.”

Brandywine Fly Ash Disposal Site

In February 2013, Pepco received a letter from the Maryland Department of the Environment (MDE) requesting that Pepco investigate the extent of waste on a Pepco right-of-way that traverses the Brandywine fly ash disposal site in Brandywine, Prince George’s County, Maryland, owned by NRG Energy, Inc. (as successor to GenOn MD Ash Management, LLC) (NRG). In July 2013, while reserving its rights and related defenses under a 2000 agreement covering the sale of this site, Pepco indicated its willingness to investigate the extent of, and propose an appropriate closure plan to address, ash on the right-of-way. Pepco submitted a schedule for development of a closure plan to MDE on September 30, 2013 and, by letter dated October 18, 2013, MDE approved the schedule.

PHI and Pepco have determined that a loss associated with this matter for PHI and Pepco is probable and have estimated that the costs for implementation of a closure plan and cap on the site are in the range of approximately $3 million to $6 million. PHI and Pepco believe that the costs incurred in this matter will be recoverable from NRG under the 2000 sale agreement.

The amount accrued for this matter is included in the table above in the column entitled “Transmission and Distribution.”

Virginia Department of Environmental Quality Notice of Violation

On February 3, 2015, the Virginia Department of Environmental Quality (VDEQ) issued a notice of violation (NOV) to DPL in connection with alleged violations of state water control laws and regulations associated with recent construction activities undertaken to replace certain transmission facilities. The NOV informed DPL of information on which VDEQ may rely to institute an administrative or judicial enforcement action, requested a meeting, and stated that DPL may be asked to enter into a consent order to formalize a plan and schedule of corrective action and settle any outstanding issues regarding the matter including the assessment of civil charges. At a February 20, 2015 meeting, VDEQ confirmed that the NOV would be resolved through a consent order, which will require the payment of a penalty, but did not specify the potential penalty amount. DPL will pursue recovery of the restoration costs for this matter from the contractor responsible for the vegetation management activities that gave rise to the alleged violations. PHI and DPL have substantially completed all remediation activities related to this matter and do not believe that the potential penalty to resolve this matter will have a material adverse effect on their respective financial condition, results of operations or cash flows.

Rock Creek Mineral Oil Release

In late August 2015, a Pepco underground transmission line in the District of Columbia suffered a breach, resulting in the release of non-toxic mineral oil surrounding the transmission line into the surrounding soil, and a small amount also reached Rock Creek through a storm drain. Pepco notified regulatory authorities, and Pepco and its spill response contractors placed booms in Rock Creek, blocked the storm drain to prevent the release of mineral oil into the creek and commenced remediation of soil around the

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transmission line and the Rock Creek shoreline. Pepco estimates that approximately 6,100 gallons of mineral oil were released and that its remediation efforts recovered approximately 80 percent of the amount released. Pepco’s remediation efforts are ongoing under the direction of the DOEE and in collaboration with the National Park Service, the Smithsonian Institution/National Zoo and EPA. Pepco’s investigation presently indicates that the damage to Pepco’s facilities occurred prior to the release of mineral oil when third-party excavators struck the Pepco underground transmission line while installing cable for another utility.

To the extent recovery is available against any party who contributed to this loss, PHI and Pepco will pursue such action. PHI and Pepco continue to investigate the cause of the incident, the parties involved, and legal responsibility under District of Columbia law, but do not believe that the remediation costs to resolve this matter will have a material adverse effect on their respective financial condition, results of operations or cash flows.

PHI’s Cross-Border Energy Lease Investments

PHI held a portfolio of cross-border energy lease investments involving public utility assets located outside of the United States. Each of these investments was comprised of multiple leases and was structured as a sale and leaseback transaction commonly referred to by the IRS as a SILO transaction. During the second and third quarters of 2013, PHI terminated early all of its remaining cross-border energy lease investments.

Since 2005, PHI’s former cross-border energy lease investments have been under examination by the IRS as part of the PHI federal income tax audits. In connection with the audit of PHI’s 2001-2002 income tax returns, the IRS disallowed the depreciation and interest deductions in excess of rental income claimed by PHI for six of the eight lease investments and, in connection with the audits of PHI’s 2003-2005 and 2006-2008 income tax returns, the IRS disallowed such deductions in excess of rental income for all eight of the lease investments. In addition, the IRS has sought to recharacterize each of the leases as a loan transaction in each of the years under audit as to which PHI would be subject to original issue discount income. PHI had disagreed with the IRS’ proposed adjustments to the 2001-2008 income tax returns and filed protests of these findings for each year with the Office of Appeals of the IRS. In November 2010, PHI entered into a settlement agreement with the IRS for the 2001 and 2002 tax years for the purpose of commencing litigation associated with this matter and subsequently filed refund claims in July 2011 for the disallowed tax deductions relating to the leases for these years. In January 2011, as part of this settlement, PHI paid $74 million of additional tax for 2001 and 2002, penalties of $1 million, and $28 million in interest associated with the disallowed deductions. Since the July 2011 refund claims were not approved by the IRS within the statutory six-month period, in January 2012 PHI filed complaints in the U.S. Court of Federal Claims seeking recovery of the tax payment, interest and penalties.

On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States (to which PHI is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. While PHI believed that its tax position with regard to its former cross-border energy lease investments was appropriate, after analyzing the recent U.S. Court of Appeals ruling, PHI determined in the first quarter of 2013 that its tax position with respect to the tax benefits associated with the cross-border energy leases no longer met the more-likely-than-not standard of recognition for accounting purposes. Accordingly, PHI recorded a non-cash after-tax charge of $377 million in the first quarter of 2013 consisting of a charge to reduce the carrying value of the cross-border energy lease investments and a charge to reflect the anticipated additional interest expense related to changes in PHI’s estimated federal and state income tax obligations for the period over which the tax benefits ultimately may be disallowed. PHI had also previously made certain business assumptions regarding foreign investment opportunities available at the end of the full lease terms. During the first quarter of 2013, management believed that its conclusions regarding these business assumptions were no longer supportable, and the tax effects of this change in conclusion were included in the charge. While the IRS could require PHI to pay a penalty of up to 20% of the amount of additional taxes due, PHI believed that it was more likely than not that no such penalty would be incurred, and therefore no amount for any potential penalty had been recorded.

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Assuming that the IRS were to be successful in disallowing 100% of the tax benefits associated with these lease investments and recharacterize these lease investments as loans, PHI estimated that, as of March 31, 2013, it would have been obligated to pay approximately $192 million in additional federal taxes (net of the $74 million tax payment described above) and approximately $50 million of interest on the additional federal taxes. These amounts, totaling $242 million, were estimated after consideration of certain tax benefits arising from matters unrelated to the leases that would offset the taxes and interest due, including PHI’s best estimate of the expected resolution of other uncertain and effectively settled tax positions, the carrying back and carrying forward of any existing net operating losses, and the application of certain amounts paid in advance to the IRS. In order to mitigate PHI’s ongoing interest costs associated with the $242 million estimate of additional taxes and interest, PHI made an advanced payment to the IRS of $242 million in the first quarter of 2013. This advanced payment was funded from currently available sources of liquidity and short-term borrowings. A portion of the proceeds from lease terminations effected during the second and third quarters of 2013 was used to repay the short-term borrowings utilized to fund the advanced payment.

On November 18, 2015, PHI entered into the Global Tax Settlement with the IRS and the DOJ to provide for the resolution of the tax treatment of its previously held cross-border energy lease investments structured as SILO transactions. As a result of the Global Tax Settlement, PHI and the DOJ filed stipulations of dismissal regarding the litigation in the U.S. Court of Federal Claims. The Court dismissed the complaint on November 20, 2015. For additional discussion on the Global Tax Settlement with the IRS, see Note (11), “Income Taxes.”

Third Party Guarantees, Indemnifications, and Off-Balance Sheet Arrangements

PHI and certain of its subsidiaries have various financial and performance guarantees and indemnification obligations that they have entered into in the normal course of business to facilitate commercial transactions with third parties as discussed below.

As of December 31, 2015, PHI and its subsidiaries were parties to a variety of agreements pursuant to which they were guarantors. The commitments and obligations were as follows:

	Guarantor
	PHI		Pepco		DPL		ACE		Total
	(millions of dollars)
Guarantees associated with disposal of Conectiv Energy assets (a)	$	13	$	—	$	—	$	—	$	13
Guaranteed lease residual values (b)		3		5		6		5		19
Total	$	16	$	5	$	6	$	5	$	32

(a) Represents guarantees by PHI of Conectiv Energy’s derivative portfolio transferred in connection with the disposition of Conectiv Energy’s wholesale business. The derivative portfolio guarantee is currently $13 million and covers Conectiv Energy’s performance prior to the assignment. The guarantee was terminated in January 2016.

(b) Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $52 million, $9 million of which is a guarantee by PHI, $13 million by Pepco, $16 million by DPL and $14 million by ACE. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.

PHI and certain of its subsidiaries have entered into various indemnification agreements related to purchase and sale agreements and other types of contractual agreements with vendors and other third

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parties. These indemnification agreements typically cover environmental, tax, litigation and other matters, as well as breaches of representations, warranties and covenants set forth in these agreements. Typically, claims may be made by third parties under these indemnification agreements over various periods of time depending on the nature of the claim. The maximum potential exposure under these indemnification agreements can range from a specified dollar amount to an unlimited amount depending on the nature of the claim and the particular transaction. The total maximum potential amount of future payments under these indemnification agreements is not estimable due to several factors, including uncertainty as to whether or when claims may be made under these indemnities.

Energy Services Performance Contracts

Pepco Energy Services has a diverse portfolio of energy savings services performance contracts that are associated with the installation of energy savings equipment or combined heat and power facilities for federal, state and local government customers. As part of the energy savings contracts, Pepco Energy Services typically guarantees that the equipment or systems it installs will generate a specified amount of energy savings on an annual basis over a multi-year period. As of December 31, 2015 the remaining notional amount of Pepco Energy Services’ energy savings guarantees over the life of the multi-year performance contracts on: (i) completed projects was $221 million, with the longest guarantee having a remaining term of 23 years; and, (ii) projects under construction was $55 million, with the longest guarantee having a term of 19 years after completion of construction. On an annual basis, Pepco Energy Services undertakes a measurement and verification process to determine the amount of energy savings for the year and whether there is any shortfall in the annual energy savings compared to the guaranteed amount.

As of December 31, 2015, Pepco Energy Services had a performance guarantee contract associated with the production at a combined heat and power facility that is under construction totaling $15 million in notional value over 20 years.

Pepco Energy Services recognizes a liability for the value of the estimated energy savings or production shortfalls when it is probable that the guaranteed amounts will not be achieved and the amount is reasonably estimable. As of December 31, 2015, Pepco Energy Services had an accrued liability of $1 million for its energy savings contracts that it established during 2012. There was no significant change in the type of contracts issued during the year ended December 31, 2015 as compared to the year ended December 31, 2014.

Contractual Obligations

Power Purchase Contracts

As of December 31, 2015, Pepco Holdings’ contractual obligations under non-derivative power purchase contracts were $268 million in 2016, $469 million in 2017 to 2018, $472 million in 2019 to 2020 and $993 million thereafter.

Lease Commitments

Rental expense for operating leases was $60 million, $59 million and $54 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Total future minimum operating lease payments for Pepco Holdings as of December 31, 2015 are $52 million in 2016, $48 million in 2017, $47 million in 2018, $34 million in 2019, $37 million in 2020 and $304 million thereafter.

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(17) VARIABLE INTEREST ENTITIES

PHI is required to consolidate a VIE in accordance with FASB ASC 810 if PHI or a subsidiary is the primary beneficiary of the VIE. The primary beneficiary of a VIE is typically the entity with both the power to direct activities most significantly impacting economic performance of the VIE and the obligation to absorb losses or receive benefits of the VIE that could potentially be significant to the VIE. PHI performs a qualitative analysis to determine whether a variable interest provides a controlling financial interest in any of the VIEs in which PHI or its subsidiaries have an interest. Set forth below are the relationships with respect to which PHI conducted a VIE analysis as of December 31, 2015:

DPL Renewable Energy Transactions

DPL is subject to Renewable Energy Portfolio Standards (RPS) in the state of Delaware that require it to obtain renewable energy credits (RECs) for energy delivered to its customers. DPL’s costs associated with obtaining RECs to fulfill its RPS obligations are recoverable from its customers by law. As of December 31, 2015, DPL is a party to three land-based wind PPAs in the aggregate amount of 128 MWs, one solar PPA with a 10 MW facility, and a PPA with the Delaware Sustainable Energy Utility (DSEU) to purchase solar renewable energy credits (SRECs). Each of the facilities associated with these PPAs is operational, except for the facilities associated with the PPA with the DSEU, which are expected to be operational within one year. DPL is obligated to purchase energy and RECs in amounts generated and delivered by the wind facilities and SRECs from the solar facility and the DSEU, up to certain amounts (as set forth below) at rates that are primarily fixed under the respective agreements. PHI and DPL have concluded that while VIEs exist under these contracts, consolidation is not required under FASB ASC 810 as DPL is not the primary beneficiary. DPL has not provided financial or other support under these arrangements that it was not previously contractually required to provide during the periods presented, and DPL does not have any intention to provide such additional support.

Because DPL has no equity or debt interest in these renewable energy transactions, the maximum exposure to loss relates primarily to any above-market costs incurred for power, RECs or SRECs. Due to unpredictability in the amount of MWs ultimately purchased under the agreements for purchased renewable energy, RECs and SRECs, PHI and DPL are unable to quantify the maximum exposure to loss, however, the power purchase, REC and SREC costs are recoverable from DPL’s customers through regulated rates.

Wind PPAs

DPL is obligated to purchase energy and RECs from one of the wind facilities through 2024 in amounts not to exceed 50 MWs, from the second wind facility through 2031 in amounts not to exceed 40 MWs, and from the third wind facility through 2031 in amounts not to exceed 38 MWs. DPL’s aggregate purchases under the three wind PPAs totaled $29 million, $31 million and $30 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Solar PPAs

The term of the PPA with the solar facility is through 2030 and DPL is obligated to purchase SRECs in an amount up to 70 percent of the energy output at a fixed price. The DSEU may enter into 20-year contracts with solar facilities to purchase SRECs for resale to DPL. Under the PPA with the DSEU, at December 31, 2015 and 2014, DPL was obligated to purchase SRECs in amounts not to exceed 28 MWs and 19 MWs, respectively, at annually determined auction rates. DPL’s purchases under these solar PPAs totaled $6 million, $6 million and $3 million for the years ended December 31, 2015, 2014 and 2013, respectively.

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Fuel Cell Facilities

On October 18, 2011, the DPSC approved a tariff submitted by DPL in accordance with the requirements of the RPS specific to fuel cell facilities totaling 30 MWs to be constructed by a qualified fuel cell provider. The tariff and the RPS establish that DPL acts solely as an agent to collect payments in advance from its distribution customers and remit them to the qualified fuel cell provider for each megawatt hour (MWh) of energy produced by the fuel cell facilities through 2033. The RPS provides for a reduction in DPL’s REC requirements based upon the actual energy output of the facilities. PHI and DPL have concluded that while a VIE exists as a result of this relationship, consolidation is not required under FASB ASC 810 as DPL is not the primary beneficiary. For the years ended December 31, 2015 and 2014, 227,113 and 222,948 MWhs, respectively, were produced from fuel cell facilities placed in service under the tariff. DPL billed $37 million, $36 million and $23 million to distribution customers for the years ended December 31, 2015, 2014 and 2013, respectively.

ACE Power Purchase Agreements

ACE is a party to three PPAs with unaffiliated NUGs totaling 459 MWs. One of the agreements ends in 2016 and the other two end in 2024. PHI and ACE have no equity or debt invested in these entities. In performing its VIE analysis, PHI has been unable to obtain sufficient information to determine whether these three entities were variable interest entities or if ACE was the primary beneficiary. As a result, PHI has applied the scope exemption from the consolidation guidance.

Because ACE has no equity or debt invested in the NUGs, the maximum exposure to loss relates primarily to any above-market costs incurred for power. Due to unpredictability in the pricing for purchased energy under the PPAs, PHI and ACE are unable to quantify the maximum exposure to loss. The power purchase costs are recoverable from ACE’s customers through regulated rates. Purchase activities with the NUGs, including excess power purchases not covered by the PPAs, for the years ended December 31, 2015, 2014 and 2013, were approximately $208 million, $233 million and $221 million, respectively, of which approximately $198 million, $208 million and $206 million, respectively, consisted of power purchases under the PPAs.

ACE Funding

In 2001, ACE established ACE Funding solely for the purpose of securitizing authorized portions of ACE’s recoverable stranded costs through the issuance and sale of Transition Bonds. The proceeds of the sale of each series of Transition Bonds were transferred to ACE in exchange for the transfer by ACE to ACE Funding of the right to collect a non-bypassable Transition Bond Charge (representing revenue ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds and related taxes, expenses and fees) from ACE customers pursuant to bondable stranded costs rate orders issued by the NJBPU in an amount sufficient to fund the principal and interest payments on the Transition Bonds and related taxes, expenses and fees (Bondable Transition Property). The assets of ACE Funding, including the Bondable Transition Property, and the Transition Bond Charges collected from ACE’s customers, are not available to creditors of ACE. The holders of Transition Bonds have recourse only to the assets of ACE Funding. ACE owns 100 percent of the equity of ACE Funding, and PHI and ACE consolidate ACE Funding in their consolidated financial statements as ACE is the primary beneficiary of ACE Funding under the variable interest entity consolidation guidance.

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(18) ACCUMULATED OTHER COMPREHENSIVE LOSS

The components of Pepco Holdings’ AOCL relating to continuing and discontinued operations are as follows. For additional information, see the consolidated statements of comprehensive income.

	Year Ended December 31,
	2015			2014			2013
	(millions of dollars)
Balance as of January 1	$	(46	)	$	(34	)	$	(48	)
Treasury Lock
Balance as of January 1		(9	)		(9	)		(10	)
Amount of pre-tax loss reclassified to Interest expense		1			1			1
Income tax expense		—			1			—
Balance as of December 31		(8	)		(9	)		(9	)
Pension and Other Postretirement Benefits
Balance as of January 1		(37	)		(25	)		(32	)
Amount of amortization of net prior service cost and actuarial loss reclassified to Other operation and maintenance expense		6			5			5
Amount of net prior service cost and actuarial gain (loss) arising during the year		9			(25	)		8
Income tax (benefit) expense		6			(8	)		6
Balance as of December 31		(28	)		(37	)		(25	)
Commodity Derivatives
Balance as of January 1		—			—			(6	)
Amount of net pre-tax loss reclassified to Income (loss) from discontinued operations before income tax		—			—			10
Income tax expense		—			—			4
Balance as of December 31		—			—			—
Balance as of December 31	$	(36	)	$	(46	)	$	(34	)

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(19) QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

The quarterly data presented below reflect all adjustments necessary in the opinion of management for a fair presentation of the interim results. Quarterly data normally vary seasonally because of temperature variations and differences between summer and winter rates. The totals of the four quarterly basic and diluted earnings per common share amounts may not equal the basic and diluted earnings per common share for the year due to changes in the number of shares of common stock outstanding during the year.

	2015
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(millions of dollars, except per share amounts)
Total Operating Revenue	$	1,371		$	1,140		$	1,362		$	1,150		$	5,023
Total Operating Expenses		1,229			1,001			1,179			941	(b)		4,350
Operating Income		142			139			183			209			673
Other Expenses		(59	)		(59	)		(43	)(a)		(65)			(226)
Income from Continuing Operations Before Income Tax Expense		83			80			140			144			447
Income Tax Expense Related to Continuing Operations		30			27			49			23	(c)		129
Net Income From Continuing Operations		53			53			91			121			318
Income from Discontinued Operations, net of taxes		—			—			—			9	(d)		9
Net Income	$	53		$	53		$	91		$	130		$	327
Basic and Diluted Earnings Per Share of Common Stock:
Earnings Per Share of Common Stock from Continuing Operations	$	0.21		$	0.21		$	0.36		$	0.48		$	1.25
Earnings Per Share of Common Stock from Discontinued Operations	$	—		$	—		$	—		$	0.03		$	0.04
Earnings Per Share of Common Stock	$	0.21		$	0.21		$	0.36		$	0.51		$	1.29
Cash Dividends Per Share of Common Stock	$	0.27		$	0.27		$	0.27		$	0.27		$	1.08

(a) Includes $15 million ($10 million after-tax) increase in fair value of preferred stock derivative.

(b) Includes gains of $46 million ($27 million after-tax) associated with the sale of Pepco non-utility land.

(c) Includes income tax benefit of $47 million associated with the Global Tax Settlement and a tax charge of $7 million to correct prior period errors.

(d) Includes income tax benefit of $9 million associated with the Global Tax Settlement.

	2014
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(millions of dollars, except per share amounts)
Total Operating Revenue (a)	$	1,330		$	1,117		$	1,313		$	1,118		$	4,878
Total Operating Expenses (b)		1,157			966			1,147			1,004	(c)		4,274
Operating Income		173			151			166			114			604
Other Expenses		(52	)		(53	)		(53	)		(66	)		(224	)
Income from Continuing Operations Before Income Tax Expense		121			98			113			48			380
Income Tax Expense Related to Continuing Operations		46			45			34			13			138
Net Income	$	75		$	53		$	79		$	35		$	242
Basic and Diluted Earnings Per Share of Common Stock	$	0.30		$	0.21		$	0.31		$	0.14		$	0.96
Cash Dividends Per Share of Common Stock	$	0.27		$	0.27		$	0.27		$	0.27		$	1.08

(a) During the fourth quarter of 2014, ACE reversed unbilled revenue of $3 million ($2 million after-tax) to correct an error that had overstated operating revenue in the third quarter of 2014.

(b) Includes pre-tax impairment losses of $53 million ($32 million after-tax) and $28 million ($16 million after-tax) in the third and fourth quarters of 2014, respectively, at Pepco Energy Services associated with its combined heat and power thermal generating facilities and operations in Atlantic City.

(c) Includes a charge of $3 million ($2 million after-tax) to correct a prior period error related to the recoverability of certain regulatory assets at ACE.

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(20) DISCONTINUED OPERATIONS

PHI’s income (loss) from discontinued operations, net of income taxes, is comprised of the following:

	For the Year Ended December 31,
	2015		2014		2013
	(millions of dollars)
Cross-border energy lease investments	$	9	$	—	$	(327	)
Pepco Energy Services’ retail electric and natural gas supply businesses		—		—		5
Income (loss) from discontinued operations, net of income taxes	$	9	$	—	$	(322	)

Cross-Border Energy Lease Investments

Between 1994 and 2002, PCI entered into cross-border energy lease investments consisting of hydroelectric generation facilities, coal-fired electric generation facilities and natural gas distribution networks located outside of the United States. Each of these lease investments was structured as a sale and leaseback transaction commonly referred to as a SILO transaction. During the second and third quarters of 2013, PHI terminated early all of its interests in the remaining lease investments. PHI received aggregate net cash proceeds from these early terminations of $873 million (net of aggregate termination payments of $2.0 billion used to retire the non-recourse debt associated with the terminated leases) and recorded an aggregate pre-tax loss, including transaction costs, of approximately $3 million ($2 million after-tax), representing the excess of the carrying value of the terminated leases over the net cash proceeds received. As a result, PHI has reported the results of operations of the cross-border energy lease investments as discontinued operations in all periods presented in the accompanying consolidated statements of income (loss).

Operating Results

The operating results for the cross-border energy lease investments are as follows:

	For the Year Ended December 31,
	2015		2014		2013
	(millions of dollars)
Operating revenue from PHI’s cross-border energy lease investments	$	—	$	—	$	7
Non-cash charge to reduce carrying value of PHI’s cross-border energy lease investments		—		—		(373	)
Total operating revenue	$	—	$	—	$	(366	)
Income (loss) from operations of discontinued operations, net of income taxes (a)	$	9	$	—	$	(325	)
Net losses associated with the early termination of the cross-border energy lease investments, net of income taxes		—		—		(2	)
Income (loss) from discontinued operations, net of income taxes	$	9	$	—	$	(327	)

(a) Includes income tax benefit of approximately $9 million and $44 million for the years ended December 31, 2015 and 2013, respectively.

On November 18, 2015, PHI entered into the Global Tax Settlement, as described in Note (11), “Income Taxes.” As a result of the Global Tax Settlement, PHI recorded in the fourth quarter of 2015 a tax benefit of $9 million associated with the cross-border energy lease investments. Substantially all of the tax benefit recorded represents uncertain tax positions that were settled in favor of PHI in the Global Tax Settlement.

On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States (to which PHI is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. As a result

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of the court’s ruling in this case, PHI determined in the first quarter of 2013 that its tax position with respect to the benefits associated with its cross-border energy leases no longer met the more-likely-than-not standard of recognition for accounting purposes, and PCI recorded after-tax non-cash charges of $323 million in the first quarter of 2013 and $6 million in the second quarter of 2013, consisting of the following components:

• A non-cash pre-tax charge of $373 million ($313 million after-tax) to reduce the carrying value of these cross-border energy lease investments under FASB guidance on leases (ASC 840). This pre-tax charge was originally recorded in the consolidated statements of income (loss) as a reduction in operating revenue and is now reflected in income (loss) from discontinued operations, net of income taxes.

• A non-cash charge of $16 million after-tax to reflect the anticipated additional net interest expense under FASB guidance for income taxes (ASC 740) related to estimated federal and state income tax obligations for the period over which the tax benefits may be disallowed. This after-tax charge was originally recorded in the consolidated statements of income (loss) as an increase in income tax expense and is now reflected in income (loss) from discontinued operations, net of income taxes. The after-tax interest charge for PHI on a consolidated basis was $70 million and this amount was allocated to each member of PHI’s consolidated group as if each member was a separate taxpayer, resulting in the recognition of a $12 million interest benefit for the Power Delivery segment, and interest expense of $16 million for PCI and $66 million for Corporate and Other, respectively.

PHI had also previously made certain business assumptions regarding foreign investment opportunities available at the end of the full lease terms. In view of the change in PHI’s tax position with respect to the tax benefits associated with the cross-border energy lease investments and PHI’s resulting decision to pursue the early termination of these investments, management concluded in the first quarter of 2013 that these business assumptions were no longer supportable and the tax effects of this conclusion were reflected in the after-tax charge of $313 million described above.

PHI accrued no penalties associated with its re-assessment of the likely outcome of tax positions associated with the cross-border energy lease investments. No penalties were incurred by PHI in connection with the Global Tax Settlement.

For additional information concerning these cross-border energy lease investments, see Note (16), “Commitments and Contingencies – PHI’s Cross-Border Energy Lease Investments.”

Retail Electric and Natural Gas Supply Businesses of Pepco Energy Services

On March 21, 2013, Pepco Energy Services entered into an agreement whereby a third party assumed all the rights and obligations of the remaining natural gas supply customer contracts, and the associated supply obligations, inventory and derivative contracts. The transaction was completed on April 1, 2013. In addition, in the second quarter of 2013, Pepco Energy Services completed the wind-down of its retail electric supply business by terminating its remaining customer supply and wholesale purchase obligations beyond June 30, 2013. As a result, PHI has reported the results of operations of Pepco Energy Services’ retail electric and natural gas supply businesses as discontinued operations in all periods presented in the accompanying consolidated statements of income (loss).

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Operating Results

The operating results for the retail electric and natural gas supply businesses of Pepco Energy Services are as follows:

	For the Year Ended December 31,
	2015		2014		2013
	(millions of dollars)
Operating revenue	$	—	$	—	$	84
Income from operations of discontinued operations, net of income taxes	$	—	$	—	$	4
Net gains associated with accelerated disposition of retail electric and natural gas contracts, net of income taxes		—		—		1
Income from discontinued operations, net of income taxes (a)	$	—	$	—	$	5

(a) Includes income tax expense of approximately $3 million for the year ended December 31, 2013.

Derivative Instruments and Hedging Activities

Derivatives were used by the retail electric and natural gas supply businesses of Pepco Energy Services to hedge commodity price risk. There were no outstanding forward contracts or derivative positions for Pepco Energy Services as of December 31, 2015, 2014 and 2013.

Derivatives Designated as Hedging Instruments

At December 31, 2012, the cumulative net pre-tax loss related to effective cash flow hedges of the retail electric and natural gas supply businesses of Pepco Energy Services included in AOCL was $10 million ($6 million after-tax). With the assumption by a third party, on April 1, 2013, of all the rights and obligations of the derivative contracts associated with the retail natural gas supply business, PHI determined that the hedged forecasted purchases of supply for retail natural gas customers were probable not to occur. Accordingly, during the first quarter of 2013, PHI recognized $4 million of pre-tax unrealized derivative losses ($2 million after-tax) that were previously included in AOCL as cash flow hedges. The remaining pre-tax loss of $6 million included in AOCL was reclassified into income on completion of the wind-down of the retail electric business in the second quarter of 2013.

Other Derivative Activity

The retail electric and natural gas supply businesses of Pepco Energy Services held certain derivatives that were not in hedge accounting relationships and were not designated as normal purchases or normal sales. These derivatives were recorded at fair value on the balance sheet with the gain or loss for changes in fair value recorded through Income (loss) from discontinued operations, net of income taxes.

For the years ended December 31, 2015, 2014, and 2013, the amount of the derivative gain (loss) for the retail electric and natural gas supply businesses of Pepco Energy Services recognized in Income (loss) from discontinued operations, net of income taxes is provided in the table below:

	For the Year Ended December 31,
	2015		2014		2013
	(millions of dollars)
Reclassification of mark-to-market to realized on settlement of contracts	$	—	$	—	$	10
Unrealized mark-to-market loss		—		—		—
Total net gain	$	—	$	—	$	10

As of December 31, 2015, 2014 and 2013, the retail electric and natural gas supply businesses of Pepco Energy Services had no outstanding commodity forward contracts or derivative positions.

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Management’s Report on Internal Control Over Financial Reporting

The management of Potomac Electric Power Company (Pepco) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management of Pepco assessed Pepco’s internal control over financial reporting as of December 31, 2015 based on criteria established in the Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its assessment, the management of Pepco concluded that Pepco’s internal control over financial reporting was effective as of December 31, 2015.

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Report of Independent Registered Public Accounting Firm

To the Shareholder and Board of Directors of

Potomac Electric Power Company

In our opinion, the financial statements of Potomac Electric Power Company (a wholly owned subsidiary of Pepco Holdings, Inc.) listed in the accompanying index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Potomac Electric Power Company at December 31, 2015 and December 31, 2014, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2015 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule of Potomac Electric Power Company listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Washington, D.C.

February 18, 2016

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POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF INCOME

For the Year Ended December 31,	2015			2014			2013
	(millions of dollars)
Operating Revenue	$	2,189		$	2,101		$	2,026
Operating Expenses
Purchased energy		763			771			750
Other operation and maintenance		441			390			391
Depreciation and amortization		277			229			196
Other taxes		369			363			368
Gains on sales of land		(46	)		—			—
Total Operating Expenses		1,804			1,753			1,705
Operating Income		385			348			321
Other Income (Expenses)
Interest expense		(123	)		(115	)		(110	)
Other income		23			30			18
Total Other Expenses		(100	)		(85	)		(92	)
Income Before Income Tax Expense		285			263			229
Income Tax Expense		98			92			79
Net Income	$	187		$	171		$	150

The accompanying Notes are an integral part of these Financial Statements.

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POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

ASSETS	December 31, 2015			December 31, 2014
	(millions of dollars)
CURRENT ASSETS
Cash and cash equivalents	$	5		$	6
Restricted cash equivalents		2			5
Accounts receivable, less allowance for uncollectible accounts of $17 million and $16 million, respectively		346			315
Inventories		67			62
Income taxes and related accrued interest receivable		170			94
Prepaid expenses and other		20			21
Total Current Assets		610			503
OTHER ASSETS
Regulatory assets		720			697
Prepaid pension expense		291			316
Investment in trust		27			34
Income taxes and related accrued interest receivable		3			30
Other		42			43
Total Other Assets		1,083			1,120
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		8,091			7,764
Accumulated depreciation		(2,799	)		(2,816	)
Net Property, Plant and Equipment		5,292			4,948
TOTAL ASSETS	$	6,985		$	6,571

The accompanying Notes are an integral part of these Financial Statements.

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POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

LIABILITIES AND EQUITY	December 31, 2015		December 31, 2014
	(millions of dollars, except shares)
CURRENT LIABILITIES
Short-term debt	$	64	$	104
Current portion of long-term debt and project funding		—		12
Accounts payable		87		94
Accrued liabilities		101		91
Accounts payable due to associated companies		30		30
Capital lease obligations due within one year		11		10
Taxes accrued		37		32
Interest accrued		22		19
Liabilities and accrued interest related to uncertain tax positions		3		—
Customer deposits		46		44
Other		68		93
Total Current Liabilities		469		529
DEFERRED CREDITS
Regulatory liabilities		92		104
Deferred income tax liabilities, net		1,721		1,579
Investment tax credits		2		2
Other postretirement benefit obligations		49		57
Other		72		67
Total Deferred Credits		1,936		1,809
OTHER LONG-TERM LIABILITIES
Long-term debt		2,301		2,096
Capital lease obligations		39		50
Total Other Long-Term Liabilities		2,340		2,146
COMMITMENTS AND CONTINGENCIES (NOTE 12)
EQUITY
Common stock, $.01 par value, 200,000,000 shares authorized, 100 shares outstanding		—		—
Premium on stock and other capital contributions		1,122		1,010
Retained earnings		1,118		1,077
Total Equity		2,240		2,087
TOTAL LIABILITIES AND EQUITY	$	6,985	$	6,571

The accompanying Notes are an integral part of these Financial Statements.

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POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF CASH FLOWS

For the Year Ended December 31,	2015			2014			2013
	(millions of dollars)
OPERATING ACTIVITIES
Net Income	$	187		$	171		$	150
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		277			229			196
Deferred income taxes		149			174			120
Gains on sales of land		(46	)		—			—
Investment tax credit amortization		—			—			(1	)
Other		—			(9	)		—
Changes in:
Accounts receivable		(32	)		27			(39	)
Inventories		(5	)		5			2
Prepaid expenses		2			(2	)		(1	)
Regulatory assets and liabilities, net		(129	)		(163	)		(99	)
Prepaid pension expense, excluding contributions		24			16			21
Accounts payable and accrued liabilities		(19	)		(34	)		26
Income tax-related prepayments, receivables and payables		(40	)		(25	)		(36	)
Interest accrued		2			—			2
Other assets and liabilities		3			(3	)		(11	)
Net Cash From Operating Activities		373			386			330
INVESTING ACTIVITIES
Investment in property, plant and equipment		(544	)		(567	)		(576	)
Department of Energy capital reimbursement awards received		—			3			20
Proceeds from sales of land		54			—			—
Changes in restricted cash equivalents		3			(3	)		(3	)
Net other investing activities		10			7			(5	)
Net Cash Used By Investing Activities		(477	)		(560	)		(564	)
FINANCING ACTIVITIES
Dividends paid to Parent		(146	)		(86	)		(46	)
Capital contributions from Parent		112			80			175
Issuances of long-term debt		208			412			400
Reacquisitions of long-term debt		(12	)		(175	)		(200	)
Repayments of short-term debt, net		(40	)		(47	)		(80	)
Cost of issuances		(4	)		(7	)		(7	)
Net other financing activities		(15	)		(6	)		(8	)
Net Cash From Financing Activities		103			171			234
Net Decrease in Cash and Cash Equivalents		(1	)		(3	)		—
Cash and Cash Equivalents at Beginning of Year		6			9			9
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	5		$	6		$	9
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for interest (net of capitalized interest of $7 million, $5 million and $5 million, respectively)	$	116		$	111		$	102
Cash received for income taxes (includes payments from PHI for Federal income taxes)		(6	)		(58	)		(28	)

The accompanying Notes are an integral part of these Financial Statements.

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POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF EQUITY

	Common Stock				Premium		Retained
(millions of dollars, except shares)	Shares		Par Value		on Stock		Earnings			Total
Balance as of December 31, 2012		100	$	—	$	755	$	888		$	1,643
Net Income		—		—		—		150			150
Capital contribution from Parent		—		—		175		—			175
Dividends on common stock		—		—		—		(46	)		(46	)
Balance as of December 31, 2013		100		—		930		992			1,922
Net Income		—		—		—		171			171
Capital contribution from Parent		—		—		80		—			80
Dividends on common stock		—		—		—		(86	)		(86	)
Balance as of December 31, 2014		100		—		1,010		1,077			2,087
Net Income		—		—		—		187			187
Capital contribution from Parent		—		—		112		—			112
Dividends on common stock		—		—		—		(146	)		(146	)
Balance as of December 31, 2015		100	$	—	$	1,122	$	1,118		$	2,240

The accompanying Notes are an integral part of these Financial Statements.

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NOTES TO FINANCIAL STATEMENTS

POTOMAC ELECTRIC POWER COMPANY

(1) ORGANIZATION

Potomac Electric Power Company (Pepco) is engaged in the transmission and distribution of electricity in the District of Columbia and major portions of Prince George’s County and Montgomery County in suburban Maryland. Pepco also provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its service territories who do not elect to purchase electricity from a competitive supplier. Default Electricity Supply is known as Standard Offer Service in both the District of Columbia and Maryland. Pepco is a wholly owned subsidiary of Pepco Holdings, Inc. (Pepco Holdings or PHI).

PHI entered into an Agreement and Plan of Merger, dated April 29, 2014, as amended and restated on July 18, 2014 (the Merger Agreement), with Exelon Corporation, a Pennsylvania corporation (Exelon), and Purple Acquisition Corp., a Delaware corporation and an indirect, wholly owned subsidiary of Exelon (Merger Sub), providing for the merger of Merger Sub with and into PHI (the Merger), with PHI surviving the Merger as an indirect, wholly owned subsidiary of Exelon. Pursuant to the Merger Agreement, at the effective time of the Merger, each outstanding share of common stock, par value $0.01 per share, of PHI (other than (i) shares owned by Exelon, Merger Sub or any other direct or indirect wholly owned subsidiary of Exelon and shares owned by PHI or any direct or indirect wholly owned subsidiary of PHI, and in each case not held on behalf of third parties (but not including shares held by PHI in any rabbi trust or similar arrangement in respect of any compensation plan or arrangement) and (ii) shares that are owned by stockholders who have perfected and not withdrawn a demand for appraisal rights pursuant to Delaware law), will be canceled and converted into the right to receive $27.25 in cash, without interest.

In connection with entering into the Merger Agreement, PHI entered into a Subscription Agreement, dated April 29, 2014 (the Subscription Agreement), with Exelon, pursuant to which on April 30, 2014, PHI issued to Exelon 9,000 originally issued shares of non-voting, non-convertible and non-transferable Series A preferred stock, par value $0.01 per share (the Preferred Stock), for a purchase price of $90 million. Exelon also committed pursuant to the Subscription Agreement to purchase 1,800 originally issued shares of Preferred Stock for a purchase price of $18 million at the end of each 90-day period following the date of the Subscription Agreement until the Merger closes or is terminated, up to a maximum of 18,000 shares of Preferred Stock for a maximum aggregate consideration of $180 million. In accordance with the Subscription Agreement, on each of July 29, 2014, October 27, 2014, January 26, 2015, April 27, 2015 and July 24, 2015, an additional 1,800 shares of Preferred Stock were issued by PHI to Exelon for an aggregate purchase price of $90 million. The holders of the Preferred Stock will be entitled to receive a cumulative, non-participating cash dividend of 0.1% per annum, payable quarterly, when, as and if declared by PHI’s board of directors. The proceeds from the issuance of the Preferred Stock are not subject to restrictions and are intended to serve as a prepayment of any applicable reverse termination fee payable from Exelon to PHI. The Preferred Stock will be redeemable on the terms and in the circumstances set forth in the Merger Agreement and the Subscription Agreement.

The Merger Agreement provides for certain termination rights for each of PHI and Exelon, and further provides that, upon termination of the Merger Agreement under certain specified circumstances, PHI will be required to pay Exelon a termination fee of $259 million or reimburse Exelon for its expenses up to $40 million (which reimbursement of expenses shall reduce on a dollar for dollar basis any termination fee subsequently payable by PHI), provided, however, that if the Merger Agreement is terminated in connection with an acquisition proposal made under certain circumstances by a person who made an acquisition proposal between April 1, 2014 and the date of the Merger Agreement, the termination fee will be $293 million plus reimbursement of Exelon for its expenses up to $40 million (not subject to offset). In addition, if the Merger Agreement is terminated under certain circumstances due to the failure

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to obtain required regulatory approvals with respect to the Merger or the breach by Exelon of its obligations in respect of obtaining such regulatory approvals (a Regulatory Termination), PHI will be able to redeem any issued and outstanding Preferred Stock at par value, and in that case, Exelon will be required to pay all documented out-of-pocket expenses incurred by PHI in connection with the Merger Agreement or the transactions contemplated thereby, up to $40 million. If the Merger Agreement is terminated, other than for a Regulatory Termination, PHI will be required to redeem the Preferred Stock at the purchase price of $10,000 per share, plus any unpaid accrued and accumulated dividends thereupon.

Consummation of the Merger is subject to the satisfaction or waiver of specified closing conditions, including (i) the approval of the Merger by the holders of a majority of the outstanding shares of common stock of PHI; (ii) the receipt of regulatory approvals required to consummate the Merger, including approvals from the Federal Energy Regulatory Commission (FERC), the Federal Communications Commission (FCC), the Delaware Public Service Commission (DPSC), the District of Columbia Public Service Commission (DCPSC), the Maryland Public Service Commission (MPSC), the New Jersey Board of Public Utilities (NJBPU) and the Virginia State Corporation Commission (VSCC); (iii) the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (the HSR Act); and (iv) other customary closing conditions, including (a) the accuracy of each party’s representations and warranties (subject to customary materiality qualifiers) and (b) each party’s compliance with its obligations and covenants contained in the Merger Agreement (including covenants that may limit, restrict or prohibit PHI and its subsidiaries from taking specified actions during the period between the date of the Merger Agreement and the closing of the Merger or the termination of the Merger Agreement). In addition, the obligations of Exelon and Merger Sub to consummate the Merger are subject to the required regulatory approvals not imposing terms, conditions, obligations or commitments, individually or in the aggregate, that constitute a burdensome condition (as defined in the Merger Agreement). For additional discussion, see Note (6), “Regulatory Matters – Merger Approval Proceedings.”

On September 23, 2014, the stockholders of PHI approved the Merger, on October 7, 2014, the VSCC approved the Merger, and on November 20, 2014, FERC approved the Merger. In addition, the transfer of control of certain communications licenses held by certain of PHI’s subsidiaries has been approved by the FCC. The NJBPU approved the Merger on February 11, 2015 and, on October 15, 2015, voted to extend the effectiveness of its approval until June 30, 2016. The DPSC approved the Merger on May 19, 2015.

The waiting period expired under the HSR Act on December 2, 2015, which allows for the closing of the Merger at any time on or before December 1, 2016.

On May 15, 2015, the MPSC approved the Merger, with conditions, including conditions that modify and supplement those originally proposed. On May 18, 2015, PHI and Exelon announced that they had committed to fulfill the modified, more stringent conditions and package of customer benefits imposed by the MPSC. In connection with these proceedings, the Maryland Office of People’s Counsel and several other parties to the Merger proceedings filed motions in the Circuit Court for Queen Anne’s County, Maryland, requesting a stay of the MPSC order. On August 7, 2015, the Circuit Court for Queen Anne’s County denied the motions for stay. On January 8, 2016, the Circuit Court affirmed the MPSC’s order in all respects. On January 20 and 22, 2016, respectively, the Maryland Office of People’s Counsel and environmental groups filed notices of appeal of the Circuit Court’s order to the Maryland Court of Special Appeals. Unless a motion to stay is filed and then granted by the court, the MPSC order will remain in effect during the appeals process.

On August 27, 2015, the DCPSC issued a written order denying the application seeking approval of the Merger. On September 28, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, filed an application for reconsideration with the DCPSC requesting reconsideration of the DCPSC order related to the Merger.

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On October 6, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, entered into a Nonunanimous Full Settlement Agreement and Stipulation (the DC Settlement Agreement) with the District of Columbia Government, the Office of the People’s Counsel and other parties, which DC Settlement Agreement contains commitments from Exelon and PHI above those contained in their original merger application.

Also on October 6, 2015, PHI, Exelon and Merger Sub entered into a Letter Agreement (the Letter Agreement), setting forth the terms and conditions under which the parties will file with the DCPSC (a) a Motion of Joint Applicants to Reopen the Record in Formal Case No. 1119 to Allow for Consideration of the DC Settlement Agreement (the Motion to Reopen), or (b) if the Motion to Reopen is not granted, a new merger application, requesting approval of the Merger on the terms and commitments agreed to in the DC Settlement Agreement. Pursuant to the Letter Agreement, PHI and Exelon each agrees, among other things, that neither party will exercise the termination rights each may have under the Merger Agreement on or after October 29, 2015, unless: (i) the DCPSC does not, by November 20, 2015, set a procedural schedule which allows for a final order for approval of the Merger by March 4, 2016, (ii) the DCPSC sets a schedule for action which does not allow for a final order for approval of the Merger by March 4, 2016, (iii) the DCPSC fails to issue a final order approving the Merger and the DC Settlement Agreement as filed without condition or modification by March 4, 2016, (iv) the DCPSC issues a final order denying approval of the Merger or the DC Settlement Agreement or adds conditions or makes modifications to the DC Settlement Agreement, (v) the DC Settlement Agreement is terminated for any reason, or (vi) after March 4, 2016 a condition to closing of the Merger has not been satisfied or waived (other than those conditions that by their nature are to be satisfied at the closing). The Letter Agreement also provides that, subject to certain conditions, Exelon may, following receipt of all regulatory approvals consistent with the DC Settlement Agreement, delay closing of the Merger for up to 30 days to engage in capital markets transactions to raise additional funds required to consummate the Merger.

On October 6, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, filed with the DCPSC the Motion to Reopen requesting consideration of the DC Settlement Agreement and approval of the Merger on such terms and conditions set forth in the DC Settlement Agreement, without condition or modification, and to stay further proceedings on the application for reconsideration filed by the parties on September 28, 2015 and suspend the time period for reconsideration pending the DCPSC’s consideration of the DC Settlement Agreement.

On October 28, 2015, the DCPSC approved the Motion to Reopen and set a procedural schedule for its review of this matter. Upon completion of the public input and evidentiary hearings, the record was closed as of December 23, 2015. Although District of Columbia law does not impose any time limit on the DCPSC’s review of the Merger, the parties requested a decision by March 4, 2016.

(2) SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the financial statements and accompanying notes. Although Pepco believes that its estimates and assumptions are reasonable, they are based upon information available to management at the time the estimates are made. Actual results may differ significantly from these estimates.

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Significant matters that involve the use of estimates include the assessment of contingencies, the calculation of future cash flows and fair value amounts for use in asset impairment calculations, pension and other postretirement benefits assumptions, the assessment of the adequacy of the allowance for uncollectible accounts, the assessment of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of unbilled revenue, recognition of changes in network service transmission rates for prior service year costs, accrual of loss contingency liabilities for general litigation and auto and other liability claims and income tax provisions and reserves. Additionally, Pepco is subject to legal, regulatory, and other proceedings and claims that arise in the ordinary course of its business. Pepco records an estimated liability for these proceedings and claims when it is probable that a loss has been incurred and the loss is reasonably estimable.

Revenue Recognition

Pepco recognizes revenue upon distribution of electricity to its customers, including unbilled revenue for services rendered, but not yet billed. Pepco’s unbilled revenue was $76 million and $77 million as of December 31, 2015 and 2014, respectively, and these amounts are included in Accounts receivable. Pepco calculates unbilled revenue using an output-based methodology. This methodology is based on the supply of electricity intended for distribution to customers. The unbilled revenue process requires management to make assumptions and judgments about input factors such as customer sales mix, temperature, and estimated line losses (estimates of electricity expected to be lost in the process of its transmission and distribution to customers). The assumptions and judgments are inherently uncertain and susceptible to change from period to period, and if actual results differ from projected results, the impact could be material.

Taxes related to the consumption of electricity by Pepco’s customers, such as fuel, energy, or other similar taxes, are components of Pepco’s tariffs and, as such, are billed to customers and recorded in Operating revenue. Accruals for the remittance of these taxes by Pepco are recorded in Other taxes.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in Pepco’s gross revenues were $304 million, $304 million and $318 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Long-Lived Assets Impairment Evaluation

Pepco evaluates certain long-lived assets to be held and used (for example, equipment and real estate) for impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. Examples of such events or changes include a significant decrease in the market price of a long-lived asset or a significant adverse change in the manner in which an asset is being used or its physical condition. A long-lived asset to be held and used is written down to its estimated fair value if the expected future undiscounted cash flow from the asset is less than its carrying value.

For long-lived assets that can be classified as assets to be disposed of by sale, an impairment loss is recognized to the extent that the asset’s carrying value exceeds its estimated fair value including costs to sell.

Income Taxes

Pepco, as a direct subsidiary of Pepco Holdings, is included in the consolidated federal income tax return of PHI. Federal income taxes are allocated to Pepco based upon the taxable income or loss amounts, determined on a separate return basis.

The financial statements include current and deferred income taxes. Current income taxes represent the amount of tax expected to be reported on Pepco’s state income tax returns and the amount of federal income tax allocated from Pepco Holdings.

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Deferred income tax assets and liabilities represent the tax effects of temporary differences between the financial statement basis and tax basis of existing assets and liabilities and they are measured using presently enacted tax rates. The portion of Pepco’s deferred tax liability applicable to its utility operations that has not been recovered from utility customers represents income taxes recoverable in the future and is included in Regulatory assets on the balance sheets. See Note (6), “Regulatory Matters,” for additional information.

Deferred income tax expense generally represents the net change during the reporting period in the net deferred tax liability and deferred recoverable income taxes.

Pepco recognizes interest on underpayments and overpayments of income taxes, interest on uncertain tax positions, and tax-related penalties in income tax expense.

Investment tax credits are being amortized to income over the useful lives of the related property.

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand, cash invested in money market funds and commercial paper held with original maturities of three months or less. Additionally, deposits in PHI’s money pool, which Pepco and certain other PHI subsidiaries use to manage short-term cash management requirements, are considered cash equivalents. Deposits in the money pool are guaranteed by PHI. PHI deposits funds in the money pool to the extent that the pool has insufficient funds to meet the needs of its participants, which may require PHI to borrow funds for deposit from external sources.

Restricted Cash Equivalents

The Restricted cash equivalents included in Current assets consist of (i) cash held as collateral that is restricted from use for general corporate purposes and (ii) cash equivalents that are specifically segregated based on management’s intent to use such cash equivalents for a particular purpose. The classification as current conforms to the classification of the related liabilities.

Accounts Receivable and Allowance for Uncollectible Accounts

Pepco’s Accounts receivable balance primarily consists of customer accounts receivable arising from the sale of goods and services to customers within its service territory, other accounts receivable, and accrued unbilled revenue. Accrued unbilled revenue represents revenue earned in the current period but not billed to the customer until a future date (usually within one month after the receivable is recorded).

Pepco maintains an allowance for uncollectible accounts and changes in the allowance are recorded as an adjustment to Other operation and maintenance expense in the statements of income. Pepco determines the amount of the allowance based on specific identification of material amounts at risk by customer and maintains a reserve based on its historical collection experience. The adequacy of this allowance is assessed on a quarterly basis by evaluating all known factors such as the aging of the receivables, historical collection experience, the economic and competitive environment and changes in the creditworthiness of its customers. Accounts receivable are written off in the period in which the receivable is deemed uncollectible and collection efforts have been exhausted. Recoveries of Accounts receivable previously written off are recorded when received. Although Pepco believes its allowance is adequate, it cannot anticipate with any certainty the changes in the financial condition of its customers. As a result, Pepco records adjustments to the allowance for uncollectible accounts in the period in which the new information that requires an adjustment to the reserve becomes known.

Inventories

Included in Inventories are transmission and distribution materials and supplies. Pepco utilizes the weighted average cost method of accounting for inventory items. Under this method, an average price is determined for the quantity of units acquired at each price level and is applied to the ending quantity to calculate the total ending inventory balance. Materials and supplies are recorded in Inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed.

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Regulatory Assets and Regulatory Liabilities

Pepco is regulated by the MPSC and the DCPSC. The transmission of electricity by Pepco is regulated by FERC.

Based on the regulatory framework in which it has operated, Pepco has historically applied, and in connection with its transmission and distribution business continues to apply, the Financial Accounting Standards Board (FASB) guidance on regulated operations (Accounting Standards Codification (ASC) 980). The guidance allows regulated entities, in appropriate circumstances, to defer the income statement impact of certain costs that are expected to be recovered in future rates through the establishment of regulatory assets and defer certain revenues that are expected to be refunded to customers through the establishment of regulatory liabilities. Management’s assessment of the probability of recovery of regulatory assets requires judgment and interpretation of laws, regulatory commission orders and other factors. If management subsequently determines, based on changes in facts or circumstances, that a regulatory asset is not probable of recovery, the regulatory asset would be eliminated through a charge to earnings.

Effective June 2007, the MPSC approved a bill stabilization adjustment (BSA) mechanism for retail customers. Effective November 2009, the DCPSC approved a BSA for retail customers. For customers to whom the BSA applies, Pepco recognizes distribution revenue based on an approved distribution charge per customer. From a revenue recognition standpoint, the BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during that period. Pursuant to this mechanism, Pepco recognizes either (i) a positive adjustment equal to the amount by which revenue from Maryland and the District of Columbia retail distribution sales falls short of the revenue that Pepco is entitled to earn based on the approved distribution charge per customer, or (ii) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that Pepco is entitled to earn based on the approved distribution charge per customer (a Revenue Decoupling Adjustment). A net positive Revenue Decoupling Adjustment is recorded as a regulatory asset and a net negative Revenue Decoupling Adjustment is recorded as a regulatory liability.

Investment in Trust

Represents assets held in a trust for the benefit of participants in the Pepco Owned Life Insurance plan.

Property, Plant and Equipment

Property, plant and equipment is recorded at original cost, including labor, materials, asset retirement costs and other direct and indirect costs including capitalized interest. The carrying value of Property, plant and equipment is evaluated for impairment whenever circumstances indicate that the carrying value of those assets may not be recoverable. Upon retirement, the cost of regulated property, net of salvage, is charged to Accumulated depreciation. For additional information regarding the treatment of asset removal obligations, see the “Asset Removal Costs” section included in this Note.

The annual provision for depreciation on electric property, plant and equipment is computed on a straight-line basis using composite rates by classes of depreciable property. Non-operating and other property is generally depreciated on a straight-line basis over the useful lives of the assets. The system-wide composite annual depreciation rates for the years ended December 31, 2015, 2014 and 2013 for Pepco’s property were approximately 2.3%, 2.3% and 2.2%, respectively.

Capitalized Interest and Allowance for Funds Used During Construction

In accordance with FASB guidance on regulated operations (ASC 980), utilities may capitalize the capital costs of financing the construction of plant and equipment as allowance for funds used during construction (AFUDC). This results in the debt portion of AFUDC being recorded as a reduction of Interest expense and the equity portion of AFUDC being recorded as an increase to Other income in the accompanying statements of income.

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Pepco recorded AFUDC for borrowed funds of $6 million, $5 million and $5 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Pepco recorded amounts for the equity component of AFUDC of $12 million, $10 million and $9 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Leasing Activities

Pepco’s lease transactions include office space, equipment, software and vehicles. In accordance with FASB guidance on leases (ASC 840), these leases are classified as either operating leases or capital leases.

Operating Leases

An operating lease in which Pepco is the lessee generally results in a level income statement charge over the term of the lease, reflecting the rental payments required by the lease agreement. If rental payments are not made on a straight-line basis, Pepco’s policy is to recognize rent expense on a straight-line basis over the lease term unless another systematic and rational allocation basis is more representative of the time pattern in which the leased property is physically employed.

Capital Leases

For ratemaking purposes, capital leases in which Pepco is the lessee are treated as operating leases; therefore, in accordance with FASB guidance on regulated operations (ASC 980), the amortization of the leased asset is based on the recovery of rental payments through customer rates. Investments in equipment under capital leases are stated at cost, less accumulated depreciation. Depreciation is recorded on a straight-line basis over the equipment’s estimated useful life.

Amortization of Debt Issuance and Reacquisition Costs

Pepco defers and amortizes debt issuance costs and long-term debt premiums and discounts over the lives of the respective debt issuances. When refinancing or redeeming existing debt, any unamortized premiums, discounts and debt issuance costs, as well as debt redemption costs, are classified as regulatory assets and are amortized generally over the life of the new issue.

Asset Removal Costs

In accordance with FASB guidance on regulated operations (ASC 980), asset removal costs are recorded as regulatory liabilities. At December 31, 2015 and 2014, $58 million and $84 million, respectively, of asset removal costs are included in Regulatory liabilities in the accompanying balance sheets.

Pension and Postretirement Benefit Plans

Pepco Holdings sponsors a non-contributory, defined benefit pension plan that covers substantially all employees of Pepco and certain employees of other Pepco Holdings subsidiaries (the PHI Retirement Plan). Pepco Holdings also provides supplemental retirement benefits to certain eligible executives and key employees through nonqualified retirement plans and provides certain postretirement health care and life insurance benefits for eligible retired employees.

The PHI Retirement Plan is accounted for in accordance with FASB guidance on retirement benefits (ASC 715).

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Dividend Restrictions

All of Pepco’s shares of outstanding common stock are held by PHI, its parent company. In addition to its future financial performance, the ability of Pepco to pay dividends to its parent company is subject to limits imposed by: (i) state corporate laws, which impose limitations on the funds that can be used to pay dividends, and (ii) the prior rights of holders of future preferred stock, if any, and existing and future mortgage bonds and other long-term debt issued by Pepco and any other restrictions imposed in connection with the incurrence of liabilities. Pepco has no shares of preferred stock outstanding. Pepco had approximately $1,118 million and $1,077 million of retained earnings available for payment of common stock dividends at December 31, 2015 and 2014, respectively. These amounts represent the total retained earnings balances at those dates.

Reclassifications

Certain prior period amounts have been reclassified in order to conform to the current period presentation.

(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Business Combinations (ASC 805)

In November 2014, the FASB issued new recognition and disclosure requirements related to pushdown accounting. The new recognition requirements grant an acquired entity (or its subsidiaries) the option to elect whether and when a new accounting and reporting basis (pushdown accounting) will be applied when an acquirer obtains control of the acquired entity. This election may be made by the acquired entity (or its subsidiaries) for future change-in-control events or for its most recent change-in-control event, and the acquired entity will be required to determine whether pushdown accounting will be applied in the reporting period in which the change-in-control event occurs or in a subsequent reporting period.

The new required disclosures include information that enables financial statement users to evaluate the effects of pushdown accounting. Disclosures are required to be made in the period in which pushdown accounting is applied and are expected to include both qualitative and quantitative information.

The new recognition and disclosure requirements became effective on a prospective basis on November 18, 2014.

Presentation of Debt Issuance Costs (ASC 835)

In April 2015, the FASB issued new guidance for the presentation of debt issuance costs on the balance sheet. Debt issuance costs are currently required to be presented on the balance sheet as assets. However, under the new requirements, these debt issuance costs will be offset against the debt to which the costs relate. The new requirements are effective for Pepco beginning January 1, 2016, and are required to be implemented on a retrospective basis for all periods presented; however, early adoption is permitted. Pepco has elected to early adopt the new guidance in the fourth quarter of 2015. The table below illustrates the effects of the retrospective application on reported balances in Pepco’s balance sheet as of December 31, 2014.

	December 31, 2014 As Filed		Reclassification ASC 835			December 31, 2014 As Adjusted
	(millions of dollars)
Other (within other assets)	$	71	$	(28	)	$	43
Long-term debt		2,124		(28	)		2,096

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Balance Sheet Classification of Deferred Taxes (ASC 740)

In November 2015, the FASB issued new requirements for the balance sheet classification of deferred taxes. Entities are currently required to present a current and noncurrent deferred tax balance on the balance sheet. Under the new requirements, deferred taxes will only be presented as noncurrent. The new requirements are be effective for PHI beginning January 1, 2017, and may be implemented on either a prospective or retrospective basis; however, early adoption is permitted. PHI has elected to early adopt the new guidance on a retrospective basis in the fourth quarter of 2015. The table below illustrates the effects of the retrospective application on reported balances in Pepco’s balance sheet as of December 31, 2014.

	December 31, 2014 As Filed		Reclassification ASC 740			December 31, 2014 As Adjusted
	(millions of dollars)
Deferred income taxes, net (within current assets)	$	14	$	(14	)	$	—
Other (within current liabilities)		102		(9	)		93
Deferred income tax liabilities, net		1,584		(5	)		1,579

(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Revenue from Contracts with Customers (ASC 606)

In May 2014, the FASB issued new recognition and disclosure requirements for revenue from contracts with customers, which supersedes the existing revenue recognition guidance. The new recognition requirements focus on when the customer obtains control of the goods or services, rather than the current risks and rewards model of recognition. The core principle of the new standard is that an entity will recognize revenue when it transfers goods or services to its customers in an amount that reflects the consideration an entity expects to be entitled to for those goods or services. The new disclosure requirements will include information intended to communicate the nature, amount, timing and any uncertainty of revenue and cash flows from applicable contracts, including any significant judgments and changes in judgments and assets recognized from the costs to obtain or fulfill a contract. Entities will generally be required to make more estimates and use more judgment under the new standard.

The new requirements will be effective for Pepco beginning January 1, 2018, and may be implemented either retrospectively for all periods presented, or as a cumulative-effect adjustment as of January 1, 2018. Early adoption is permitted, but not before January 1, 2017. Pepco is currently evaluating the potential impact of this new guidance on its financial statements and which implementation approach to select.

Business Combination (ASC 805)

In September 2015, the FASB issued new guidance on adjustments to provisional amounts recognized in a business combination, which are currently recognized on a retrospective basis. Under the new requirements, adjustments will be recognized in the reporting period in which the adjustments are determined. The effects of changes in depreciation, amortization, or other income arising from changes to the provisional amounts, if any, are included in earnings of the reporting period in which the adjustments to the provisional amounts are determined. An entity is also required to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The new requirements will be effective for Pepco beginning January 1, 2016, and are required to be implemented on a prospective basis. Early adoption is permitted. Pepco currently anticipates it may be affected by the new guidance if its Merger with Exelon is consummated.

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(5) SEGMENT INFORMATION

Pepco operates its business as one regulated utility segment, which includes all of its services as described above.

(6) REGULATORY MATTERS

Regulatory Assets and Regulatory Liabilities

The components of Pepco’s regulatory asset and liability balances at December 31, 2015 and 2014 are as follows:

	2015		2014
	(millions of dollars)
Regulatory Assets
Demand-side management costs	$	292	$	238
Smart Grid costs		181		175
Recoverable income taxes		142		148
Recoverable workers’ compensation and long-term disability costs		31		30
Incremental storm restoration costs		19		29
Deferred debt extinguishment costs		19		22
MAPP abandonment costs		4		19
Deferred energy supply costs		3		3
Other		29		33
Total Regulatory Assets	$	720	$	697
Regulatory Liabilities
Asset removal costs	$	58	$	84
Reserves for FERC ROE transmission challenges		13		2
Deferred income taxes due to customers		6		4
Deferred energy supply costs		5		3
Other		10		11
Total Regulatory Liabilities	$	92	$	104

A description for each category of regulatory assets and regulatory liabilities follows:

Demand-Side Management Costs: Represents recoverable costs associated with customer direct load control and energy efficiency and conservation programs in all jurisdictions that are being recovered from customers. These programs are designed to reduce customer’s energy consumption. Pepco earns a return on these regulatory assets.

Smart Grid Costs: Represents advanced metering infrastructure (AMI) costs associated with the installation of smart meters and the early retirement of legacy meters throughout Pepco’s service territory that are recoverable from customers. Pepco generally is deferring carrying charges on these regulatory assets.

Recoverable Income Taxes: Represents amounts recoverable from Pepco’s customers for tax benefits applicable to utility operations that were previously recognized in income tax expense before the company was ordered to record the tax benefits as deferred income taxes. As the temporary differences between the financial statement basis and tax basis of assets reverse, the deferred recoverable balances are reversed.

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Recoverable Workers’ Compensation and Long-Term Disability Costs: Represents accrued workers’ compensation and long-term disability costs for Pepco, which are recoverable from customers when actual claims are paid to employees. Pepco does not earn a return on these regulatory assets.

Incremental Storm Restoration Costs: Represents total incremental storm restoration costs incurred for repair work due to major storm events in 2012 and 2011, including Hurricane Sandy, the June 2012 derecho, Hurricane Irene, and the 2011 severe winter storm, that are recoverable from customers in the Maryland jurisdiction. Pepco’s costs related to Hurricane Sandy, the June 2012 derecho, Hurricane Irene and the 2011 severe winter storm are being amortized and recovered from customers, each over a five-year period. Pepco does not earn a return on these regulatory assets.

Deferred Debt Extinguishment Costs: Represents deferred costs of debt extinguishment that are amortized to interest expense and recovered from customers. Pepco generally earns a return on these regulatory assets.

MAPP Abandonment Costs: Represents abandonment costs incurred in connection with the Mid-Atlantic Power Pathway (MAPP) transmission line construction project which was terminated by PJM Interconnection, LLC (PJM) on August 24, 2012. These regulatory assets are being amortized and recovered in transmission rates through May 2016. Pepco generally does not earn a return on these regulatory assets.

Deferred Energy Supply Costs: The regulatory asset represents primarily deferred costs associated with a net under-recovery of Default Electricity Supply costs incurred by Pepco and are being or are expected to be recovered from customers. Pepco does not earn a return on these regulatory assets. The regulatory liability represents primarily deferred costs associated with a net over-recovery of Default Electricity Supply costs incurred that will be refunded by Pepco to customers.

Other: Represents miscellaneous regulatory assets that generally are being amortized over 1 to 20 years.

Asset Removal Costs: The depreciation rates for Pepco include a component for removal costs, as approved by the relevant federal and state regulatory commissions. Accordingly, Pepco has recorded regulatory liabilities for its estimate of the difference between incurred removal costs and the amount of removal costs recovered through depreciation rates.

Reserves for FERC ROE Transmission Challenges: Represents reserves established under a settlement agreement filed with FERC for the resolution of certain challenges filed by a group of complainants of the base return on equity (ROE) currently authorized by FERC for the transmission service that Pepco provides.

Deferred Income Taxes Due to Customers: Represents the portions of deferred income tax assets applicable to utility operations of Pepco that have not been reflected in current customer rates for which future payment to customers is probable. As the temporary differences between the financial statement basis and tax basis of assets reverse, deferred recoverable income taxes are amortized.

Other: Represents miscellaneous regulatory liabilities.

Rate Proceedings

As further described in Note (1), “Organization,” on April 29, 2014, PHI entered into the Merger Agreement with Exelon and Merger Sub. Subject to certain exceptions, prior to the Merger or the termination of the Merger Agreement, PHI and its subsidiaries may not, without the consent of Exelon, initiate, file or pursue any rate cases, other than pursuing the conclusion of certain proceedings, as described below. To date, Pepco has not requested such consent from Exelon and has not filed any new distribution base rate cases since entering into the Merger Agreement.

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Bill Stabilization Adjustment

A decoupling mechanism, the BSA, was approved and implemented for Pepco electric service in Maryland and in the District of Columbia.

Maryland

Pepco Electric Distribution Base Rates

2011 Base Rate Proceeding

In December 2011, Pepco submitted an application with the MPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $68.4 million (subsequently adjusted by Pepco to approximately $66.2 million), based on a requested ROE of 10.75%. In July 2012, the MPSC issued an order approving an annual rate increase of approximately $18.1 million, based on an ROE of 9.31%. Among other things, the order also authorized Pepco to recover the actual cost of AMI meters installed during the 2011 test year, stating that cost recovery for AMI deployment will be allowed in future rate cases in which Pepco demonstrates that the system is cost effective. The new rates became effective on July 20, 2012. The Maryland Office of People’s Counsel has sought rehearing on the portion of the order allowing Pepco to recover the costs of AMI meters installed during the test year; that motion remains pending.

2012 Base Rate Proceeding – Phase I

In November 2012, Pepco submitted an application with the MPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $60.8 million, based on a requested ROE of 10.25%. In July 2013, the MPSC issued an order in this proceeding approving an annual rate increase of approximately $27.9 million, based on an ROE of 9.36%. The order excludes the cost of AMI meters from Pepco’s rate base until such time as Pepco demonstrates the cost effectiveness of the AMI system; as a result, costs for AMI meters incurred with respect to the 2012 test year and beyond will be treated as other incremental AMI costs incurred in conjunction with the deployment of the AMI system that are deferred and on which a carrying charge is deferred, but only until such cost effectiveness has been demonstrated and such costs are included in rates. However, MPSC’s July 2012 order issued in connection with Pepco’s 2011 base rate proceeding, which allowed Pepco to recover the costs of meters installed during the 2011 test year for that case, remains in effect.

The July 2013 order also approved a Grid Resiliency Charge, which went into effect on January 1, 2014, for recovery of costs totaling approximately $24.0 million associated with Pepco’s proposed plan to accelerate investments related to certain priority feeders, provided that, before implementing the surcharge, Pepco (i) provides additional information to the MPSC related to performance objectives, milestones and costs, and (ii) makes annual filings with the MPSC thereafter concerning this project, which will permit the MPSC to establish the applicable Grid Resiliency Charge rider for each following year. These conditions have been met. The MPSC rejected certain other cost recovery mechanisms, including Pepco’s proposed reliability performance-based mechanism. The new rates were effective on July 12, 2013.

In July 2013, Pepco filed a notice of appeal of the July 2013 order in the Circuit Court for Baltimore City. Other parties also filed notices of appeal, which were consolidated with Pepco’s appeal. In its appeal, Pepco asserted that the MPSC erred in failing to grant Pepco an adequate ROE, denying a number of other cost recovery mechanisms and limiting Pepco’s test year data to no more than four months of forecasted data in future rate cases. The other parties primarily asserted that the MPSC erred or acted arbitrarily and capriciously in allowing the recovery of certain costs by Pepco, in approving the Grid Resiliency Charge, and in refusing to reduce Pepco’s rate base by known and measurable accumulated depreciation. In November 2014, the Circuit Court issued an order reversing the MPSC’s decision on Pepco’s ROE and directing the MPSC to make more specific findings regarding the impact of improved service reliability and the BSA in calculating Pepco’s ROE. On all other issues that were the subject of an appeal, the Circuit Court affirmed the MPSC’s July 2013 order.

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Other parties to this proceeding filed notices of appeal of the Circuit Court’s decision to the Maryland Court of Special Appeals. On December 15, 2015, the Court of Special Appeals issued its decision in this matter (i) affirming the Circuit Court’s decision upholding the MPSC’s decision to approve the use of the Grid Resiliency Charge for Pepco, and (ii) reversing the Circuit Court on the ROE issue, finding that the MPSC’s original ROE of 9.36% was within the zone of reasonableness. Because none of the parties to the proceeding, including Pepco, appealed this Court of Special Appeals decision, the MPSC decision is now final.

2013 Base Rate Proceeding – Phase I

In December 2013, Pepco submitted an application with the MPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $43.3 million (adjusted by Pepco to approximately $37.4 million on April 15, 2014), based on a requested ROE of 10.25%. The requested rate increase sought to recover expenses associated with Pepco’s ongoing investments in reliability enhancement improvements and efforts to maintain safe and reliable service. In July 2014, the MPSC issued an order approving an annual rate increase of approximately $8.75 million, based on an ROE of 9.62%. The new rates became effective on July 4, 2014. In July 2014, Pepco filed a petition for rehearing seeking reconsideration of the recovery of certain expenses, which the MPSC denied by its order issued in November 2014 (described below). In December 2014, Pepco filed a petition for judicial review of this MPSC order with the Circuit Court for Baltimore City. On August 7, 2015, the Circuit Court for Baltimore City affirmed the MPSC’s decision and denied Pepco’s appeal. Pepco has elected not to appeal the decision of the Circuit Court.

2012 and 2013 Base Rate Proceedings – Phase II

In August 2014, the MPSC issued an order establishing a Phase II proceeding in the 2012 base rate case described above (the 2012 Phase II proceeding) to address the tax implications of Pepco’s net operating loss carryforward (NOLC), which had impacted certain of Pepco’s rate adjustments in the 2012 base rate proceeding. Pepco filed a motion to dismiss the 2012 Phase II proceeding, asserting that the MPSC no longer has jurisdiction over the 2012 base rate case due to appeals having been filed by numerous parties. In September 2014, the MPSC issued an order staying the 2012 Phase II proceeding until further notice. In a similar Phase II proceeding in the 2013 base rate case described above, the MPSC issued an order in November 2014 upholding Pepco’s treatment of the NOLC. Although Pepco believes the November 2014 MPSC order should be dispositive of the issues raised in the 2012 Phase II proceeding, the 2012 Phase II proceeding has remained open pending the resolution of all appeals of the 2012 base rate proceeding. Now that the MPSC decision in that proceeding is final, the MPSC will have authority to act on Phase II.

FERC Transmission ROE Challenges

In February 2013, the public service commissions and public advocates of the District of Columbia, Maryland, Delaware and New Jersey, as well as the Delaware Municipal Electric Corporation, Inc., filed a joint complaint at FERC against Pepco and its affiliates, Delmarva Power & Light Company (DPL) and Atlantic City Electric Company (ACE), as well as Baltimore Gas and Electric Company (BGE). The complainants challenged the base ROE and certain protocols regarding the formula rate process associated with the transmission service that the utilities provide. The complainants support an ROE within a zone of reasonableness of 6.78% and 10.33%, and have argued for a base ROE of 8.7%. The base ROE currently authorized by FERC for PHI’s utilities is (i) 11.3% for facilities placed into service after January 1, 2006, and (ii) 10.8% for facilities placed into service prior to 2006. The 10.8% base ROE for facilities placed into service prior to 2006 receives a 50-basis-point incentive adder for being a member of a regional transmission organization. In August 2014, FERC issued an order setting the matters in this proceeding for hearing, but holding the hearing in abeyance pending settlement

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discussions. The order also (i) directed that the evidence and analysis presented concerning ROE be guided by the new ROE methodology adopted by FERC in another proceeding (discussed below), and (ii) set a 15-month refund period that commenced on February 27, 2013, should a refund result from this proceeding. After settlement discussions among the parties in this matter reached an impasse, the settlement judge, in November 2014, issued an order terminating the settlement discussions and referring the matter to a presiding administrative law judge.

In June 2014, FERC issued an order in a proceeding in which Pepco was not involved, in which it adopted a new ROE methodology for electric utilities. This new methodology replaces the existing one-step discounted cash flow analysis (which incorporates only short-term growth rates) traditionally used to derive ROE for electric utilities with the two-step discounted cash flow analysis (which incorporates both short-term and long-term measures of growth) used for natural gas and oil pipelines. As a result of the August 2014 FERC order discussed in the preceding paragraph, Pepco applied an estimated ROE based on the two-step methodology announced by FERC for the 15-month period over which its transmission revenues would be subject to refund as a result of the challenge, and recorded estimated reserves for the entire 15-month refund period in the second quarter of 2014.

On December 8, 2014, the parties that filed the February 2013 complaint filed a second complaint against Pepco, DPL, ACE, as well as BGE, regarding the base transmission ROE, seeking a reduction from 10.8% to 8.8%. By order issued on February 9, 2015, FERC established a hearing on the second complaint and established a second 15-month refund period that commenced on December 8, 2014. Consistent with the prior challenge, Pepco applied an estimated ROE based on the two-step methodology described above, and in the fourth quarter of 2014 and in the first, second and third quarters of 2015 established reserves for the estimated refund based on the effective date of the second refund period of December 8, 2014. On February 20, 2015, the chief judge issued an order consolidating the two complaint proceedings and established an initial decision issuance deadline of February 29, 2016. On March 2, 2015, the presiding administrative law judge issued an order establishing a procedural schedule for the consolidated proceedings that provided for the hearing to commence on October 20, 2015.

Also during the third quarter of 2015, Pepco further evaluated the reserves established for each of the two refund periods and, based on an updated assessment of market conditions, developments in other cases before FERC, litigation risk and other factors, increased its reserves to reflect management’s best estimate of the refund that is expected to result from these consolidated proceedings. A settlement entered into by the parties regarding the protocols (but not the ROE) raised in the February 2013 complaint was submitted to FERC on July 31, 2015 and was approved by FERC in November 2015.

On November 6, 2015, the parties filed a settlement agreement with FERC regarding the ROE. This settlement agreement provides for (i) a base ROE of 10.0%, effective March 8, 2016, to which a 50-basis-point incentive adder will be applied for being a member of a regional transmission organization, and (ii) customer refunds in the amount of approximately $14.2 million for Pepco covering the two 15-month refund periods described above. In addition, under this settlement agreement, no party may file to change the base ROE or any incentives prior to June 1, 2018. The parties have requested that FERC approve this settlement agreement by March 16, 2016, in order to incorporate the new ROE and applicable refunds into each utility’s 2016 transmission formula rate update. As of December 31, 2015, Pepco’s reserves for both of the refund periods totaled $13 million as required under the settlement agreement.

MPSC New Generation Contract Requirement

In April 2012, the MPSC issued an order that requires Maryland electric distribution companies (EDCs) Pepco, DPL and BGE (collectively, the Contract EDCs) to negotiate and enter into a contract with the winning bidder of a competitive bidding process to build one new power plant in the range of 650 to 700 megawatts (MWs) beginning in 2015, in amounts proportional to their relative standard offer service (SOS) loads. Under the terms of the order, the winning bidder was to construct a 661 MW natural gas-fired combined cycle generation plant in Waldorf, Maryland, with an originally expected commercial operation date of June 1, 2015 (which is now deferred pending the outcome of the proceedings discussed below), and each of the Contract EDCs was to recover its costs associated with the contract through surcharges on its respective SOS customers.

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In response to a complaint filed by a group of generating companies in the PJM region, in September 2013, the U.S. District Court for the District of Maryland (the Federal District Court) issued a ruling that the MPSC’s April 2012 order violated the Supremacy Clause of the U.S. Constitution by attempting to regulate wholesale prices. In contrast, in October 2013, in response to appeals filed by the Contract EDCs and other parties, the Maryland Circuit Court for Baltimore City (the Maryland Circuit Court) upheld the MPSC’s orders requiring the Contract EDCs to enter into the contracts.

In October 2013, the Federal District Court issued an order ruling that the contracts are illegal and unenforceable. The Contract EDCs, the Maryland Office of People’s Counsel and one generating company have appealed the Maryland Circuit Court’s decision to the Maryland Court of Special Appeals. In addition, in November 2013 both the winning bidder and the MPSC appealed the Federal District Court decision to the U.S. Court of Appeals for the Fourth Circuit, which affirmed the decision. In November 2014, the winning bidder and the MPSC each petitioned the U.S. Supreme Court to consider hearing an appeal of the Fourth Circuit decision and, on October 19, 2015, the U.S. Supreme Court agreed to review that decision.

Assuming the contracts, as currently written, become effective following the satisfaction of all relevant conditions, including the completion of the proceedings discussed above, Pepco continues to believe that it may be required to record its proportional share of the contracts as derivative instruments at fair value and record related regulatory assets of approximately the same amount because it would be entitled to recover any payments under the contracts from SOS customers. Pepco has concluded that any accounting for these contracts would not be required until all legal proceedings related to these contracts and the actions of the MPSC in the related proceeding have been resolved.

District of Columbia Power Line Undergrounding Initiative

In May 2014, the Council of the District of Columbia enacted the Electric Company Infrastructure Improvement Financing Act of 2014 (the Improvement Financing Act), which provides enabling legislation for the District of Columbia Power Line Undergrounding (DC PLUG) initiative. This $1 billion initiative seeks to selectively place underground some of the District of Columbia’s most outage-prone power lines, which lines and surrounding conduit would be owned and maintained by Pepco.

The Improvement Financing Act provides that: (i) Pepco is to fund approximately $500 million of the estimated cost to complete the DC PLUG initiative, recovering those costs through a surcharge on the electric bills of Pepco District of Columbia customers; (ii) $375 million of the DC PLUG initiative cost is to be financed by the District of Columbia’s issuance of securitized bonds, which bonds will be repaid through a surcharge on the electric bills of Pepco District of Columbia customers that Pepco will collect on behalf of and remit to the District of Columbia; and (iii) the remaining costs up to $125 million are to be covered by the existing capital projects program of the District of Columbia Department of Transportation (DDOT). Pepco will not earn a return on or a return of the cost of the assets funded with the proceeds of the securitized bonds or assets that are constructed by DDOT under its capital projects program, but ownership and responsibility for the operation and maintenance of such assets will be transferred to Pepco for a nominal amount.

In June 2014, Pepco and DDOT filed a Triennial Plan related to the construction of selected underground feeders in the District of Columbia and recovery of Pepco’s investment through a volumetric surcharge (the Triennial Plan), all in accordance with the Improvement Financing Act. In August 2014, Pepco filed an application for the issuance of a financing order to provide for the issuance of the District’s bonds and a volumetric surcharge for the District of Columbia to recover the costs associated with the bond issuance (the DDOT surcharge).

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In November 2014, the DCPSC issued an order approving the Triennial Plan, including Pepco’s volumetric surcharge, and issued the financing order, including approval of the DDOT surcharge. Together these orders permit (i) Pepco and DDOT to commence proposed construction under the Triennial Plan; (ii) the District of Columbia to issue the necessary bonds to fund the District of Columbia’s portion of the DC PLUG initiative; and (iii) the establishment of the customer surcharges contemplated by the Improvement Financing Act. In December 2014, a party to the proceeding sought reconsideration from the DCPSC of both decisions. Final decisions denying both requests for reconsideration were issued by the DCPSC on January 22, 2015 and February 2, 2015, respectively.

In March 2015, a party to the DCPSC proceedings filed with the District of Columbia Court of Appeals a petition for review of the order approving the Triennial Plan and the issuance of the financing order. On January 14, 2016, the District of Columbia Court of Appeals affirmed the orders of the DCPSC. On January 27, 2016, the original petitioning party sought rehearing of the District of Columbia Court of Appeals decision. A determination whether the Court of Appeals will rehear the case is pending.

Separately, in June 2015, an agency of the federal government served by Pepco asserted that the DDOT surcharge constitutes a tax on end users from which the federal government is immune. PHI is currently evaluating the assertion and the resolution of this matter will likely delay implementation of the DC PLUG initiative.

Merger Approval Proceedings

District of Columbia

On June 18, 2014, Exelon, PHI and Pepco, and certain of their respective affiliates, filed an application with the DCPSC seeking approval of the Merger. To approve the Merger, the DCPSC must find that the Merger is in the public interest. In an order issued August 22, 2014, the DCPSC stated that to make the determination of whether the transaction is in the public interest, it will analyze the transaction in the context of seven factors to determine whether the transaction balances the interests of shareholders and investors with ratepayers and the community, whether the benefits to shareholders do or do not come at the expense of the ratepayers, and whether the transaction produces a direct and tangible benefit to ratepayers. The seven factors identified by the DCPSC are the effects of the transaction on: (i) ratepayers, shareholders, the financial health of the utility standing alone and as merged, and the local economy; (ii) utility management and administrative operations; (iii) the public safety and the safety and reliability of services; (iv) risks associated with all of the affiliated non-jurisdictional business operations, including nuclear operations, of the applicants; (v) the DCPSC’s ability to regulate the utility effectively following the Merger; (vi) competition in the local retail and wholesale markets that impacts the District and District ratepayers; and (vii) conservation of natural resources and preservation of environmental quality. District of Columbia law does not impose any time limit on the DCPSC’s review of the Merger. The DCPSC held evidentiary hearings in March and April of 2015 and the record was closed on May 27, 2015.

On August 27, 2015, the DCPSC issued a written order denying the application seeking approval of the Merger. On September 28, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, filed an application for reconsideration before the DCPSC. Following the DCPSC’s decision on reconsideration, Exelon and Pepco Holdings have the option of filing further appeals with the DC Court of Appeals.

On October 6, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, entered into the DC Settlement Agreement with the District of Columbia Government, the Office of the People’s Counsel and other parties. Also on October 6, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates filed with the DCPSC the Motion to Reopen requesting consideration of the DC Settlement Agreement and approval of the Merger on such terms and conditions set forth in the DC Settlement Agreement, without condition or modification, and to stay further proceedings on the application for reconsideration filed by the parties on September 28, 2015, and suspend the time period for reconsideration pending the DCPSC’s consideration of the DC Settlement Agreement.

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On October 28, 2015, the DCPSC approved the Motion to Reopen and set a procedural schedule for its review of this matter. Upon completion of the public input and evidentiary hearings, the record was closed as of December 23, 2015. Although District of Columbia law does not impose any time limit on the DCPSC’s review of the Merger, the parties requested a decision by March 4, 2016.

Maryland

On August 19, 2014, Exelon, PHI, Pepco, DPL and certain of their respective affiliates, filed an application with the MPSC seeking approval of the Merger. Maryland law requires the MPSC to approve a merger subject to its review if it finds that the merger is consistent with the public interest, convenience and necessity, including its benefits to and impact on consumers. Evidentiary hearings were held beginning on January 26, 2015. On March 10, 2015, Exelon, PHI, Pepco, DPL and certain of their respective affiliates, filed with the MPSC a settlement agreement entered into with one of the stakeholder groups participating in the MPSC approval proceeding. On March 16, 2015, Exelon, PHI, Pepco, DPL and certain of their respective affiliates, filed with the MPSC a settlement agreement entered into with Montgomery and Prince George’s Counties in Maryland, and a number of other parties. On May 15, 2015, the MPSC approved the Merger, with conditions, including conditions that modify and supplement those originally proposed. On May 18, 2015, Pepco Holdings and Exelon announced that they had completed their review of the MPSC’s order approving the Merger and have committed to fulfill the modified, more stringent conditions and package of customer benefits imposed by the MPSC.

Multiple parties have filed petitions for judicial review of the MPSC order by the Circuit Court of Queen Anne’s County, Maryland, seeking to appeal the MPSC order. In connection with these proceedings, the Maryland Office of People’s Counsel and several other parties to the Merger proceedings filed motions in the Circuit Court for Queen Anne’s County, Maryland, requesting a stay of the MPSC order. On August 7, 2015, the Circuit Court for Queen Anne’s County denied the motions for stay. On January 8, 2016, the Circuit Court affirmed the MPSC’s order in all respects. On January 20 and 22, 2016, respectively, the Maryland Office of People’s Counsel and environmental groups filed notices of appeal of the Circuit Court’s order to the Maryland Court of Special Appeals. Unless a motion to stay is filed and then granted by the court, the MPSC order will remain in effect during the appeals process.

Virginia

On June 3, 2014, Exelon, PHI, Pepco and DPL, and certain of their respective affiliates, filed an application with the VSCC seeking approval of the Merger. Virginia law provides that, if the VSCC determines, with or without hearing, that adequate service to the public at just and reasonable rates will not be impaired or jeopardized by granting the application for approval, then the VSCC shall approve a merger with such conditions that the VSCC deems to be appropriate in order to satisfy this standard. On October 7, 2014, the VSCC issued an order approving the Merger.

Federal Energy Regulatory Commission

On May 30, 2014, Exelon, PHI, Pepco, DPL and ACE, and certain of their respective affiliates, submitted to FERC a Joint Application for Authorization of Disposition of Jurisdictional Assets and Merger under Section 203 of the Federal Power Act. Under that section, FERC shall approve a merger if it finds that the proposed transaction will be consistent with the public interest. On November 20, 2014, FERC issued an order approving the Merger.

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(7) PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment is comprised of the following:

	Original Cost		Accumulated Depreciation		Net Book Value
	(millions of dollars)
At December 31, 2015
Distribution	$	5,996	$	2,199	$	3,797
Transmission		1,378		475		903
Construction work in progress		318		—		318
Non-operating and other property		399		125		274
Total	$	8,091	$	2,799	$	5,292
At December 31, 2014
Distribution	$	5,668	$	2,082	$	3,586
Transmission		1,306		463		843
Construction work in progress		312		—		312
Non-operating and other property		478		271		207
Total	$	7,764	$	2,816	$	4,948

The non-operating and other property amounts include balances for general plant, distribution plant and transmission plant held for future use, intangible plant and non-utility property. Utility plant is generally subject to a first mortgage lien.

Capital Leases

Pepco leases its consolidated control center, which is an integrated energy management center used by Pepco to centrally control the operation of its transmission and distribution systems. This lease is accounted for as a capital lease and was initially recorded at the present value of future lease payments, which totalled $152 million. The lease requires semi-annual payments of approximately $8 million over a 25-year period that began in December 1994, and provides for transfer of ownership of the system to Pepco for $1 at the end of the lease term. Under FASB guidance on regulated operations, the amortization of leased assets is modified so that the total interest expense charged on the obligation and amortization expense of the leased asset is equal to the rental expense allowed for rate-making purposes. The amortization expense is included within Depreciation and amortization in the statements of income. This lease is treated as an operating lease for rate-making purposes.

Capital lease assets recorded within Property, plant and equipment at December 31, 2015 and 2014 are comprised of the following:

	Original Cost		Accumulated Amortization		Net Book Value
	(millions of dollars)
At December 31, 2015
Transmission	$	76	$	51	$	25
Distribution		76		51		25
Total	$	152	$	102	$	50
At December 31, 2014
Transmission	$	76	$	46	$	30
Distribution		76		46		30
Total	$	152	$	92	$	60

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The approximate annual commitments under all capital leases are $15 million in each of the years 2016 through 2018 and $16 million in 2019.

Gains on Sales of Land

Since 2002, Pepco has owned a 3.5 acre parcel of unimproved land (held as non-utility property) in the Buzzard Point area of southeast Washington, D.C. On July 2, 2015, Pepco entered into a purchase and sale agreement with the District of Columbia to sell the 3.5-acre parcel with a carrying value of $2 million at a purchase price of $39 million. The transaction was consummated on November 10, 2015 resulting in a $37 million pre-tax gain ($22 million after-tax) which was recorded in the fourth quarter of 2015.

Since 2003, Pepco has owned a 3.8 acre parcel of unimproved land (held as non-utility property) in the NoMa area of northeast Washington, D.C. On October 16, 2015, Pepco entered into a purchase and sale agreement with a third party to sell a two-acre parcel of the unimproved land with an allocated carrying value of $5 million at a purchase price of $14 million. The transaction was consummated on December 31, 2015 resulting in a $9 million pre-tax gain ($5 million after-tax) which was recorded in the fourth quarter of 2015. The purchase and sale agreement also provided the third party with a 90-day option to purchase the remaining 1.8-acre land parcel with an allocated carrying value of $4 million at a purchase price of $13 million.

(8) PENSION AND OTHER POSTRETIREMENT BENEFITS

Pepco accounts for its participation in PHI’s single-employer plans, the PHI Retirement Plan and its other postretirement benefits plan, the Pepco Holdings, Inc. Welfare Plan for Retirees (the OPEB Plan), as participation in multiemployer plans. For 2015, 2014 and 2013, Pepco was responsible for $30 million, $22 million and $34 million, respectively, of the pension and other postretirement net periodic benefit cost incurred by PHI. For the years ended December 31, 2015, 2014 and 2013, Pepco made no discretionary tax-deductible contributions to the PHI Retirement Plan. Pepco made contributions of $2 million, $1 million and $6 million, respectively, to the OPEB Plan for the years ended December 31, 2015, 2014 and 2013. At December 31, 2015 and 2014, Pepco’s Prepaid pension expense of $291 million and $316 million, respectively, and Other postretirement benefit obligations of $49 million and $57 million, respectively, effectively represent assets and benefit obligations resulting from Pepco’s participation in the Pepco Holdings benefit plans.

Other Postretirement Benefit Plan Amendments

During 2013, PHI approved two amendments to its other postretirement benefits plan. These amendments impacted the retiree medical plan and the retiree life insurance benefits, and became effective on January 1, 2014. As a result of the amendments, which were cumulatively significant, PHI remeasured its projected benefit obligation for other postretirement benefits as of July 1, 2013. The remeasurement resulted in a $7 million reduction in Pepco’s net periodic benefit cost for other postretirement benefits in 2014, when compared to 2013. Approximately 40% of net periodic other postretirement benefit costs were capitalized in 2014.

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(9) DEBT

Long-Term Debt

The components of long-term debt are shown in the table below:

Type of Debt	Interest Rate			Maturity	2015			2014
					(millions of dollars)
First Mortgage Bonds
		3.05	%	2022	$	200		$	200
		6.20	%(a)(b)	2022		110			110
		3.60	%	2024		400			400
		5.75	%(c)(d)	2034		100			100
		5.40	%(c)(d)	2035		175			175
		6.50	%(a)(c)	2037		500			500
		7.90	%	2038		250			250
		4.15	%	2043		450			250
		4.95	%	2043		150			150
Total long-term debt						2,335			2,135
Net unamortized discount						(3	)		(11	)
Unamortized debt issuance costs						(31	)		(28	)
Total net long-term debt					$	2,301		$	2,096

(a) Represents a series of Collateral First Mortgage Bonds which must be cancelled and released as security for Pepco’s obligations under the corresponding series of senior notes or tax-exempt bonds, at such time as Pepco does not have any first mortgage bonds outstanding (other than its Collateral First Mortgage Bonds), except that Pepco may not permit such release of collateral unless Pepco substitutes comparable obligations for such collateral.

(b) Represents a series of Collateral First Mortgage Bonds securing a series of senior notes issued by Pepco, which in turn secures a series of tax-exempt bonds issued for the benefit of Pepco.

(c) Represents a series of Collateral First Mortgage Bonds (as defined herein) securing a series of senior notes issued by Pepco.

(d) Represents a series of Collateral First Mortgage Bonds which must be cancelled and released as security for Pepco’s obligations under the corresponding series of senior notes or tax-exempt bonds, at such time as Pepco does not have any first mortgage bonds outstanding (other than its Collateral First Mortgage Bonds).

The outstanding first mortgage bonds are issued under a mortgage and deed of trust and are secured by a first lien on substantially all of Pepco’s property, plant and equipment, except for certain property excluded from the lien of the mortgage.

Maturities of Pepco’s long-term debt outstanding at December 31, 2015, are zero in 2016 through 2020, and $2,335 million, thereafter.

Pepco’s long-term debt is subject to certain covenants. As of December 31, 2015, Pepco is in compliance with all such covenants.

The table above does not separately identify $885 million in aggregate principal amount of senior notes issued by Pepco and $110 million in aggregate principal amount of tax-exempt bonds issued for the benefit of Pepco. These senior notes are secured by a like amount of first mortgage bonds (Collateral First Mortgage Bonds) of Pepco. In addition, these tax-exempt bonds are secured by a like amount of Collateral First Mortgage Bonds issued by Pepco. The principal terms of each such series of senior notes, or Pepco’s obligations in respect of each such series of tax-exempt bonds, are identical to the same terms of the corresponding series of Collateral First Mortgage Bonds. Payments of principal and interest made on a series of such senior notes, or the satisfaction of Pepco’s obligations in respect of a series of such tax-exempt bonds, satisfy the corresponding obligations on the related series of Collateral First Mortgage Bonds. For these reasons, each such series of Collateral First Mortgage Bonds and the corresponding senior notes and/or tax-exempt bonds together effectively represent a single financial obligation and are not identified in the table above separately.

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Bond Issuances

During 2015, Pepco issued $200 million of 4.15% first mortgage bonds due March 15, 2043, with a 3.9% yield to maturity. Net proceeds from the issuance of the bonds, which included a premium of $8 million, were used by Pepco to repay outstanding commercial paper and for general corporate purposes.

Short-Term Debt

Pepco has traditionally used a number of sources to fulfill short-term funding needs, such as commercial paper, short-term notes, and bank lines of credit. Proceeds from short-term borrowings are used primarily to meet working capital needs, but may also be used to temporarily fund long-term capital requirements. Pepco’s short-term debt at December 31, 2015 and 2014 consisted of the following:

	2015		2014
	(millions of dollars)
Commercial paper	$	64	$	104

Commercial Paper

Pepco maintains an ongoing commercial paper program to address its short-term liquidity needs. As of December 31, 2015, the maximum capacity available under the program was $500 million, subject to available borrowing capacity under the credit facility.

Pepco had $64 million and $104 million of commercial paper outstanding at December 31, 2015 and 2014, respectively. The weighted average interest rates for commercial paper issued by Pepco during 2015 and 2014 were 0.44% and 0.28%, respectively. The weighted average maturity of all commercial paper issued by Pepco during 2015 and 2014 was four days and six days, respectively.

Credit Facility

PHI, Pepco, DPL and ACE maintain an unsecured syndicated credit facility to provide for their respective liquidity needs, including obtaining letters of credit, borrowing for general corporate purposes and supporting their commercial paper programs. On August 1, 2013, as permitted under the existing terms of the credit agreement, a request by PHI, Pepco, DPL and ACE to extend the credit facility termination date to August 1, 2018 was approved. All of the terms and conditions as well as pricing remained the same.

The aggregate borrowing limit under the amended and restated credit facility is $1.5 billion, all or any portion of which may be used to obtain loans and up to $500 million of which may be used to obtain letters of credit. The facility also includes a swingline loan sub-facility, pursuant to which each company may make same day borrowings in an aggregate amount not to exceed 10% of the total amount of the facility. Any swingline loan must be repaid by the borrower within fourteen days of receipt. The credit sublimit is $750 million for PHI and $250 million for each of Pepco, DPL and ACE. The sublimits may be increased or decreased by the individual borrower during the term of the facility, except that (i) the sum of all of the borrower sublimits following any such increase or decrease must equal the total amount of the facility and (ii) the aggregate amount of credit used at any given time by (a) PHI may not exceed $1.25 billion and (b) each of Pepco, DPL or ACE may not exceed the lesser of $500 million and the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the sublimit reallocations may not exceed eight per year during the term of the facility.

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The interest rate payable by each company on utilized funds is, at the borrowing company’s election, (i) the greater of the prevailing prime rate, the federal funds effective rate plus 0.5% and the one month London Interbank Offered Rate plus 1.0%, or (ii) the prevailing Eurodollar rate, plus a margin that varies according to the credit rating of the borrower.

In order for a borrower to use the facility, certain representations and warranties must be true and correct, and the borrower must be in compliance with specified financial and other covenants, including (i) the requirement that each borrowing company maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the credit agreement, which calculation excludes from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) with certain exceptions, a restriction on sales or other dispositions of assets, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than permitted liens. The credit agreement contains certain covenants and other customary agreements and requirements that, if not complied with, could result in an event of default and the acceleration of repayment obligations of one or more of the borrowers thereunder. Each of the borrowers was in compliance with all covenants under this facility at December 31, 2015.

The absence of a material adverse change in PHI’s business, property, results of operations or financial condition is not a condition to the availability of credit under the credit agreement. The credit agreement does not include any rating triggers.

As of December 31, 2015 and 2014, the amount of cash plus borrowing capacity under the credit facility available to meet the liquidity needs of PHI’s utility subsidiaries in the aggregate was $576 million and $413 million, respectively. Pepco’s borrowing capacity under the credit facility at any given time depends on the amount of the subsidiary borrowing capacity being utilized by DPL and ACE and the portion of the total capacity being used by PHI.

Credit Facility Amendment

During 2014, PHI, Pepco, DPL and ACE entered into an amendment of and consent with respect to the credit agreement (the Consent). PHI was required to obtain the consent of certain of the lenders under the credit facility in order to permit the consummation of the Merger. Pursuant to the Consent, certain of the lenders consented to the consummation of the Merger and the subsequent conversion of PHI from a Delaware corporation to a Delaware limited liability company, provided that the Merger and subsequent conversion are consummated on or before October 29, 2015. In addition, the Consent amends the definition of “Change in Control” in the credit agreement to mean, following consummation of the Merger, an event or series of events by which Exelon no longer owns, directly or indirectly, 100% of the outstanding shares of voting stock of Pepco Holdings. PHI requested and obtained an extension of the Consent to allow for completion of the Merger by June 30, 2016.

Other Financing Activities

Sale of Receivables

During 2015, Pepco, as seller, entered into a purchase agreement with a buyer to sell receivables from an energy savings project over a period of time pursuant to a task order. The purchase price to be received by Pepco is $5 million. Pursuant to the purchase agreement, following acceptance of the energy savings project by the buyer, the buyer is entitled to receive the contract payments under the task order payable by the customer over approximately 15 years. The energy savings project will be performed by Pepco Energy Services, Inc. and its subsidiaries (Pepco Energy Services) and is expected to be completed by the end of 2017.

During 2014, Pepco, as seller, entered into a purchase agreement with a buyer to sell receivables from an energy savings project pursuant to a task order entered into under a General Services Administration area-wide agreement. The purchase price received by Pepco was $12 million, which was included in the

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Current portion of long-term debt and project funding at December 31, 2014. The energy savings project was performed by Pepco Energy Services and was completed in 2014. Pursuant to the purchase agreement, following acceptance of the energy savings project by the buyer, the buyer was entitled to receive the contract payments under the task order payable by the buyer over approximately 9 years. The energy savings project was accepted during the first quarter of 2015 and the amount was removed from the Current portion of long-term debt and project funding.

(10) INCOME TAXES

Pepco, as a direct subsidiary of PHI, is included in the consolidated federal income tax return of PHI. Federal income taxes are allocated to Pepco pursuant to a written tax sharing agreement that was approved by the Securities and Exchange Commission in connection with the establishment of PHI as a holding company. Under this tax sharing agreement, PHI’s consolidated federal income tax liability is allocated based upon PHI’s and its subsidiaries’ separate taxable income or loss.

The provision for income taxes, reconciliation of income tax expense, and components of deferred income tax liabilities (assets) are shown below.

Provision for Income Taxes

	For the Year Ended December 31,
	2015			2014			2013
	(millions of dollars)
Current Tax Benefit
Federal	$	(57	)	$	(79	)	$	(39	)
State and local		6			(3	)		(1	)
Total Current Tax Benefit		(51	)		(82	)		(40	)
Deferred Tax Expense (Benefit)
Federal		125			150			96
State and local		24			24			24
Investment tax credit amortization		—			—			(1	)
Total Deferred Tax Expense		149			174			119
Total Income Tax Expense	$	98		$	92		$	79

Reconciliation of Income Tax Expense

	For the Year Ended December 31,
	2015					2014					2013
	(millions of dollars)
Income tax at Federal statutory rate	$	100		35.0	%	$	92		35.0	%	$	80		35.0	%
Increases (decreases) resulting from:
State income taxes, net of federal effect		15		5.3	%		15		5.7	%		13		5.7	%
Asset removal costs		(14	)	(4.9	)%		(12	)	(4.6	)%		(14	)	(6.1	)%
Change in estimates and interest related to uncertain and effectively settled tax positions		(6	)	(2.1	)%		(1	)	(0.4	)%		(3	)	(1.3	)%
Deferred tax basis adjustments		6		2.1	%		—		—			—		—
Other, net		(3	)	(1.0	)%		(2	)	(0.7	)%		3		1.2	%
Income Tax Expense	$	98		34.4	%	$	92		35.0	%	$	79		34.5	%

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Global Tax Settlement

On November 18, 2015, PHI entered into a settlement with the Internal Revenue Service (IRS) and the Department of Justice (DOJ) (the Global Tax Settlement) to provide for the resolution of the tax treatment of its previously held cross-border energy lease investments involving public utility assets located outside of the United States structured as sale-in, lease-out, or SILO, transactions. The Global Tax Settlement followed the acceptance by PHI on October 29, 2015 of IRS revenue agent reports covering adjustments incorporated in the terms of the Global Tax Settlement, as well as adjustments for all other tax matters in dispute with the IRS. The Global Tax Settlement and the revenue agent reports, together, effectively close all years open to examination of federal income tax liabilities for PHI and Pepco through 2011, and all matters associated with the cross-border energy lease investments through 2013.

As a result of the Global Tax Settlement, Pepco recorded in the fourth quarter of 2015 a tax benefit of $9 million, which is included above in Change in estimates and interest related to uncertain and effectively settled tax positions. Included in the tax benefit of $9 million was a $3 million after-tax interest benefit associated with Pepco’s uncertain tax positions. The interest benefit represented Pepco’s allocated share of an overall net interest benefit for PHI’s consolidated group of $21 million resulting from the Global Tax Settlement assuming Pepco was a separate taxpayer. The remaining tax benefit recorded of $6 million primarily represents uncertain tax positions associated with Pepco’s operations that were settled in favor of Pepco in the Global Tax Settlement. Also in the fourth quarter of 2015, Pepco recorded a charge of $3 million for an uncertain tax position not related to the Global Tax Settlement, which was also included above in Change in estimates and interest related to uncertain and effectively settled tax positions.

Also during the fourth quarter of 2015, Pepco completed its annual reconciliation of its deferred income tax accounts and corrected prior period errors by recording an after-tax charge of $6 million which is included above in Deferred tax basis adjustments. Management has determined that these errors, individually or in the aggregate were not material to the current or prior periods.

Other Tax Matter

On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States (to which Pepco is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. As a result of the court’s ruling in this case, PHI determined in the first quarter of 2013 that it could no longer support its current assessment with respect to the likely outcome of tax positions associated with its cross-border energy lease investments held by its wholly owned subsidiary Potomac Capital Investment Corporation, and PHI recorded an after-tax charge of $377 million in the first quarter of 2013. Included in the $377 million charge was an after-tax interest charge of $54 million and this amount was allocated to each member of PHI’s consolidated group as if each member was a separate taxpayer, resulting in Pepco recording a $5 million (after-tax) interest benefit in the first quarter of 2013, which is included above in Change in estimates and interest related to uncertain and effectively settled tax positions.

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Components of Deferred Income Tax Liabilities (Assets)

	At December 31,
	2015			2014
	(millions of dollars)
Deferred Tax Liabilities (Assets)
Depreciation and other basis differences related to plant and equipment	$	1,541		$	1,423
Pension and other postretirement benefits		95			103
Deferred taxes on amounts to be collected through future rates		55			59
Federal and state net operating losses		(141	)		(186	)
Other		171			180
Total Deferred Tax Liabilities, net	$	1,721		$	1,579

The net deferred tax liability represents the tax effect, at presently enacted tax rates, of temporary differences between the financial statement basis and tax basis of assets and liabilities. The portion of the net deferred tax liability applicable to Pepco’s operations, which has not been reflected in current service rates, represents income taxes recoverable through future rates, net, and is recorded as a regulatory asset on the balance sheet. No valuation allowance for deferred tax assets was required or recorded at December 31, 2015 and 2014. Federal and state net operating losses generally expire over 20 years from 2029 to 2034.

The Tax Reform Act of 1986 repealed the investment tax credit for property placed in service after December 31, 1985, except for certain transition property. Investment tax credits previously earned on Pepco’s property continue to be amortized to income over the useful lives of the related property.

Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits

	2015			2014			2013
	(millions of dollars)
Balance as of January 1	$	97		$	101		$	91
Tax positions related to current year:
Additions		—			1			1
Reductions		—			(2	)		—
Tax positions related to prior years:
Additions		10			1			12
Reductions		(55	)(a)		(4	)		(3	)
Settlements		(40	)(a)		—			—
Balance as of December 31	$	12		$	97		$	101

(a) Reductions and settlements in 2015 resulted from the Global Tax Settlement. Settlements represent unrecognized tax benefits that were satisfied with cash or use of net operating losses and tax credits.

Unrecognized Benefits That, If Recognized, Would Affect the Effective Tax Rate

Unrecognized tax benefits are related to tax positions that have been taken or are expected to be taken in tax returns that are not recognized in the financial statements because management has either measured the tax benefit at an amount less than the benefit claimed, or expected to be claimed, or has concluded that it is not more likely than not that the tax position will be ultimately sustained. For the majority of these tax positions, the ultimate deductibility is highly certain, but there is uncertainty about the timing of such deductibility. At December 31, 2015, Pepco had $8 million of unrecognized tax benefits that, if recognized, would lower the effective tax rate.

Interest and Penalties

Pepco recognizes interest and penalties relating to its uncertain tax positions as an element of income tax expense. For the years ended December 31, 2015, 2014 and 2013, Pepco recognized $5 million of pre-tax interest income ($3 million after-tax), $2 million of pre-tax interest income ($1 million after-tax), and $5 million of pre-tax interest income ($3 million after-tax), respectively, as a component of income tax expense. As of December 31, 2015, 2014 and 2013, Pepco had accrued interest receivable of zero, $9 million and $9 million, respectively, related to effectively settled and uncertain tax positions.

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Possible Changes to Unrecognized Tax Benefits

It is reasonably possible that the amount of the unrecognized tax benefit with respect to some of Pepco’s uncertain tax positions will significantly increase or decrease within the next 12 months. At this time, it is estimated that there will be a $3 million to $5 million decrease in unrecognized tax benefits within the next 12 months.

Tax Years Open to Examination

Pepco, as a direct subsidiary of PHI, is included on PHI’s consolidated Federal income tax return. As a result of the Global Tax Settlement described above, Pepco’s federal income tax liabilities for all years through 2011 have been determined, subject to adjustment to the extent of any net operating loss or other loss or credit carrybacks from subsequent years. The open tax years for the significant states where Pepco files state income tax returns (District of Columbia and Maryland) are the same as for the Federal returns. As a result of the final determination of these years, Pepco has filed or intends to file amended state returns requesting refunds which are subject to review by the various states.

Changes to the District of Columbia Tax Law

On February 26, 2015, the District of Columbia Fiscal Year 2015 Budget Support Act of 2014 became law, effective January 1, 2015. The law revised the apportionment methodology for corporate tax and included a phase-down of the corporate tax rate from 9.975% to 8.25% by fiscal year 2019. The change in law required PHI and Pepco to remeasure their net deferred tax liabilities in the first and fourth quarters of 2015. This remeasurement resulted in Pepco reducing its deferred tax liabilities by $23 million in the first quarter of 2015 to reflect the initial reduction in the tax rate from 9.975% to 9.4% on January 1, 2015 and $2 million in the fourth quarter of 2015 to reflect the subsequent reduction in the tax rate from 9.4% to 9.2% on January 1, 2016. These reductions to the deferred tax liabilities were offset by corresponding decreases to Pepco’s regulatory assets. Further reductions to the corporate tax rate in future years will depend upon the achievement of future revenue projections for the District of Columbia.

Final IRS Regulations on Repair of Tangible Property

In August 2011, the IRS issued Revenue Procedure 2011-43 providing a safe harbor method of tax accounting for repair costs associated with electric transmission and distribution property. In September 2012, with the filing of its 2011 tax return, PHI adopted the safe harbor for the 2011 tax year. In September 2013, the IRS published final regulations regarding the tax treatment of costs incurred to acquire, produce or improve tangible property. In February 2014, the IRS issued revenue procedures that describe how taxpayers should implement the final regulations. The final repair regulations and the related revenue procedures did not modify the guidance set forth in Revenue Procedure 2011-43 that the Unit of Property for electric transmission and distribution network assets is determined by the taxpayer’s particular facts and circumstances. The final regulations did not have a material impact on Pepco’s financial statements.

Other Taxes

Taxes other than income taxes for each year are shown below. These amounts are recoverable through rates.

	2015		2014		2013
	(millions of dollars)
Gross Receipts/Delivery	$	107	$	107	$	108
Property		55		51		45
County Fuel and Energy		143		143		153
Environmental, Use and Other		64		62		62
Total	$	369	$	363	$	368

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(11) FAIR VALUE DISCLOSURES

Financial Instruments Measured at Fair Value on a Recurring Basis

Pepco applies FASB guidance on fair value measurement (ASC 820) that established a framework for measuring fair value and expanded disclosures about fair value measurements. As defined in the guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Pepco utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. Accordingly, Pepco utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1) and the lowest priority to unobservable inputs (level 3).

The following tables set forth, by level within the fair value hierarchy, Pepco’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2015 and 2014. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Pepco’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Fair Value Measurements at December 31, 2015
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1) (a)		Significant Other Observable Inputs (Level 2) (a)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Cash equivalents and restricted cash equivalents
Treasury funds	$	2	$	2	$	—	$	—
Executive deferred compensation plan assets
Money market funds and short-term investments		26		11		15		—
Life insurance contracts		42		—		23		19
Total	$	70	$	13	$	38	$	19
LIABILITIES
Executive deferred compensation plan liabilities
Life insurance contracts	$	6	$	—	$	6	$	—
Total	$	6	$	—	$	6	$	—

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2015.

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	Fair Value Measurements at December 31, 2014
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1) (a)		Significant Other Observable Inputs (Level 2) (a)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Restricted cash equivalents
Treasury fund	$	5	$	5	$	—	$	—
Executive deferred compensation plan assets
Money market funds and short-term investments		34		13		21		—
Life insurance contracts		41		—		23		18
Total	$	80	$	18	$	44	$	18
LIABILITIES
Executive deferred compensation plan liabilities
Life insurance contracts	$	7	$	—	$	7	$	—
Total	$	7	$	—	$	7	$	—

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2014.

Pepco classifies its fair value balances in the fair value hierarchy based on the observability of the inputs used in the fair value calculation as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 – Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using broker quotes in liquid markets and other observable data. Level 2 also includes those financial instruments that are valued using methodologies that have been corroborated by observable market data through correlation or by other means. Significant assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

Executive deferred compensation plan assets and liabilities categorized as level 2 consist of life insurance policies and certain employment agreement obligations. The life insurance policies are categorized as level 2 assets because they are valued based on the assets underlying the policies, which consist of short-term cash equivalents and fixed income securities that are priced using observable market data and can be liquidated for the value of the underlying assets as of December 31, 2015. The level 2 liability associated with the life insurance policies represents a deferred compensation obligation, the value of which is tracked via underlying insurance sub-accounts. The sub-accounts are designed to mirror existing mutual funds and money market funds that are observable and actively traded.

The value of certain employment agreement obligations (which are included with life insurance contracts in the tables above) is derived using a discounted cash flow valuation technique. The discounted cash flow calculations are based on a known and certain stream of payments to be made over time that are

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discounted to determine their net present value. The primary variable input, the discount rate, is based on market-corroborated and observable published rates. These obligations have been classified as level 2 within the fair value hierarchy because the payment streams represent contractually known and certain amounts and the discount rate is based on published, observable data.

Level 3 – Pricing inputs that are significant and generally less observable than those from objective sources. Level 3 includes those financial instruments that are valued using models or other valuation methodologies.

Executive deferred compensation plan assets include certain life insurance policies that are valued using the cash surrender value of the policies, net of loans against those policies. The cash surrender values do not represent a quoted price in an active market; therefore, those inputs are unobservable and the policies are categorized as level 3. Cash surrender values are provided by third parties and reviewed by Pepco for reasonableness.

Reconciliations of the beginning and ending balances of Pepco’s fair value measurements using significant unobservable inputs (Level 3) for the years ended December 31, 2015 and 2014 are shown below.

	2015			2014
	Life Insurance Contracts			Life Insurance Contracts
	(millions of dollars)
Balance as of January 1	$	18		$	18
Total gains (losses) (realized and unrealized):
Included in income		5			3
Included in accumulated other comprehensive loss		—			—
Purchases		—			—
Issuances		(3	)		(3	)
Settlements		(1	)		—
Transfers in (out) of level 3		—			—
Balance as of December 31	$	19		$	18

The breakdown of realized and unrealized gains on level 3 instruments included in income as a component of Other income or Other operation and maintenance expense for the periods below were as follows:

	Year Ended December 31,
	2015		2014
	(millions of dollars)
Total gains included in income for the period	$	5	$	3
Change in unrealized gains relating to assets still held at reporting date	$	3	$	3

Other Financial Instruments

The estimated fair values of Pepco’s Long-term debt instruments that are measured at amortized cost in Pepco’s financial statements and the associated levels of the estimates within the fair value hierarchy as of December 31, 2015 and 2014 are shown in the tables below. As required by the fair value measurement guidance, debt instruments are classified in their entirety within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. Pepco’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, which may affect the valuation of fair value debt instruments and their placement within the fair value hierarchy levels.

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The fair value of Long-term debt categorized as level 2 is based on a blend of quoted prices for the debt and quoted prices for similar debt on the measurement date. The blend places more weight on current pricing information when determining the final fair value measurement. The fair value information is provided by brokers, and Pepco reviews the methodologies and results.

The Project funding represents debt instruments issued by Pepco related to its construction contracts. Project funding is categorized as level 3 because Pepco concluded that the amortized cost carrying amounts for these instruments approximate fair value, which does not represent a quoted price in an active market.

	Fair Value Measurements at December 31, 2015
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	2,673	$	—	$	2,673	$	—

(a) The carrying amount for Long-term debt, net of unamortized discount, was $2,332 million as of December 31, 2015.

	Fair Value Measurements at December 31, 2014
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	2,624	$	—	$	2,624	$	—
Project funding		12		—		—		12
Total	$	2,636	$	—	$	2,624	$	12

(a) The carrying amount for Long-term debt, net of unamortized discount, was $2,124 million as of December 31, 2014.

The carrying amount of all other financial instruments in the accompanying financial statements approximate fair value.

(12) COMMITMENTS AND CONTINGENCIES

General Litigation

From time to time, Pepco is named as a defendant in litigation, usually relating to general liability or auto liability claims that resulted in personal injury or property damage to third parties. Pepco is self-insured against such claims up to a certain self-insured retention amount and maintains insurance coverage against such claims at higher levels, to the extent deemed prudent by management. In addition, Pepco’s contracts with its vendors generally require the vendors to name Pepco as an additional insured for the amount at least equal to Pepco’s self-insured retention. Further, Pepco’s contracts with its vendors require the vendors to indemnify Pepco for various acts and activities that may give rise to claims against Pepco. Loss contingency liabilities for both asserted and unasserted claims are recognized if it is probable that a loss will result from such a claim and if the amounts of the losses can be reasonably estimated. Although

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the outcome of the claims and proceedings cannot be predicted with any certainty, management believes that there are no existing claims or proceedings that are likely to have a material adverse effect on Pepco’s financial condition, results of operations or cash flows. At December 31, 2015, Pepco had recorded estimated loss contingency liabilities for general litigation totaling approximately $4 million.

Environmental Matters

Pepco is subject to regulation by various federal, regional, state and local authorities with respect to the environmental effects of its operations, including air and water quality control, solid and hazardous waste disposal and limitations on land use. Although penalties assessed for violations of environmental laws and regulations are not recoverable from customers of Pepco, environmental clean-up costs incurred by Pepco generally are included in its cost of service for ratemaking purposes. The total accrued liabilities for the environmental contingencies of Pepco described below at December 31, 2015 are summarized as follows:

	Transmission and Distribution			Legacy Generation - Regulated		Total
	(millions of dollars)
Balance as of January 1	$	16		$	3	$	19
Accruals		4			3		7
Payments		(2	)		—		(2	)
Balance as of December 31		18			6		24
Less amounts in Other Current Liabilities		2			—		2
Amounts in Other Deferred Credits	$	16		$	6	$	22

Peck Iron and Metal Site

The U.S. Environmental Protection Agency (EPA) informed Pepco in a May 2009 letter that Pepco may be a potentially responsible party (PRP) under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA) with respect to the cleanup of the Peck Iron and Metal site in Portsmouth, Virginia, and for costs EPA has incurred in cleaning up the site. The EPA letter states that Peck Iron and Metal purchased, processed, stored and shipped metal scrap from military bases, governmental agencies and businesses and that the Peck Iron and Metal scrap operations resulted in the improper storage and disposal of hazardous substances. EPA bases its allegation that Pepco arranged for disposal or treatment of hazardous substances sent to the site on information provided by former Peck Iron and Metal personnel, who informed EPA that Pepco was a customer at the site. Pepco has advised EPA by letter that its records show no evidence of any sale of scrap metal by Pepco to the site. Even if EPA has such records and such sales did occur, Pepco believes that any such scrap metal sales may be entitled to the recyclable material exemption from CERCLA liability. In September 2011, EPA initiated a remedial investigation/feasibility study (RI/FS) for the site using federal funds. Pepco cannot at this time estimate an amount or range of reasonably possible loss associated with this RI/FS, any remediation activities to be performed at the site or any other costs that EPA might seek to impose on Pepco.

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Benning Road Site

Contamination of Lower Anacostia River

In September 2010, PHI received a letter from EPA identifying the Benning Road site as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. A portion of the site was formerly the location of a Pepco Energy Services electric generating facility. That generating facility was deactivated in June 2012 and plant structure demolition was completed in July 2015. The remaining portion of the site consists of a Pepco transmission and distribution service center that remains in operation. The principal contaminants allegedly of concern are polychlorinated biphenyls and polycyclic aromatic hydrocarbons. In December 2011, the U.S. District Court for the District of Columbia approved a consent decree entered into by Pepco and Pepco Energy Services with the District of Columbia Department of Energy and Environment (DOEE) (formerly the District of Columbia Department of the Environment), which requires Pepco and Pepco Energy Services to conduct a RI/FS for the Benning Road site and an approximately 10 to 15 acre portion of the adjacent Anacostia River. The RI/FS will form the basis for the remedial actions for the Benning Road site and for the Anacostia River sediment associated with the site. The consent decree does not obligate Pepco or Pepco Energy Services to pay for or perform any remediation work, but it is anticipated that DOEE will look to Pepco and Pepco Energy Services to assume responsibility for cleanup of any conditions in the river that are determined to be attributable to past activities at the Benning Road site.

The initial remedial investigation field work began in January 2013 and was completed in December 2014. In addition, in conjunction with the power plant demolition activities, Pepco and Pepco Energy Services collected soil samples adjacent to and beneath the concrete basins for the dismantled cooling towers for the generating facility. This sampling showed localized areas of soil contamination associated with the cooling tower basins, and, beginning in the first quarter of 2016, Pepco and Pepco Energy Services expect to implement a plan approved by DOEE to remove contaminated soil in conjunction with the demolition and removal of the concrete basins. On April 30, 2015, Pepco and Pepco Energy Services submitted a draft Remedial Investigation (RI) Report to DOEE. After review, DOEE determined that additional field investigation and data analysis is required to complete the RI process (much of which is beyond the scope of the original DOEE-approved RI work plan). In the meantime, Pepco and Pepco Energy Services will revise the draft RI Report as appropriate to address DOEE’s comments and DOEE will make the draft RI available for public review during the first quarter of 2016. The additional field investigation and data analysis will proceed later in 2016 according to a schedule to be developed by Pepco and Pepco Energy Services and approved by DOEE. Once the additional RI work has been completed, Pepco and Pepco Energy Services will issue a draft “final” RI report for review and comment by DOEE and the public. Pepco and Pepco Energy Services will then proceed with a feasibility study (FS) to evaluate possible remedial alternatives. This effort also may include a treatability study to evaluate the effectiveness of potential remedial options. Once the FS has been completed, Pepco and Pepco Energy Services will prepare and submit a draft FS Report for review and comment by DOEE and the public. Thereafter, Pepco and Pepco Energy Services will revise the draft FS Report as appropriate to address comments received and will submit a final FS Report to DOEE.

Upon DOEE’s approval of the final RI and FS Reports, Pepco and Pepco Energy Services will have satisfied their obligations under the consent decree. At that point, DOEE will prepare a Proposed Plan regarding further response actions based on the results of the RI/FS. After considering public comment on the Proposed Plan, DOEE will issue a Record of Decision identifying any further response actions determined to be necessary.

DOEE, Pepco and Pepco Energy Services must submit their next joint status report to the court regarding progress on the RI/FS by May 24, 2016.

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Pepco and Pepco Energy Services have determined that a loss associated with this matter for Pepco and Pepco Energy Services is probable and have estimated that the costs of remediation are in the range of approximately $8 million to $12 million.

The remediation costs accrued for this matter are included in the table above in the columns entitled “Transmission and Distribution” and “Legacy Generation – Regulated.”

NPDES Permit Limit Exceedances

Pepco holds a National Pollutant Discharge Elimination System (NPDES) permit issued by EPA with a July 19, 2009 effective date, which authorizes discharges from the Benning Road site, including the Pepco Energy Services generating facility previously located on the site that was deactivated in 2012 and has been demolished. The 2009 permit for the first time imposed numerical limits on the allowable concentration of certain metals in storm water discharged from the site into the Anacostia River as determined by EPA to be necessary to meet the applicable District of Columbia surface water quality standards. The permit contemplated that Pepco would meet these limits over time through the use of best management practices (BMPs). As of December 2012, Pepco completed the implementation of the first two phases of BMPs identified in a plan approved by EPA (consisting principally of installing metal absorbing filters to capture contaminants at storm water inlets, removing stored equipment from areas exposed to the weather, covering and painting exposed metal pipes, and covering and cleaning dumpsters). These measures were effective in reducing metal concentrations in storm water discharges, but were not sufficient to meet all of the numerical limits for metals. Most of the quarterly monitoring results since the issuance of the permit have shown exceedances of the limits for copper and zinc, as well as occasional exceedances for iron and lead.

The NPDES permit was due to expire on June 19, 2014. Pepco submitted a permit renewal application on December 17, 2013. In November 2014, EPA advised Pepco that it will not renew the permit until the Benning Road site has come into compliance with the existing permit limits. The current permit remains in effect pending EPA’s action on the renewal application. In December 2014, Pepco submitted a plan to EPA to implement the third phase of BMPs recommended in the original permit compliance plan with the objective of achieving full compliance with the permit limits for metals by the end of 2015 and Pepco immediately began to implement the additional BMPs in accordance with the plan. On September 1, 2015, Pepco submitted a report to EPA on the status of implementation of the third phase of BMPs. As of that date, Pepco had fully implemented most of the elements of the Phase 3 plan, including installation of upgraded storm water inlet controls (filters and booms), enhanced inspection and maintenance of inlets, removal of materials and equipment from exposure to storm water, and removal of accumulated sediments from the underground storm drains. The sampling results from the third quarter of 2015 showed compliance with all of the permit limits. The sampling results from the fourth quarter of 2015 showed compliance with all but a single permit limit for metals; the concentration of copper was below the daily maximum limit but exceeded the monthly average limit. As confirmed by this latest sampling, because the permit limits are low and site conditions are subject to variation, Pepco has concluded that some form of storm water treatment prior to discharge will be necessary to ensure ongoing compliance with all permit limits and has begun the process of evaluating treatment options. The nature and scope of the necessary treatment system, and the amount of the associated capital expenditures, will not be known until Pepco has completed the evaluation and design process.

Pepco has been engaged in discussions with representatives from EPA and the DOJ regarding permit compliance. On October 30, 2015, EPA filed a Clean Water Act civil enforcement action against Pepco in federal district court. Pepco expects that this enforcement action will be resolved through a consent decree that will (i) establish further requirements to achieve compliance with the permit limits, including the design and installation of an appropriate storm water treatment system as noted above, and (ii) include civil penalties for past noncompliance. The amount of such penalties is not known or estimable at this time and Pepco does not expect the amount of such penalties to have a material adverse effect on PHI’s consolidated financial condition, results of operations or cash flows.

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Pepco and EPA are currently in discussions regarding the terms of the contemplated consent decree, and it is anticipated that the parties will finalize the consent decree during the first half of 2016. In response to a joint motion by the parties, the court has extended the deadline for Pepco to answer the complaint to May 16, 2016, to give the parties time to work towards agreement on the terms of a consent decree. The parties contemplate seeking a further extension if necessary to complete their negotiations. Once executed by the parties, the consent decree will be filed with the court for review and approval following a period for public comment.

Potomac River Mineral Oil Release

In January 2011, a coupling failure on a transformer cooler pipe resulted in a release of non-toxic mineral oil at Pepco’s Potomac River substation in Alexandria, Virginia. An overflow of an underground secondary containment reservoir resulted in approximately 4,500 gallons of mineral oil flowing into the Potomac River.

In March 2014, Pepco and DOEE entered into a consent decree to resolve a threatened DOEE enforcement action, the terms of which include a combination of a civil penalty and a Supplemental Environmental Project (SEP) with a total cost to Pepco of $875,000. The consent decree was approved and entered by the District of Columbia Superior Court on April 4, 2014. Pepco has paid the $250,000 civil penalty imposed under the consent decree and, pursuant to the consent decree, has made a one-time donation in the amount of $25,000 to the Northeast Environmental Enforcement Training Fund, Inc., a non-profit organization that funds scholarships for environmental enforcement training. The consent decree confirmed that no further actions are required by Pepco to investigate, assess or remediate impacts to the river from the mineral oil release. To implement the SEP, Pepco has entered into an agreement with Living Classrooms Foundation, Inc., a non-profit educational organization, pursuant to which Pepco will provide $600,000 to fund the design, installation and operation of a trash collection system at a storm water outfall that drains to the Anacostia River. DOEE approved the design for the trash collection system and efforts to secure necessary permits are in progress. Pepco expects that this system will be constructed and placed into operation by the end of 2016, which will satisfy Pepco’s obligations under the consent decree. On September 11, 2015, Pepco and DOEE filed a joint report with the D.C. Superior Court on the status of the trash cage project and other elements of the consent decree. The court accepted that report and scheduled the next status hearing in this matter for September 23, 2016.

The consent decree did not resolve potential claims under federal law for natural resource damages resulting from the mineral oil release. Pepco has engaged in separate discussions with DOEE and the federal resource trustees regarding the settlement of a possible natural resource damages claim under federal law. In July 2013, Pepco submitted a natural resource damage assessment to DOEE and the federal trustees that proposed monetary compensation for such damages in the range of $106,000 to $161,000. By letter dated September 16, 2015, the U.S. Department of Interior, on behalf of the trustees, made a confidential counter-proposal for settlement of the natural resource damage claim. Pepco has engaged in subsequent discussions with the trustees and believes that the parties are close to reaching an agreement to settle the claims. Based on the discussions to date, PHI and Pepco do not believe that the resolution of the natural resource damages claim will have a material adverse effect on their respective financial condition, results of operations or cash flows.

As a result of the mineral oil release, Pepco implemented certain interim operational changes to the secondary containment systems at the facility, which involve pumping accumulated storm water to an above-ground holding tank for off-site disposal. Pepco is continuing to use the above-ground holding tank to manage storm water from the secondary containment system while it evaluates other technical and regulatory options.

The amount accrued for this matter is included in the table above in the column entitled “Transmission and Distribution.”

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Metal Bank Site

In the first quarter of 2013, the National Oceanic and Atmospheric Administration (NOAA) contacted Pepco on behalf of itself and other federal and state trustees to request that Pepco execute a tolling agreement to facilitate settlement negotiations concerning natural resource damages allegedly caused by releases of hazardous substances, including polychlorinated biphenyls, at the Metal Bank Cottman Avenue Superfund Site located in Philadelphia, Pennsylvania. Pepco executed a tolling agreement, which has been extended to March 15, 2016, and will continue settlement discussions with the NOAA, the trustees and other PRPs.

The amount accrued for this matter is included in the table above in the column entitled “Transmission and Distribution.”

Brandywine Fly Ash Disposal Site

In February 2013, Pepco received a letter from the Maryland Department of the Environment (MDE) requesting that Pepco investigate the extent of waste on a Pepco right-of-way that traverses the Brandywine fly ash disposal site in Brandywine, Prince George’s County, Maryland, owned by NRG Energy, Inc. (as successor to GenOn MD Ash Management, LLC) (NRG). In July 2013, while reserving its rights and related defenses under a 2000 agreement covering the sale of this site, Pepco indicated its willingness to investigate the extent of, and propose an appropriate closure plan to address, ash on the right-of-way. Pepco submitted a schedule for development of a closure plan to MDE on September 30, 2013 and, by letter dated October 18, 2013, MDE approved the schedule.

Pepco has determined that a loss associated with this matter for Pepco is probable and has estimated that the costs for implementation of a closure plan and cap on the site are in the range of approximately $3 million to $6 million. Pepco believes that the costs incurred in this matter will be recoverable from NRG under the 2000 sale agreement.

The amount accrued for this matter is included in the table above in the column entitled “Transmission and Distribution.”

Rock Creek Mineral Oil Release

In late August 2015, a Pepco underground transmission line in the District of Columbia suffered a breach, resulting in the release of non-toxic mineral oil surrounding the transmission line into the surrounding soil, and a small amount also reached Rock Creek through a storm drain. Pepco notified regulatory authorities, and Pepco and its spill response contractors placed booms in Rock Creek, blocked the storm drain to prevent the release of mineral oil into the creek and commenced remediation of soil around the transmission line and the Rock Creek shoreline. Pepco estimates that approximately 6,100 gallons of mineral oil were released and that its remediation efforts recovered approximately 80 percent of the amount released. Pepco’s remediation efforts are ongoing under the direction of the DOEE and in collaboration with the National Park Service, the Smithsonian Institution/National Zoo and EPA. Pepco’s investigation presently indicates that the damage to Pepco’s facilities occurred prior to the release of mineral oil when third-party excavators struck the Pepco underground transmission line while installing cable for another utility. To the extent recovery is available against any party who contributed to this loss, Pepco will pursue such action. Pepco continues to investigate the cause of the incident, the parties involved, and legal responsibility under District of Columbia law, but does not believe that the remediation costs to resolve this matter will have a material adverse effect on its financial condition, results of operations or cash flows.

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Contractual Obligations

Power Purchase Contracts

As of December 31, 2015, Pepco had no contractual obligations under non-derivative power purchase contracts.

Lease Commitments

Rental expense for operating leases was $7 million, $8 million and $7 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Total future minimum operating lease payments for Pepco as of December 31, 2015 are $7 million in 2016, $6 million in 2017, $5 million in 2018, $4 million in 2019, $3 million in 2020 and $7 million thereafter.

(13) RELATED PARTY TRANSACTIONS

PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries, including Pepco. The cost of these services is allocated in accordance with cost allocation methodologies set forth in the service agreement using a variety of factors, including the subsidiaries’ share of employees, operating expenses, assets and other cost methods. These intercompany transactions are eliminated by PHI in consolidation and no profit results from these transactions at PHI. PHI Service Company costs directly charged or allocated to Pepco for the years ended December 31, 2015, 2014 and 2013 were approximately $240 million, $220 million and $209 million, respectively.

Pepco Energy Services performs utility maintenance services and high voltage underground transmission cabling, including services that are treated as capital costs, for Pepco. Amounts charged to Pepco by Pepco Energy Services for the years ended December 31, 2015, 2014 and 2013 were approximately $26 million, $30 million and $20 million, respectively.

As of December 31, 2015 and 2014, Pepco had the following balances on its balance sheets due to related parties:

	2015			2014
	(millions of dollars)
Payable to Related Party (current) (a)
PHI Service Company	$	(25	)	$	(27	)
Pepco Energy Services (b)		(4	)		(2	)
Other		(1	)		(1	)
Total	$	(30	)	$	(30	)

(a) Included in Accounts payable due to associated companies.

(b) Pepco bills customers on behalf of Pepco Energy Services where Pepco Energy Services has performed work for certain government agencies under a General Services Administration area-wide agreement. Amount also includes charges for utility work performed by Pepco Energy Services on behalf of Pepco.

(14) QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

The quarterly data presented below reflect all adjustments necessary, in the opinion of management, for a fair presentation of the interim results. Quarterly data normally vary seasonally because of temperature variations and differences between summer and winter rates. Therefore, comparisons by quarter within a year are not meaningful.

	2015
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(millions of dollars)
Total Operating Revenue	$	556		$	518		$	612		$	503		$	2,189
Total Operating Expenses		493			435			497			379	(a)		1,804
Operating Income		63			83			115			124			385
Other Expenses		(25	)		(23	)		(23	)		(29	)		(100	)
Income Before Income Tax Expense		38			60			92			95			285
Income Tax Expense		12			18			32			36	(b)		98
Net Income	$	26		$	42		$	60		$	59		$	187

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(a) Includes gains of $46 million ($27 million after-tax) associated with the sale of non-utility land.

(b) Includes net income tax benefit of $9 million associated with the Global Tax Settlement, a tax charge of $3 million for an uncertain tax position not related to the Global Tax Settlement and a tax charge of $6 million to correct prior period errors.

	2014
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(millions of dollars)
Total Operating Revenue	$	535		$	508		$	587		$	471		$	2,101
Total Operating Expenses		469			414			462			408			1,753
Operating Income		66			94			125			63			348
Other Expenses		(18	)		(20	)		(20	)		(27	)		(85	)
Income Before Income Tax Expense		48			74			105			36			263
Income Tax Expense		16			28			38			10			92
Net Income	$	32		$	46		$	67		$	26		$	171

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Management’s Report on Internal Control Over Financial Reporting

The management of Delmarva Power & Light Company (DPL) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management of DPL assessed DPL’s internal control over financial reporting as of December 31, 2015 based on criteria established in the Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its assessment, the management of DPL concluded that DPL’s internal control over financial reporting was effective as of December 31, 2015.

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Report of Independent Registered Public Accounting Firm

To the Shareholder and Board of Directors of

Delmarva Power & Light Company

In our opinion, the financial statements of Delmarva Power & Light Company (a wholly owned subsidiary of Pepco Holdings, Inc.) listed in the accompanying index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Delmarva Power & Light Company at December 31, 2015 and December 31, 2014, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2015 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule of Delmarva Power & Light Company listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Washington, D.C.

February 18, 2016

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STATEMENTS OF INCOME

For the Year Ended December 31,	2015			2014			2013
	(millions of dollars)
Operating Revenue
Electric	$	1,153		$	1,099		$	1,053
Natural gas		165			194			191
Total Operating Revenue		1,318			1,293			1,244
Operating Expenses
Purchased energy		568			546			552
Gas purchased		79			104			109
Other operation and maintenance		306			269			251
Depreciation and amortization		153			125			107
Other taxes		47			42			40
Total Operating Expenses		1,153			1,086			1,059
Operating Income		165			207			185
Other Income (Expenses)
Interest expense		(50	)		(48	)		(50	)
Other income		10			10			10
Total Other Expenses		(40	)		(38	)		(40	)
Income Before Income Tax Expense		125			169			145
Income Tax Expense		49			65			56
Net Income	$	76		$	104		$	89

The accompanying Notes are an integral part of these Financial Statements.

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BALANCE SHEETS

	December 31, 2015			December 31, 2014
	(millions of dollars)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	5		$	4
Restricted cash equivalents		—			5
Accounts receivable, less allowance for uncollectible accounts of $17 million and $11 million, respectively		203			193
Inventories		50			55
Income taxes and related accrued interest receivable		58			34
Prepaid expenses and other		10			12
Total Current Assets		326			303
OTHER ASSETS
Goodwill		8			8
Regulatory assets		308			356
Prepaid pension expense		205			220
Income taxes and related accrued interest receivable		—			4
Other		1			4
Total Other Assets		522			592
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		4,209			3,946
Accumulated depreciation		(1,046	)		(1,021	)
Net Property, Plant and Equipment		3,163			2,925
TOTAL ASSETS	$	4,011		$	3,820

The accompanying Notes are an integral part of these Financial Statements.

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BALANCE SHEETS

	December 31, 2015		December 31, 2014
	(millions of dollars, except shares)
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Short-term debt	$	210	$	211
Current portion of long-term debt		100		100
Accounts payable		41		39
Accrued liabilities		76		74
Accounts payable due to associated companies		20		17
Taxes accrued		3		3
Interest accrued		7		7
Customer deposits		31		24
Other		39		41
Total Current Liabilities		527		516
DEFERRED CREDITS
Regulatory liabilities		189		225
Deferred income tax liabilities, net		941		878
Investment tax credits		4		4
Other postretirement benefit obligations		19		21
Other		33		35
Total Deferred Credits		1,186		1,163
OTHER LONG-TERM LIABILITIES
Long-term debt		1,061		963
COMMITMENTS AND CONTINGENCIES (NOTE 14)
EQUITY
Common stock, $2.25 par value, 1,000 shares authorized, 1,000 shares outstanding		—		—
Premium on stock and other capital contributions		612		537
Retained earnings		625		641
Total Equity		1,237		1,178
TOTAL LIABILITIES AND EQUITY	$	4,011	$	3,820

The accompanying Notes are an integral part of these Financial Statements.

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STATEMENTS OF CASH FLOWS

For the Year Ended December 31,	2015			2014			2013
	(millions of dollars)
OPERATING ACTIVITIES
Net income	$	76		$	104		$	89
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		153			125			107
Deferred income taxes		74			111			65
Investment tax credit amortization		(1	)		(1	)		(1	)
Changes in:
Accounts receivable		(9	)		15			(7	)
Inventories		5			(4	)		2
Regulatory assets and liabilities, net		(38	)		(66	)		(42	)
Accounts payable and accrued liabilities		10			(15	)		(1	)
Pension contributions		—			—			(10	)
Prepaid pension expense, excluding contributions		15			8			14
Income tax-related prepayments, receivables and payables		(19	)		(3	)		(1	)
Other assets and liabilities		—			(6	)		(1	)
Net Cash From Operating Activities		266			268			214
INVESTING ACTIVITIES
Investment in property, plant and equipment		(352	)		(352	)		(357	)
Net other investing activities		7			(6	)		2
Net Cash Used By Investing Activities		(345	)		(358	)		(355	)
FINANCING ACTIVITIES
Dividends paid to Parent		(92	)		(100	)		(30	)
Capital contributions from Parent		75			130			—
Issuances of long-term debt		200			204			300
Reacquisitions of long-term debt		(100	)		(100	)		(250	)
(Repayments) issuances of short-term debt, net		(1	)		(41	)		115
Cost of issuances		(2	)		(2	)		(3	)
Net other financing activities		—			1			5
Net Cash From Financing Activities		80			92			137
Net Increase (Decrease) In Cash and Cash Equivalents		1			2			(4	)
Cash and Cash Equivalents at Beginning of Year		4			2			6
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	5		$	4		$	2
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for interest (net of capitalized interest of $1 million, $1 million and $2 million, respectively)	$	47		$	45		$	47
Cash received for income taxes (includes payments from PHI for Federal income taxes)		(5	)		(43	)		(8	)

The accompanying Notes are an integral part of these Financial Statements.

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STATEMENTS OF EQUITY

	Common Stock				Premium on Stock		Retained Earnings			Total
(millions of dollars, except shares)	Shares		Par Value
Balance as of December 31, 2012		1,000	$	—	$	407	$	578		$	985
Net Income		—		—		—		89			89
Dividends on common stock		—		—		—		(30	)		(30	)
Balance as of December 31, 2013		1,000		—		407		637			1,044
Net Income		—		—		—		104			104
Capital contribution from Parent		—		—		130		—			130
Dividends on common stock		—		—		—		(100	)		(100	)
Balance as of December 31, 2014		1,000		—		537		641			1,178
Net Income		—		—		—		76			76
Capital contribution from Parent		—		—		75		—			75
Dividends on common stock		—		—		—		(92	)		(92	)
Balance as of December 31, 2015		1,000	$	—	$	612	$	625		$	1,237

The accompanying Notes are an integral part of these Financial Statements.

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NOTES TO FINANCIAL STATEMENTS

DELMARVA POWER & LIGHT COMPANY

(1) ORGANIZATION

Delmarva Power & Light Company (DPL) is engaged in the transmission and distribution of electricity in portions of Delaware and Maryland and provides natural gas distribution service in northern Delaware. Additionally, DPL provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its service territories who do not elect to purchase electricity from a competitive supplier. Default Electricity Supply is known as Standard Offer Service in both Delaware and Maryland. DPL is a wholly owned subsidiary of Conectiv, LLC (Conectiv), which is wholly owned by Pepco Holdings, Inc. (Pepco Holdings or PHI).

PHI entered into an Agreement and Plan of Merger, dated April 29, 2014, as amended and restated on July 18, 2014 (the Merger Agreement), with Exelon Corporation, a Pennsylvania corporation (Exelon), and Purple Acquisition Corp., a Delaware corporation and an indirect, wholly owned subsidiary of Exelon (Merger Sub), providing for the merger of Merger Sub with and into PHI (the Merger), with PHI surviving the Merger as an indirect, wholly owned subsidiary of Exelon. Pursuant to the Merger Agreement, at the effective time of the Merger, each outstanding share of common stock, par value $0.01 per share, of PHI (other than (i) shares owned by Exelon, Merger Sub or any other direct or indirect wholly owned subsidiary of Exelon and shares owned by PHI or any direct or indirect wholly owned subsidiary of PHI, and in each case not held on behalf of third parties (but not including shares held by PHI in any rabbi trust or similar arrangement in respect of any compensation plan or arrangement) and (ii) shares that are owned by stockholders who have perfected and not withdrawn a demand for appraisal rights pursuant to Delaware law), will be canceled and converted into the right to receive $27.25 in cash, without interest.

In connection with entering into the Merger Agreement, PHI entered into a Subscription Agreement, dated April 29, 2014 (the Subscription Agreement), with Exelon, pursuant to which on April 30, 2014, PHI issued to Exelon 9,000 originally issued shares of non-voting, non-convertible and non-transferable Series A preferred stock, par value $0.01 per share (the Preferred Stock), for a purchase price of $90 million. Exelon also committed pursuant to the Subscription Agreement to purchase 1,800 originally issued shares of Preferred Stock for a purchase price of $18 million at the end of each 90-day period following the date of the Subscription Agreement until the Merger closes or is terminated, up to a maximum of 18,000 shares of Preferred Stock for a maximum aggregate consideration of $180 million. In accordance with the Subscription Agreement, on each of July 29, 2014, October 27, 2014, January 26, 2015, April 27, 2015 and July 24, 2015, an additional 1,800 shares of Preferred Stock were issued by PHI to Exelon for an aggregate purchase price of $90 million. The holders of the Preferred Stock will be entitled to receive a cumulative, non-participating cash dividend of 0.1% per annum, payable quarterly, when, as and if declared by PHI’s board of directors. The proceeds from the issuance of the Preferred Stock are not subject to restrictions and are intended to serve as a prepayment of any applicable reverse termination fee payable from Exelon to PHI. The Preferred Stock will be redeemable on the terms and in the circumstances set forth in the Merger Agreement and the Subscription Agreement.

The Merger Agreement provides for certain termination rights for each of PHI and Exelon, and further provides that, upon termination of the Merger Agreement under certain specified circumstances, PHI will be required to pay Exelon a termination fee of $259 million or reimburse Exelon for its expenses up to $40 million (which reimbursement of expenses shall reduce on a dollar for dollar basis any termination fee subsequently payable by PHI), provided, however, that if the Merger Agreement is terminated in connection with an acquisition proposal made under certain circumstances by a person who made an acquisition proposal between April 1, 2014 and the date of the Merger Agreement, the termination fee will be $293 million plus reimbursement of Exelon for its expenses up to $40 million (not subject to offset). In addition, if the Merger Agreement is terminated under certain circumstances due to the failure

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to obtain required regulatory approvals with respect to the Merger or the breach by Exelon of its obligations in respect of obtaining such regulatory approvals (a Regulatory Termination), PHI will be able to redeem any issued and outstanding Preferred Stock at par value, and in that case, Exelon will be required to pay all documented out-of-pocket expenses incurred by PHI in connection with the Merger Agreement or the transactions contemplated thereby, up to $40 million. If the Merger Agreement is terminated, other than for a Regulatory Termination, PHI will be required to redeem the Preferred Stock at the purchase price of $10,000 per share, plus any unpaid accrued and accumulated dividends thereupon.

Consummation of the Merger is subject to the satisfaction or waiver of specified closing conditions, including (i) the approval of the Merger by the holders of a majority of the outstanding shares of common stock of PHI; (ii) the receipt of regulatory approvals required to consummate the Merger, including approvals from the Federal Energy Regulatory Commission (FERC), the Federal Communications Commission (FCC), the Delaware Public Service Commission (DPSC), the District of Columbia Public Service Commission (DCPSC), the Maryland Public Service Commission (MPSC), the New Jersey Board of Public Utilities (NJBPU) and the Virginia State Corporation Commission (VSCC); (iii) the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (the HSR Act); and (iv) other customary closing conditions, including (a) the accuracy of each party’s representations and warranties (subject to customary materiality qualifiers) and (b) each party’s compliance with its obligations and covenants contained in the Merger Agreement (including covenants that may limit, restrict or prohibit PHI and its subsidiaries from taking specified actions during the period between the date of the Merger Agreement and the closing of the Merger or the termination of the Merger Agreement). In addition, the obligations of Exelon and Merger Sub to consummate the Merger are subject to the required regulatory approvals not imposing terms, conditions, obligations or commitments, individually or in the aggregate, that constitute a burdensome condition (as defined in the Merger Agreement). For additional discussion, see Note (7), “Regulatory Matters – Merger Approval Proceedings.”

On September 23, 2014, the stockholders of PHI approved the Merger, on October 7, 2014, the VSCC approved the Merger, and on November 20, 2014, FERC approved the Merger. In addition, the transfer of control of certain communications licenses held by certain of PHI’s subsidiaries has been approved by the FCC. The NJBPU approved the Merger on February 11, 2015 and, on October 15, 2015, voted to extend the effectiveness of its approval until June 30, 2016. The DPSC approved the Merger on May 19, 2015.

The waiting period under the HSR Act expired on December 2, 2015, which allows for the closing of the Merger at any time on or before December 1, 2016.

On May 15, 2015, the MPSC approved the Merger, with conditions, including conditions that modify and supplement those originally proposed. On May 18, 2015, PHI and Exelon announced that they had committed to fulfill the modified, more stringent conditions and package of customer benefits imposed by the MPSC. In connection with these proceedings, the Maryland Office of People’s Counsel and several other parties to the Merger proceedings filed motions in the Circuit Court for Queen Anne’s County, Maryland, requesting a stay of the MPSC order. On August 7, 2015, the Circuit Court for Queen Anne’s County denied the motions for stay. On January 8, 2016, the Circuit Court affirmed the MPSC’s order in all respects. On January 20 and 22, 2016, respectively, the Maryland Office of People’s Counsel and environmental groups filed notices of appeal of the Circuit Court’s order to the Maryland Court of Special Appeals. Unless a motion to stay is filed and then granted by the court, the MPSC order will remain in effect during the appeals process.

On August 27, 2015, the DCPSC issued a written order denying the application seeking approval of the Merger. On September 28, 2015, Exelon, PHI and Potomac Electric Power Company (Pepco), and certain of their respective affiliates, filed an application for reconsideration with the DCPSC requesting reconsideration of the DCPSC order related to the Merger.

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On October 6, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, entered into a Nonunanimous Full Settlement Agreement and Stipulation (the DC Settlement Agreement) with the District of Columbia Government, the Office of the People’s Counsel and other parties, which DC Settlement Agreement contains commitments from Exelon and PHI above those contained in their original merger application.

Also on October 6, 2015, PHI, Exelon and Merger Sub entered into a Letter Agreement (the Letter Agreement), setting forth the terms and conditions under which the parties will file with the DCPSC (a) a Motion of Joint Applicants to Reopen the Record in Formal Case No. 1119 to Allow for Consideration of the DC Settlement Agreement (the Motion to Reopen), or (b) if the Motion to Reopen is not granted, a new merger application, requesting approval of the Merger on the terms and commitments agreed to in the DC Settlement Agreement. Pursuant to the Letter Agreement, PHI and Exelon each agrees, among other things, that neither party will exercise the termination rights each may have under the Merger Agreement on or after October 29, 2015, unless: (i) the DCPSC does not, by November 20, 2015, set a procedural schedule which allows for a final order for approval of the Merger by March 4, 2016, (ii) the DCPSC sets a schedule for action which does not allow for a final order for approval of the Merger by March 4, 2016, (iii) the DCPSC fails to issue a final order approving the Merger and the DC Settlement Agreement as filed without condition or modification by March 4, 2016, (iv) the DCPSC issues a final order denying approval of the Merger or the DC Settlement Agreement or adds conditions or makes modifications to the DC Settlement Agreement, (v) the DC Settlement Agreement is terminated for any reason, or (vi) after March 4, 2016 a condition to closing of the Merger has not been satisfied or waived (other than those conditions that by their nature are to be satisfied at the closing). The Letter Agreement also provides that, subject to certain conditions, Exelon may, following receipt of all regulatory approvals consistent with the DC Settlement Agreement, delay closing of the Merger for up to 30 days to engage in capital markets transactions to raise additional funds required to consummate the Merger.

On October 6, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, filed with the DCPSC the Motion to Reopen requesting consideration of the DC Settlement Agreement and approval of the Merger on such terms and conditions set forth in the DC Settlement Agreement, without condition or modification, and to stay further proceedings on the application for reconsideration filed by the parties on September 28, 2015 and suspend the time period for reconsideration pending the DCPSC’s consideration of the DC Settlement Agreement.

On October 28, 2015, the DCPSC approved the Motion to Reopen and set a procedural schedule for its review of this matter. Upon completion of the public input and evidentiary hearings, the record was closed as of December 23, 2015. Although District of Columbia law does not impose any time limit on the DCPSC’s review of the Merger, the parties requested a decision by March 4, 2016.

(2) SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the financial statements and accompanying notes. Although DPL believes that its estimates and assumptions are reasonable, they are based upon information available to management at the time the estimates are made. Actual results may differ significantly from these estimates.

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Significant matters that involve the use of estimates include the assessment of contingencies, the calculation of future cash flows and fair value amounts for use in asset and goodwill impairment calculations, fair value calculations for derivative instruments, pension and other postretirement benefits assumptions, the assessment of the adequacy of the allowance for uncollectible accounts, the assessment of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of unbilled revenue, recognition of changes in network service transmission rates for prior service year costs, accrual of loss contingency liabilities for general litigation and auto and other liability claims, and income tax provisions and reserves. Additionally, DPL is subject to legal, regulatory, and other proceedings and claims that arise in the ordinary course of its business. DPL records an estimated liability for these proceedings and claims when it is probable that a loss has been incurred and the loss is reasonably estimable.

Revenue Recognition

DPL recognizes revenue upon distribution of electricity and natural gas to its customers, including unbilled revenue for services rendered, but not yet billed. DPL’s unbilled revenue was $37 million and $63 million as of December 31, 2015 and 2014, respectively, and these amounts are included in Accounts receivable. DPL calculates unbilled revenue using an output-based methodology. This methodology is based on the supply of electricity or natural gas intended for distribution to customers. The unbilled revenue process requires management to make assumptions and judgments about input factors such as customer sales mix, temperature, and estimated line losses (estimates of electricity and natural gas expected to be lost in the process of its transmission and distribution to customers). The assumptions and judgments are inherently uncertain and susceptible to change from period to period, and if the actual results differ from the projected results, the impact could be material. Revenue from non-regulated electricity and natural gas sales is included in Electric revenue and Natural gas revenue, respectively.

Taxes related to the consumption of electricity and natural gas by DPL’s customers, such as fuel, energy, or other similar taxes, are components of DPL’s tariffs and, as such, are billed to customers and recorded in Operating revenue. Accruals for the remittance of these taxes by DPL are recorded in Other taxes.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in DPL’s gross revenues were $18 million, $16 million and $17 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Accounting for Derivatives

DPL uses derivative instruments primarily to reduce natural gas commodity price volatility and to limit its customers’ exposure to natural gas price fluctuations under a hedging program approved by the DPSC. Derivatives are recorded in the balance sheets as Derivative assets or Derivative liabilities and measured at fair value. DPL enters physical natural gas contracts as part of the hedging program that qualify as normal purchases or normal sales, which are not required to be recorded in the financial statements until settled. DPL’s capacity contracts are not classified as derivatives. Changes in the fair value of derivatives that are not designated as cash flow hedges are reflected in income.

All premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all gains and losses related to hedging activities, are fully recoverable through the fuel adjustment clause approved by the DPSC, and are deferred under Financial Accounting Standards Board (FASB) guidance on regulated operations (Accounting Standards Codification (ASC) 980) until recovered.

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Long-Lived Assets Impairment Evaluation

DPL evaluates certain long-lived assets to be held and used (for example, equipment and real estate) for impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. Examples of such events or changes include a significant decrease in the market price of a long-lived asset or a significant adverse change in the manner in which an asset is being used or its physical condition. A long-lived asset to be held and used is written down to its estimated fair value if the expected future undiscounted cash flow from the asset is less than its carrying value.

For long-lived assets that can be classified as assets to be disposed of by sale, an impairment loss is recognized to the extent that the assets’ carrying value exceeds its estimated fair value including costs to sell.

Income Taxes

DPL, as an indirect subsidiary of Pepco Holdings, is included in the consolidated federal income tax return of PHI. Federal income taxes are allocated to DPL based upon the taxable income or loss amounts, determined on a separate return basis.

The accompanying financial statements include current and deferred income taxes. Current income taxes represent the amount of tax expected to be reported on DPL’s state income tax returns and the amount of federal income tax allocated from Pepco Holdings.

Deferred income tax assets and liabilities represent the tax effects of temporary differences between the financial statement basis and tax basis of existing assets and liabilities, and they are measured using presently enacted tax rates. The portion of DPL’s deferred tax liability applicable to its utility operations that has not been recovered from utility customers represents income taxes recoverable in the future and is included in Regulatory assets on the accompanying balance sheets. See Note (7), “Regulatory Matters,” for additional information.

Deferred income tax expense generally represents the net change during the reporting period in the net deferred tax liability and deferred recoverable income taxes.

DPL recognizes interest on underpayments and overpayments of income taxes, interest on uncertain tax positions, and tax-related penalties in income tax expense.

Investment tax credits are being amortized to income over the useful lives of the related property.

Consolidation of Variable Interest Entities

DPL assesses its contractual arrangements with variable interest entities (VIEs) to determine whether it is the primary beneficiary and thereby has to consolidate the entities in accordance with FASB ASC 810. The guidance addresses conditions under which an entity should be consolidated based upon variable interests rather than voting interests. See Note (17), “Variable Interest Entities,” for additional information.

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand, cash invested in money market funds and commercial paper held with original maturities of three months or less. Additionally, deposits in PHI’s money pool, which DPL and certain other PHI subsidiaries use to manage short-term cash management requirements, are considered cash equivalents. Deposits in the money pool are guaranteed by PHI. PHI deposits funds in the money pool to the extent that the pool has insufficient funds to meet the needs of its participants, which may require PHI to borrow funds for deposit from external sources.

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Accounts Receivable and Allowance for Uncollectible Accounts

DPL’s Accounts receivable balance primarily consists of customer accounts receivable arising from the sale of goods and services to customers within its service territory, other accounts receivable, and accrued unbilled revenue. Accrued unbilled revenue represents revenue earned in the current period but not billed to the customer until a future date (usually within one month after the receivable is recorded).

DPL maintains an allowance for uncollectible accounts and changes in the allowance are recorded as an adjustment to Other operation and maintenance expense in the accompanying statements of income. DPL determines the amount of the allowance based on specific identification of material amounts at risk by customer and maintains a reserve based on its historical collection experience. The adequacy of this allowance is assessed on a quarterly basis by evaluating all known factors such as the aging of the receivables, historical collection experience, the economic and competitive environment and changes in the creditworthiness of its customers. Accounts receivable are written off in the period in which the receivable is deemed uncollectible and collection efforts have been exhausted. Recoveries of Accounts receivable previously written off are recorded when received. Although DPL believes its allowance is adequate, it cannot anticipate with any certainty the changes in the financial condition of its customers. As a result, DPL records adjustments to the allowance for uncollectible accounts in the period in which the new information that requires an adjustment to the reserve becomes known.

Inventories

Included in Inventories are transmission and distribution materials and supplies and natural gas. DPL utilizes the weighted average cost method of accounting for inventory items. Under this method, an average price is determined for the quantity of units acquired at each price level and is applied to the ending quantity to calculate the total ending inventory balance. Materials and supplies are recorded in Inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed.

The cost of natural gas, including transportation costs, is included in Inventory when purchased and charged to Gas purchased expense when used.

Goodwill

Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired at the acquisition date. DPL tests its goodwill for impairment annually as of November 1 and whenever an event occurs or circumstances change in the interim that would more likely than not (that is, a greater than 50% chance) reduce the estimated fair value of DPL below the carrying amount of its net assets. Factors that may result in an interim impairment test include, but are not limited to: a change in the identified reporting unit, an adverse change in business conditions, an adverse regulatory action, or an impairment of DPL’s long-lived assets. DPL performed its most recent annual impairment test as of November 1, 2015, and its goodwill was not impaired as described in Note (6), “Goodwill.”

Regulatory Assets and Regulatory Liabilities

Certain aspects of DPL’s business are subject to regulation by the DPSC and the MPSC. The transmission of electricity by DPL is regulated by FERC. DPL’s interstate transportation and wholesale sale of natural gas are regulated by FERC.

Based on the regulatory framework in which it has operated, DPL has historically applied, and in connection with its transmission and distribution business continues to apply, FASB guidance on regulated operations (ASC 980). The guidance allows regulated entities, in appropriate circumstances, to defer the income statement impact of certain costs that are expected to be recovered in future rates through the establishment of regulatory assets and defer certain revenues that are expected to be refunded to customers through the establishment of regulatory liabilities. Management’s assessment of the probability of recovery of regulatory assets requires judgment and interpretation of laws, regulatory commission orders and other factors. If management subsequently determines, based on changes in facts or circumstances, that a regulatory asset is not probable of recovery, the regulatory asset would be eliminated through a charge to earnings.

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Effective June 2007, the MPSC approved a bill stabilization adjustment (BSA) mechanism for retail customers. For customers to whom the BSA applies, DPL recognizes distribution revenue based on an approved distribution charge per customer. From a revenue recognition standpoint, the BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during that period. Pursuant to this mechanism, DPL recognizes either (i) a positive adjustment equal to the amount by which revenue from Maryland retail distribution sales falls short of the revenue that DPL is entitled to earn based on the approved distribution charge per customer, or (ii) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that DPL is entitled to earn based on the approved distribution charge per customer (a Revenue Decoupling Adjustment). A net positive Revenue Decoupling Adjustment is recorded as a regulatory asset and a net negative Revenue Decoupling Adjustment is recorded as a regulatory liability.

Property, Plant and Equipment

Property, plant and equipment is recorded at original cost, including labor, materials, asset retirement costs and other direct and indirect costs including capitalized interest. The carrying value of Property, plant and equipment is evaluated for impairment whenever circumstances indicate that the carrying value of those assets may not be recoverable. Upon retirement, the cost of regulated property, net of salvage, is charged to Accumulated depreciation. For additional information regarding the treatment of asset retirement obligations, see the “Asset Removal Costs” section included in this Note.

The annual provision for depreciation on electric and natural gas property, plant and equipment is computed on a straight-line basis using composite rates by classes of depreciable property. Non-operating and other property is generally depreciated on a straight-line basis over the useful lives of the assets. The system-wide composite annual depreciation rate for each of the years ended December 31, 2015, 2014 and 2013 for DPL’s property was approximately 2.6%.

Capitalized Interest and Allowance for Funds Used During Construction

In accordance with FASB guidance on regulated operations (ASC 980), utilities may capitalize the capital costs of financing the construction of plant and equipment as allowance for funds used during construction (AFUDC). This results in the debt portion of AFUDC being recorded as a reduction of Interest expense and the equity portion of AFUDC being recorded as an increase to Other income in the accompanying statements of income.

DPL recorded AFUDC for borrowed funds of $1 million, $1 million and $2 million for the years ended December 31, 2015, 2014 and 2013, respectively.

DPL recorded amounts for the equity component of AFUDC of $1 million, $2 million and $2 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Leasing Activities

DPL’s lease transactions include plant, office space, equipment, software, vehicles and elements of power purchase agreements (PPAs). In accordance with FASB guidance on leases (ASC 840), these leases are classified as operating leases.

Operating Leases

An operating lease in which DPL is the lessee generally results in a level income statement charge over the term of the lease, reflecting the rental payments required by the lease agreement. If rental payments are not made on a straight-line basis, DPL’s policy is to recognize rent expense on a straight-line basis over the lease term unless another systematic and rational allocation basis is more representative of the time pattern in which the leased property is physically employed.

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DPL

Arrangements Containing a Lease

PPAs are deemed to contain a lease if the arrangement conveys the right to control the use of property, plant or equipment. If so, DPL determines the appropriate lease accounting classification.

Amortization of Debt Issuance and Reacquisition Costs

DPL defers and amortizes debt issuance costs and long-term debt premiums and discounts over the lives of the respective debt issuances. When refinancing or redeeming existing debt, any unamortized premiums, discounts and debt issuance costs, as well as debt redemption costs, are classified as regulatory assets and are amortized generally over the life of the original issue.

Asset Removal Costs

In accordance with FASB guidance on regulated operations (ASC 980), asset removal costs are recorded as regulatory liabilities. At December 31, 2015 and 2014, $153 million and $166 million, respectively, of asset removal costs are included in Regulatory liabilities in the accompanying balance sheets.

Pension and Postretirement Benefit Plans

Pepco Holdings sponsors a non-contributory, defined benefit pension plan that covers substantially all employees of DPL and certain employees of other Pepco Holdings subsidiaries (the PHI Retirement Plan). Pepco Holdings also provides supplemental retirement benefits to certain eligible executives and key employees through nonqualified retirement plans and provides certain postretirement health care and life insurance benefits for eligible retired employees.

The PHI Retirement Plan is accounted for in accordance with FASB guidance on retirement benefits (ASC 715).

Dividend Restrictions

All of DPL’s shares of outstanding common stock are held by Conectiv, its parent company. In addition to its future financial performance, the ability of DPL to pay dividends to its parent company is subject to limits imposed by: (i) state corporate laws, which impose limitations on the funds that can be used to pay dividends, and (ii) the prior rights of holders of future preferred stock, if any, and existing and future mortgage bonds and other long-term debt issued by DPL and any other restrictions imposed in connection with the incurrence of liabilities. DPL has no shares of preferred stock outstanding. DPL had approximately $625 million and $641 million of retained earnings available for payment of common stock dividends at December 31, 2015 and 2014, respectively. These amounts represent the total retained earnings balances at those dates.

Reclassifications

Certain prior period amounts have been reclassified in order to conform to the current period presentation.

(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Business Combinations (ASC 805)

In November 2014, the FASB issued new recognition and disclosure requirements related to pushdown accounting. The new recognition requirements grant an acquired entity (or its subsidiaries) the option to elect whether and when a new accounting and reporting basis (pushdown accounting) will be applied when an acquirer obtains control of the acquired entity. This election may be made by the acquired entity

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(or its subsidiaries) for future change-in-control events or for its most recent change-in-control event, and the acquired entity will be required to determine whether pushdown accounting will be applied in the reporting period in which the change-in-control event occurs or in a subsequent reporting period.

The new required disclosures include information that enables financial statement users to evaluate the effects of pushdown accounting. Disclosures are required to be made in the period in which pushdown accounting is applied and are expected to include both qualitative and quantitative information.

The new recognition and disclosure requirements became effective on a prospective basis on November 18, 2014.

Presentation of Debt Issuance Costs (ASC 835)

In April 2015, the FASB issued new guidance for the presentation of debt issuance costs on the balance sheet. Debt issuance costs are currently required to be presented on the balance sheet as assets. However, under the new requirements, these debt issuance costs will be offset against the debt to which the costs relate. The new requirements are effective for DPL beginning January 1, 2016, and are required to be implemented on a retrospective basis for all periods presented; however, early adoption is permitted. DPL has elected to early adopt the new guidance in the fourth quarter of 2015. The table below illustrates the effects of the retrospective application on reported balances in DPL’s balance sheet as of December 31, 2014.

	December 31, 2014 As Filed		Reclassification ASC 835			December 31, 2014 As Adjusted
	(millions of dollars)
Other (within other assets)	$	12	$	(8	)	$	4
Long-term debt		971		(8	)		963

Balance Sheet Classification of Deferred Taxes (ASC 740)

In November 2015, the FASB issued new requirements for the balance sheet classification of deferred taxes. Entities are currently required to present a current and noncurrent deferred tax balance on the balance sheet. Under the new requirements, deferred taxes will only be presented as noncurrent. The new requirements are effective for PHI beginning January 1, 2017, and may be implemented on either a prospective or retrospective basis; however, early adoption is permitted. PHI has elected to early adopt the new guidance on a retrospective basis in the fourth quarter of 2015. The table below illustrates the effects of the retrospective application on reported balances in DPL’s balance sheet as of December 31, 2014.

	December 31, 2014 As Filed		Reclassification ASC 740			December 31, 2014 As Adjusted
	(millions of dollars)
Deferred income taxes, net (within current assets)	$	16	$	(16	)	$	—
Other (within current liabilities)		42		(1	)		41
Deferred income tax liabilities, net		893		(15	)		878

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DPL

(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Revenue from Contracts with Customers (ASC 606)

In May 2014, the FASB issued new recognition and disclosure requirements for revenue from contracts with customers, which supersedes the existing revenue recognition guidance. The new recognition requirements focus on when the customer obtains control of the goods or services, rather than the current risks and rewards model of recognition. The core principle of the new standard is that an entity will recognize revenue when it transfers goods or services to its customers in an amount that reflects the consideration an entity expects to be entitled to for those goods or services. The new disclosure requirements will include information intended to communicate the nature, amount, timing and any uncertainty of revenue and cash flows from applicable contracts, including any significant judgments and changes in judgments and assets recognized from the costs to obtain or fulfill a contract. Entities will generally be required to make more estimates and use more judgment under the new standard.

The new requirements will be effective for DPL beginning January 1, 2018, and may be implemented either retrospectively for all periods presented, or as a cumulative-effect adjustment as of January 1, 2018. Early adoption is permitted, but not before January 1, 2017. DPL is currently evaluating the potential impact of this new guidance on its financial statements and which implementation approach to select.

Business Combination (ASC 805)

In September 2015, the FASB issued new guidance on adjustments to provisional amounts recognized in a business combination, which are currently recognized on a retrospective basis. Under the new requirements, adjustments will be recognized in the reporting period in which the adjustments are determined. The effects of changes in depreciation, amortization, or other income arising from changes to the provisional amounts, if any, are included in earnings of the reporting period in which the adjustments to the provisional amounts are determined. An entity is also required to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The new requirements will be effective for DPL beginning January 1, 2016, and are required to be implemented on a prospective basis. Early adoption is permitted. DPL currently anticipates it may be affected by the new guidance if its Merger with Exelon is consummated.

(5) SEGMENT INFORMATION

DPL operates its business as one regulated utility segment, which includes all of its services as described above.

(6) GOODWILL

All of DPL’s goodwill was generated by its acquisition of Conowingo Power Company in 1995.

DPL performs an annual impairment assessment as of November 1 of each year, or more frequently if indicators of potential impairment exist, to determine whether it is more likely than not that the fair value of the DPL reporting unit to which goodwill relates is less than its carrying value. In evaluating goodwill for impairment, DPL first assesses qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If DPL concludes that it is more likely than not that the fair value is more than its carrying value, goodwill is not considered impaired and DPL is not required to perform the two-step goodwill impairment test. Qualitative factors considered in this assessment include industry and market considerations, overall financial performance, changes in any key inputs to the prior year impairment test, including the discount rate, and other relevant events and factors affecting the reporting unit.

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If DPL concludes that it is more likely than not that the fair value is less than its carrying value, DPL performs the first step of the goodwill impairment test, which compares DPL’s fair value to its carrying value. If DPL’s fair value exceeds the carrying value of DPL’s net assets, goodwill is not considered impaired and DPL is not required to perform additional testing. If the carrying value of DPL’s net assets exceeds DPL’s fair value, then DPL must perform the second step of the goodwill impairment test to determine the implied fair value of DPL’s goodwill. If DPL determines during this second step that the carrying value of DPL’s goodwill exceeds its implied fair value, DPL records an impairment loss equal to the difference.

For the annual impairment assessment in 2015, DPL qualitatively determined that it was more likely than not that fair value exceeded carrying value. As a result, DPL did not perform the two-step goodwill impairment test on that reporting unit.

As of December 31, 2015 and 2014, DPL’s goodwill balance was $8 million. There are no accumulated impairment losses.

(7) REGULATORY MATTERS

Regulatory Assets and Regulatory Liabilities

The components of DPL’s regulatory asset and liability balances at December 31, 2015 and 2014 are as follows:

	2015		2014
	(millions of dollars)
Regulatory Assets
Demand-side management costs	$	111	$	91
Smart Grid costs		85		86
Recoverable income taxes		38		84
COPCO acquisition adjustment		13		18
Deferred debt extinguishment costs		10		12
Incremental storm restoration costs		6		7
MAPP abandonment costs		3		14
Deferred energy supply costs		2		12
Deferred losses on gas derivatives		2		4
Other		38		28
Total Regulatory Assets	$	308	$	356
Regulatory Liabilities
Asset removal costs	$	153	$	166
Reserves for FERC ROE transmission challenges		11		1
Deferred energy supply costs		6		—
Deferred income taxes due to customers		3		37
Other		16		21
Total Regulatory Liabilities	$	189	$	225

A description for each category of regulatory assets and regulatory liabilities follows:

Demand-Side Management Costs: Represents recoverable costs associated with customer direct load control and energy efficiency and conservation programs in all jurisdictions that are being recovered from customers. These programs are designed to reduce customers’ energy consumption. DPL earns a return on these regulatory assets.

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Smart Grid Costs: Represents advanced metering infrastructure costs associated with the installation of smart meters and the early retirement of legacy meters throughout DPL’s service territory that are recoverable from customers. DPL generally is deferring carrying charges on these regulatory assets.

Recoverable Income Taxes: Represents amounts recoverable from DPL’s customers for tax benefits applicable to utility operations that were previously recognized in income tax expense before the company was ordered to record the tax benefits as deferred income taxes. As the temporary differences between the financial statement basis and tax basis of assets reverse, the deferred recoverable balances are reversed.

COPCO Acquisition Adjustment: On July 19, 2007, the MPSC issued an order which provided for the recovery of a portion of DPL’s goodwill. As a result of this order, $41 million in DPL goodwill was transferred to a regulatory asset. This item is being amortized from August 2007 through August 2018. DPL earns a return of 12.95% on these regulatory assets.

Deferred Debt Extinguishment Costs: Represents deferred costs of debt extinguishment that are amortized to interest expense and recovered from customers. DPL generally earns a return on these regulatory assets.

Incremental Storm Restoration Costs: Represents total incremental storm restoration costs incurred for repair work due to major storm events in 2015, 2012 and 2011, including the June 2015 storm, Hurricane Sandy, the June 2012 derecho, and Hurricane Irene, that are recoverable from customers in the Maryland jurisdiction. DPL’s costs related to Hurricane Sandy, the June 2012 derecho and Hurricane Irene are being amortized and recovered from customers, each over a five-year period. DPL generally earns a return on these regulatory assets.

MAPP Abandonment Costs: Represents abandonment costs incurred in connection with the Mid-Atlantic Power Pathway (MAPP) transmission line construction project which was terminated by PJM Interconnection, LLC (PJM) on August 24, 2012. These regulatory assets are being amortized and recovered in transmission rates through May 2016. DPL generally does not earn a return on these regulatory assets.

Deferred Energy Supply Costs: The regulatory asset represents primarily deferred costs associated with a net under-recovery of Default Electricity Supply costs incurred by DPL that are being or expected to be recovered from customers. DPL earns a return on these regulatory assets in Delaware. The regulatory liability represents primarily deferred costs associated with a net over-recovery of Default Electricity Supply costs incurred that will be refunded by DPL to customers.

Deferred Losses on Gas Derivatives: Represents losses associated with hedges of natural gas purchases that are recoverable from customers through the Gas Cost Rate (GCR) approved by the DPSC. DPL does not earn a return on these regulatory assets.

Other: Represents miscellaneous regulatory assets that generally are being amortized over 1 to 20 years.

Asset Removal Costs: The depreciation rates for DPL include a component for removal costs, as approved by the relevant federal and state regulatory commissions. Accordingly, DPL has recorded regulatory liabilities for its estimate of the difference between incurred removal costs and the amount of removal costs recovered through depreciation rates.

Reserves for FERC ROE Transmission Challenges: Represents reserves established under a settlement agreement filed with FERC for the resolution of certain challenges filed by a group of complainants of the base return on equity (ROE) currently authorized by FERC for the transmission service that DPL provides.

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DPL

Deferred Income Taxes Due to Customers: Represents the portions of deferred income tax assets applicable to utility operations of DPL that have not been reflected in current customer rates for which future payment to customers is probable. As the temporary differences between the financial statement basis and tax basis of assets reverse, deferred recoverable income taxes are amortized.

Other: Represents miscellaneous regulatory liabilities.

Rate Proceedings

As further described in Note (1), “Organization,” on April 29, 2014, PHI entered into the Merger Agreement with Exelon and Merger Sub. Subject to certain exceptions, prior to the Merger or the termination of the Merger Agreement, PHI and its subsidiaries may not, without the consent of Exelon, initiate, file or pursue any rate cases, other than pursuing the conclusion of certain proceedings, as described below. To date, DPL has not requested such consent from Exelon and has not filed any new distribution base rate cases since entering into the Merger Agreement.

Bill Stabilization Adjustment

A decoupling mechanism, the BSA, was approved and implemented for DPL electric service in Maryland. DPL’s decoupling proposal in Delaware has not to date been adopted.

Delaware

Electric Distribution Base Rates

In March 2013, DPL submitted an application with the DPSC to increase its electric distribution base rates. The application sought approval of an annual rate increase of approximately $42 million (adjusted by DPL to approximately $39 million on September 20, 2013), based on a requested ROE of 10.25%. The requested rate increase sought to recover expenses associated with DPL’s ongoing investments in reliability enhancement improvements and efforts to maintain safe and reliable service. In August 2014, the DPSC issued a final order in this proceeding providing for an annual increase in DPL’s electric distribution base rates of approximately $15.1 million, based on an ROE of 9.70%. The new rates became effective on May 1, 2014.

In September 2014, DPL filed an appeal with the Delaware Superior Court of the DPSC’s August 2014 order in this proceeding, seeking the court’s review of the DPSC’s decision relating to the recovery of costs associated with one component of employee compensation, certain retirement benefits and credit facility expenses. The Division of the Public Advocate filed a cross-appeal in September 2014, pertaining to the treatment of a prepaid pension expense and other postretirement benefit obligations in base rates. Under the settlement agreement related to the Merger described below in “Merger Approval Proceedings – Delaware,” the parties agreed to suspend the appeal and, if the Merger is completed, to the withdrawal of the appeal and the cross-appeal with prejudice.

Forward Looking Rate Plan

In October 2013, DPL filed a multi-year rate plan, referred to as the Forward Looking Rate Plan (FLRP). As proposed, the FLRP would provide for annual electric distribution base rate increases over a four-year period in the aggregate amount of approximately $56 million. The FLRP as proposed provides the opportunity to achieve estimated earned ROEs of 7.41% and 8.80% in years one and two, respectively, and 9.75% in both years three and four of the plan.

In addition, DPL proposed that as part of the FLRP, in order to provide a higher minimum required standard of reliability for DPL’s customers than that to which DPL is currently subject, the standards by which DPL’s reliability is measured would be made more stringent in each year of the FLRP. DPL has also offered to refund an aggregate of $500,000 to customers in each year of the FLRP that it fails to meet the proposed stricter minimum reliability standards.

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In October 2013, the DPSC opened a docket for the purpose of reviewing the details of the FLRP, but stated that it would not address the FLRP until the electric distribution base rate case discussed above was concluded. Although the rate case has been concluded, a schedule for the FLRP docket has not yet been established.

Under the Merger Agreement, DPL is permitted to pursue this matter; however, under the settlement agreement related to the Merger described below in “Merger Approval Proceedings – Delaware,” DPL agreed to withdraw the FLRP if the Merger is completed, without prejudice to the right to make future filings with the DPSC proposing alternative regulatory methodologies that could include, but are not limited to, a multi-year rate plan.

Gas Cost Rates

DPL makes an annual GCR filing with the DPSC for the purpose of allowing DPL to recover natural gas procurement costs through customer rates.

In August 2015, DPL made its 2015 GCR filing. The rates proposed in the 2015 GCR filing would result in a GCR decrease of approximately 26%, primarily reflecting lower natural gas prices. On September 22, 2015, the DPSC issued an order allowing DPL to place the new rates into effect on November 1, 2015, subject to refund and pending final DPSC approval.

Under the Merger Agreement, DPL is permitted to continue to file its required annual GCR cases in Delaware.

FERC Transmission ROE Challenges

In February 2013, the public service commissions and public advocates of the District of Columbia, Maryland, Delaware and New Jersey, as well as the Delaware Municipal Electric Corporation, Inc., filed a joint complaint at FERC against DPL and its affiliates, Pepco and Atlantic City Electric Company (ACE), as well as Baltimore Gas and Electric Company (BGE). The complainants challenged the base ROE and certain protocols regarding the formula rate process associated with the transmission service that the utilities provide. The complainants support an ROE within a zone of reasonableness of 6.78% and 10.33%, and have argued for a base ROE of 8.7%. The base ROE currently authorized by FERC for PHI’s utilities is (i) 11.3% for facilities placed into service after January 1, 2006, and (ii) 10.8% for facilities placed into service prior to 2006. The 10.8% base ROE for facilities placed into service prior to 2006 receives a 50-basis-point incentive adder for being a member of a regional transmission organization. In August 2014, FERC issued an order setting the matters in this proceeding for hearing, but holding the hearing in abeyance pending settlement discussions. The order also (i) directed that the evidence and analysis presented concerning ROE be guided by the new ROE methodology adopted by FERC in another proceeding (discussed below), and (ii) set a 15-month refund period that commenced on February 27, 2013, should a refund result from this proceeding. After settlement discussions among the parties in this matter reached an impasse, the settlement judge, in November 2014, issued an order terminating the settlement discussions and referring the matter to a presiding administrative law judge.

In June 2014, FERC issued an order in a proceeding in which DPL was not involved, in which it adopted a new ROE methodology for electric utilities. This new methodology replaces the existing one-step discounted cash flow analysis (which incorporates only short-term growth rates) traditionally used to derive ROE for electric utilities with the two-step discounted cash flow analysis (which incorporates both short-term and long-term measures of growth) used for natural gas and oil pipelines. As a result of the August 2014 FERC order discussed in the preceding paragraph, DPL applied an estimated ROE based on the two-step methodology announced by FERC for the 15-month period over which its transmission revenues would be subject to refund as a result of the challenge, and recorded estimated reserves for the entire 15-month refund period in the second quarter of 2014.

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DPL

On December 8, 2014, the parties that filed the February 2013 complaint filed a second complaint against Pepco, DPL, ACE, as well as BGE, regarding the base transmission ROE, seeking a reduction from 10.8% to 8.8%. By order issued on February 9, 2015, FERC established a hearing on the second complaint and established a second 15-month refund period that commenced on December 8, 2014. Consistent with the prior challenge, DPL applied an estimated ROE based on the two-step methodology described above, and in the fourth quarter of 2014 and in the first, second and third quarters of 2015 established reserves for the estimated refund based on the effective date of the second refund period of December 8, 2014. On February 20, 2015, the chief judge issued an order consolidating the two complaint proceedings and established an initial decision issuance deadline of February 29, 2016. On March 2, 2015, the presiding administrative law judge issued an order establishing a procedural schedule for the consolidated proceedings that provided for the hearing to commence on October 20, 2015.

Also during the third quarter of 2015, DPL further evaluated the reserves established for each of the two refund periods and, based on an updated assessment of market conditions, developments in other cases before FERC, litigation risk and other factors, increased its reserves to reflect management’s best estimate of the refund that is expected to result from these consolidated proceedings. A settlement entered into by the parties regarding the protocols (but not the ROE) raised in the February 2013 complaint was submitted to FERC on July 31, 2015 and was approved by FERC in November 2015.

On November 6, 2015, the parties filed a settlement agreement with FERC regarding the ROE. This settlement agreement provides for (i) a base ROE of 10.0%, effective March 8, 2016, to which a 50-basis-point incentive adder will be applied for being a member of a regional transmission organization, and (ii) customer refunds in the amount of approximately $11.9 million for DPL covering the two 15-month refund periods described above. In addition, under this settlement agreement, no party may file to change the base ROE or any incentives prior to June 1, 2018. The parties have requested that FERC approve this settlement agreement by March 16, 2016, in order to incorporate the new ROE and applicable refunds into each utility’s 2016 transmission formula rate update. As of December 31, 2015, DPL’s reserves for both of the refund periods totaled $11 million as required under the settlement agreement.

MPSC New Generation Contract Requirement

In April 2012, the MPSC issued an order that requires Maryland electric distribution companies (EDCs) Pepco, DPL and BGE (collectively, the Contract EDCs) to negotiate and enter into a contract with the winning bidder of a competitive bidding process to build one new power plant in the range of 650 to 700 megawatts (MWs) beginning in 2015, in amounts proportional to their relative standard offer service (SOS) loads. Under the terms of the order, the winning bidder was to construct a 661 MW natural gas-fired combined cycle generation plant in Waldorf, Maryland, with an originally expected commercial operation date of June 1, 2015 (which is now deferred pending the outcome of the proceedings discussed below), and each of the Contract EDCs was to recover its costs associated with the contract through surcharges on its respective SOS customers.

In response to a complaint filed by a group of generating companies in the PJM region, in September 2013, the U.S. District Court for the District of Maryland (the Federal District Court) issued a ruling that the MPSC’s April 2012 order violated the Supremacy Clause of the U.S. Constitution by attempting to regulate wholesale prices. In contrast, in October 2013, in response to appeals filed by the Contract EDCs and other parties, the Maryland Circuit Court for Baltimore City (the Maryland Circuit Court) upheld the MPSC’s orders requiring the Contract EDCs to enter into the contracts.

In October 2013, the Federal District Court issued an order ruling that the contracts are illegal and unenforceable. The Contract EDCs, the Maryland Office of People’s Counsel and one generating company have appealed the Maryland Circuit Court’s decision to the Maryland Court of Special Appeals. In addition, in November 2013 both the winning bidder and the MPSC appealed the Federal District Court decision to the U.S. Court of Appeals for the Fourth Circuit, which affirmed the decision. In November 2014, the winning bidder and the MPSC each petitioned the U.S. Supreme Court to consider hearing an appeal of the Fourth Circuit decision and, on October 19, 2015, the U.S. Supreme Court agreed to review that decision.

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Assuming the contracts, as currently written, become effective following the satisfaction of all relevant conditions, including the completion of the proceedings discussed above, DPL continues to believe that it may be required to record its proportional share of the contracts as derivative instruments at fair value and record related regulatory assets of approximately the same amount because it would be entitled to recover any payments under the contracts from SOS customers. DPL has concluded that any accounting for these contracts would not be required until all legal proceedings related to these contracts and the actions of the MPSC in the related proceeding have been resolved.

Merger Approval Proceedings

Delaware

On June 18, 2014, Exelon, PHI and DPL, and certain of their respective affiliates, filed an application with the DPSC seeking approval of the Merger. Delaware law requires the DPSC to approve the Merger when it determines that the transaction is in accordance with law, for a proper purpose, and is consistent with the public interest. The DPSC must further find that the successor will continue to provide safe and reliable service, will not terminate or impair existing collective bargaining agreements and will engage in good faith bargaining with organized labor. On February 13, 2015, Exelon, DPL, the DPSC staff, the Division of the Public Advocate and certain other parties filed a settlement agreement with the DPSC, which was amended in April 2015. The DPSC approved the amended settlement agreement at its meeting held on May 19, 2015, memorializing this decision by written order issued on June 2, 2015. The specific grounds for the DPSC’s approval of the Merger, as well as the specific conditions, will be included in an order to be issued by the DPSC after the Merger closes.

Maryland

On August 19, 2014, Exelon, PHI, Pepco, DPL and certain of their respective affiliates, filed an application with the MPSC seeking approval of the Merger. Maryland law requires the MPSC to approve a merger subject to its review if it finds that the merger is consistent with the public interest, convenience and necessity, including its benefits to and impact on consumers. Evidentiary hearings were held beginning on January 26, 2015. On March 10, 2015, Exelon, PHI, Pepco, DPL and certain of their respective affiliates, filed with the MPSC a settlement agreement entered into with one of the stakeholder groups participating in the MPSC approval proceeding. On March 16, 2015, Exelon, PHI, Pepco, DPL and certain of their respective affiliates, filed with the MPSC a settlement agreement entered into with Montgomery and Prince George’s Counties in Maryland, and a number of other parties. On May 15, 2015, the MPSC approved the Merger, with conditions, including conditions that modify and supplement those originally proposed. On May 18, 2015, Pepco Holdings and Exelon announced that they had completed their review of the MPSC’s order approving the Merger and have committed to fulfill the modified, more stringent conditions and package of customer benefits imposed by the MPSC.

Multiple parties have filed petitions for judicial review of the MPSC order by the Circuit Court of Queen Anne’s County, Maryland, seeking to appeal the MPSC order. In connection with these proceedings, the Maryland Office of People’s Counsel and several other parties to the Merger proceedings filed motions in the Circuit Court for Queen Anne’s County, Maryland, requesting a stay of the MPSC order. On August 7, 2015, the Circuit Court for Queen Anne’s County denied the motions for stay. On January 8, 2016, the Circuit Court affirmed the MPSC’s order in all respects. On January 20 and 22, 2016, respectively, the Maryland Office of People’s Counsel and environmental groups filed notices of appeal of the Circuit Court’s order to the Maryland Court of Special Appeals. Unless a motion to stay is filed and then granted by the court, the MPSC order will remain in effect during the appeals process.

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Virginia

On June 3, 2014, Exelon, PHI, Pepco and DPL, and certain of their respective affiliates, filed an application with the VSCC seeking approval of the Merger. Virginia law provides that, if the VSCC determines, with or without hearing, that adequate service to the public at just and reasonable rates will not be impaired or jeopardized by granting the application for approval, then the VSCC shall approve a merger with such conditions that the VSCC deems to be appropriate in order to satisfy this standard. On October 7, 2014, the VSCC issued an order approving the Merger.

Federal Energy Regulatory Commission

On May 30, 2014, Exelon, PHI, Pepco, DPL and ACE, and certain of their respective affiliates, submitted to FERC a Joint Application for Authorization of Disposition of Jurisdictional Assets and Merger under Section 203 of the Federal Power Act. Under that section, FERC shall approve a merger if it finds that the proposed transaction will be consistent with the public interest. On November 20, 2014, FERC issued an order approving the Merger.

(8) PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment is comprised of the following:

	Original Cost		Accumulated Depreciation		Net Book Value
	(millions of dollars)
At December 31, 2015
Distribution	$	2,043	$	490	$	1,553
Transmission		1,208		259		949
Gas		546		163		383
Construction work in progress		107		—		107
Non-operating and other property		305		134		171
Total	$	4,209	$	1,046	$	3,163
At December 31, 2014
Distribution	$	1,928	$	489	$	1,439
Transmission		1,107		248		859
Gas		511		153		358
Construction work in progress		125		—		125
Non-operating and other property		275		131		144
Total	$	3,946	$	1,021	$	2,925

The non-operating and other property amounts include balances for general plant, plant held for future use, intangible plant and non-utility property. Utility plant is generally subject to a first mortgage lien.

(9) PENSION AND OTHER POSTRETIREMENT BENEFITS

DPL accounts for its participation in PHI’s single-employer plans, the PHI Retirement Plan and its other postretirement benefits plan, the Pepco Holdings, Inc. Welfare Plan for Retirees (the OPEB Plan), as participation in multiemployer plans. For 2015, 2014 and 2013, DPL was responsible for $15 million, $7 million and $18 million, respectively, of the pension and other postretirement net periodic benefit cost incurred by PHI. DPL made a discretionary tax-deductible contribution to the PHI Retirement Plan of zero, zero and $10 million for the years ended December 31, 2015, 2014 and 2013, respectively. In addition, DPL made contributions of zero, zero and $3 million, respectively, to the OPEB Plan for the years ended December 31, 2015, 2014 and 2013. At December 31, 2015 and 2014, DPL’s Prepaid

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pension expense of $205 million and $220 million, respectively, and Other postretirement benefit obligations of $19 million and $21 million, respectively, effectively represent assets and benefit obligations resulting from DPL’s participation in the PHI benefit plans.

Other Postretirement Benefit Plan Amendments

During 2013, PHI approved two amendments to its other postretirement benefits plan. These amendments impacted the retiree medical plan and the retiree life insurance benefits, and became effective on January 1, 2014. As a result of the amendments, which were cumulatively significant, PHI remeasured its projected benefit obligation for other postretirement benefits as of July 1, 2013. The remeasurement resulted in a $4 million reduction in DPL’s net periodic benefit cost for other postretirement benefits in 2014, when compared to 2013.

(10) DEBT

Long-Term Debt

The components of long-term debt are shown in the table below:

Type of Debt	Interest Rate	Maturity	2015			2014
			(millions of dollars)
First Mortgage Bonds
	5.22%(a)	2016	$	100		$	100
	3.50%	2023		500			500
	4.00%	2042		250			250
	4.15%	2045		200			—
				1,050			850
Unsecured Tax-Exempt Bonds
	5.40%	2031		78			78
				78			78
Medium-Term Notes (unsecured)
	7.56%-7.58%	2017		14			14
	6.81%	2018		4			4
	7.61%	2019		12			12
	7.72%	2027		10			10
				40			40
Notes (unsecured)
	5.00%	2015		—			100
				—			100
Total long-term debt				1,168			1,068
Net unamortized premium				2			3
Unamortized debt issuance costs				(9	)		(8	)
Current portion of long-term debt				(100	)		(100	)
Total net long-term debt			$	1,061		$	963

(a) Represents a series of Collateral First Mortgage Bonds securing a series of debt securities issued by DPL.

The outstanding first mortgage bonds issued by DPL are issued under a Mortgage and Deed of Trust and are secured by a first lien on substantially all of DPL’s property, plant and equipment, except for certain property excluded from the lien of the mortgage.

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Maturities of DPL’s long-term debt outstanding at December 31, 2015 are $100 million in 2016, $14 million in 2017, $4 million in 2018, $12 million in 2019, zero in 2020 and $1,038 million thereafter.

DPL’s long-term debt is subject to certain covenants. As of December 31, 2015, DPL is in compliance with all such covenants.

The table above does not separately identify $100 million in aggregate principal amount of debt securities issued by DPL. These debt securities are secured by a like amount of first mortgage bonds (Collateral First Mortgage Bonds) of DPL. The principal terms of each such series of debt securities are identical to the same terms of the corresponding series of Collateral First Mortgage Bonds. Payments of principal and interest made on a series of such debt securities, satisfy the corresponding obligations on the related series of Collateral First Mortgage Bonds. For these reasons, each such series of Collateral First Mortgage Bonds and the corresponding debt securities together effectively represent a single financial obligation and are not identified in the table above separately.

Bond Issuance

During 2015, DPL issued $200 million of 4.15% first mortgage bonds due May 15, 2045. Net proceeds from the issuance of the bonds were used by DPL to repay outstanding commercial paper and for general corporate purposes.

Note Retirements

During 2015, DPL retired, at maturity, $100 million of its 5.00% unsecured notes due June 1, 2015.

Short-Term Debt

DPL has traditionally used a number of sources to fulfill short-term funding needs, such as commercial paper, short-term notes, and bank lines of credit. Proceeds from short-term borrowings are used primarily to meet working capital needs, but may also be used to temporarily fund long-term capital requirements. The components of DPL’s short-term debt at December 31, 2015 and 2014 are as follows:

	2015		2014
	(millions of dollars)
Commercial paper	$	105	$	106
Variable rate demand bonds		105		105
Total	$	210	$	211

Commercial Paper

DPL maintains an ongoing commercial paper program to address its short-term liquidity needs. As of December 31, 2015, the maximum capacity available under the program was $500 million, subject to available borrowing capacity under the credit facility.

DPL had $105 million and $106 million of commercial paper outstanding at December 31, 2015 and 2014, respectively. The weighted average interest rates for commercial paper issued by DPL during 2015 and 2014 were 0.47% and 0.26%, respectively. The weighted average maturity of all commercial paper issued by DPL during 2015 and 2014 was four days and five days, respectively.

Variable Rate Demand Bonds

Variable Rate Demand Bonds (VRDBs) are subject to repayment on the demand of the holders and, for this reason, are accounted for as short-term debt in accordance with accounting principles generally accepted in the United States of America. However, bonds submitted for purchase are remarketed by a remarketing agent on a best efforts basis. DPL expects that any bonds submitted for purchase will

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continue to be remarketed successfully due to the creditworthiness of the company and because the remarketing agent resets the interest rate to the then-current market rate. The bonds may be converted to a fixed rate, fixed term option to establish a maturity which corresponds to the date of final maturity of the bonds. On this basis, DPL views VRDBs as a source of long-term financing. The VRDBs outstanding in 2015 mature as follows: 2017 ($26 million), 2024 ($33 million), 2028 ($16 million), and 2029 ($30 million). The weighted average interest rate for VRDBs was 0.13% during 2015 and 0.19% during 2014. As of December 31, 2015, $105 million in VRDBs issued on behalf of DPL were outstanding (of which $72 million were secured by Collateral First Mortgage Bonds issued by DPL).

Credit Facility

PHI, Pepco, DPL and ACE maintain an unsecured syndicated credit facility to provide for their respective liquidity needs, including obtaining letters of credit, borrowing for general corporate purposes and supporting their commercial paper programs. On August 1, 2013, as permitted under the existing terms of the credit agreement, a request by PHI, Pepco, DPL and ACE to extend the credit facility termination date to August 1, 2018 was approved. All of the terms and conditions as well as pricing remained the same.

The aggregate borrowing limit under the amended and restated credit facility is $1.5 billion, all or any portion of which may be used to obtain loans and up to $500 million of which may be used to obtain letters of credit. The facility also includes a swingline loan sub-facility, pursuant to which each company may make same day borrowings in an aggregate amount not to exceed 10% of the total amount of the facility. Any swingline loan must be repaid by the borrower within fourteen days of receipt. The credit sublimit is $750 million for PHI and $250 million for each of Pepco, DPL and ACE. The sublimits may be increased or decreased by the individual borrower during the term of the facility, except that (i) the sum of all of the borrower sublimits following any such increase or decrease must equal the total amount of the facility, and (ii) the aggregate amount of credit used at any given time by (a) PHI may not exceed $1.25 billion, and (b) each of Pepco, DPL or ACE may not exceed the lesser of $500 million or the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the sublimit reallocations may not exceed eight per year during the term of the facility.

The interest rate payable by each company on utilized funds is, at the borrowing company’s election, (i) the greater of the prevailing prime rate, the federal funds effective rate plus 0.5% and the one month London Interbank Offered Rate plus 1.0%, or (ii) the prevailing Eurodollar rate, plus a margin that varies according to the credit rating of the borrower.

In order for a borrower to use the facility, certain representations and warranties must be true and correct, and the borrower must be in compliance with specified financial and other covenants, including (i) the requirement that each borrowing company maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the credit agreement, which calculation excludes from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) with certain exceptions, a restriction on sales or other dispositions of assets, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than permitted liens. The credit agreement contains certain covenants and other customary agreements and requirements that, if not complied with, could result in an event of default and the acceleration of repayment obligations of one or more of the borrowers thereunder. Each of the borrowers was in compliance with all covenants under this facility at December 31, 2015.

The absence of a material adverse change in PHI’s business, property, results of operations or financial condition is not a condition to the availability of credit under the credit agreement. The credit agreement does not include any rating triggers.

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As of December 31, 2015 and 2014, the amount of cash plus borrowing capacity under the credit facility available to meet the liquidity needs of PHI’s utility subsidiaries in the aggregate was $576 million and $413 million, respectively. DPL’s borrowing capacity under the credit facility at any given time depends on the amount of the subsidiary borrowing capacity being utilized by Pepco and ACE and the portion of the total capacity being used by PHI.

Credit Facility Amendment

During 2014, PHI, Pepco, DPL and ACE entered into an amendment of and consent with respect to the credit agreement (the Consent). PHI was required to obtain the consent of certain of the lenders under the credit facility in order to permit the consummation of the Merger. Pursuant to the Consent, certain of the lenders consented to the consummation of the Merger and the subsequent conversion of PHI from a Delaware corporation to a Delaware limited liability company, provided that the Merger and subsequent conversion are consummated on or before October 29, 2015. In addition, the Consent amends the definition of “Change in Control” in the credit agreement to mean, following consummation of the Merger, an event or series of events by which Exelon no longer owns, directly or indirectly, 100% of the outstanding shares of voting stock of Pepco Holdings. PHI requested and obtained an extension of the Consent to allow for completion of the Merger by June 30, 2016.

(11) INCOME TAXES

DPL, as an indirect subsidiary of PHI, is included in the consolidated federal income tax return of PHI. Federal income taxes are allocated to DPL pursuant to a written tax sharing agreement that was approved by the Securities and Exchange Commission in connection with the establishment of PHI as a holding company. Under this tax sharing agreement, PHI’s consolidated federal income tax liability is allocated based upon PHI’s and its subsidiaries’ separate taxable income or loss.

The provision for income taxes, reconciliation of income tax expense, and components of deferred income tax liabilities (assets) are shown below.

Provision for Income Taxes

	For the Year Ended December 31,
	2015			2014			2013
	(millions of dollars)
Current Tax (Benefit) Expense
Federal	$	(26	)	$	(45	)	$	(8	)
State and local		2			—			—
Total Current Tax Benefit		(24	)		(45	)		(8	)
Deferred Tax Expense (Benefit)
Federal		73			99			53
State and local		1			12			12
Investment tax credit amortization		(1	)		(1	)		(1	)
Total Deferred Tax Expense		73			110			64
Total Income Tax Expense	$	49		$	65		$	56

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Reconciliation of Income Tax Expense

	For the Year Ended December 31,
	2015					2014					2013
	(millions of dollars)
Income tax at Federal statutory rate	$	44		35.0	%	$	59		35.0	%	$	51		35.0	%
Increases (decreases) resulting from:
State income taxes, net of federal effect		7		5.6	%		9		5.3	%		8		5.5	%
Change in estimates and interest related to uncertain and effectively settled tax positions		3		2.4	%		—		—			(1	)	(0.7	)%
Other, net		(5	)	(3.8	)%		(3	)	(1.8	)%		(2	)	(1.2	)%
Income Tax Expense	$	49		39.2	%	$	65		38.5	%	$	56		38.6	%

Global Tax Settlement

On November 18, 2015, PHI entered into a settlement with the Internal Revenue Service (IRS) and the Department of Justice (DOJ) (the Global Tax Settlement) to provide for the resolution of the tax treatment of its previously held cross-border energy lease investments involving public utility assets located outside of the United States structured as sale-in, lease-out, or SILO, transactions. The Global Tax Settlement followed the acceptance by PHI on October 29, 2015 of IRS revenue agent reports covering adjustments incorporated in the terms of the Global Tax Settlement, as well as adjustments for all other tax matters in dispute with the IRS. The Global Tax Settlement and the revenue agent reports, together, effectively close all years open to examination of federal income tax liabilities for PHI and DPL through 2011, and all matters associated with the cross-border energy lease investments through 2013.

As a result of the Global Tax Settlement, DPL recorded in the fourth quarter of 2015 tax expense of $3 million which is included above in Change in estimates and interest related to uncertain and effectively settled tax positions. The tax charge recorded of $3 million primarily represents uncertain tax positions that were settled in favor of the IRS in the Global Tax Settlement. Included in the tax expense of $3 million was an after-tax interest benefit of less than $1 million associated with DPL’s uncertain tax positions. The interest benefit represented DPL’s allocated share of an overall net interest benefit for PHI’s consolidated group of $21 million resulting from the Global Tax Settlement assuming DPL was a separate taxpayer.

Other Tax Matter

On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States (to which DPL is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. As a result of the court’s ruling in this case, PHI determined in the first quarter of 2013 that it could no longer support its current assessment with respect to the likely outcome of tax positions associated with its cross-border energy lease investments held by its wholly owned subsidiary Potomac Capital Investment Corporation, and PHI recorded an after-tax charge of $377 million in the first quarter of 2013. Included in the $377 million charge was an after-tax interest charge of $54 million and this amount was allocated to each member of PHI’s consolidated group as if each member was a separate taxpayer, resulting in DPL recording a $1 million (after-tax) interest benefit in the first quarter of 2013, which is included above in Change in estimates and interest related to uncertain and effectively settled tax positions.

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DPL

Components of Deferred Income Tax Liabilities (Assets)

	As of December 31,
	2015			2014
	(millions of dollars)
Deferred Tax Liabilities (Assets)
Depreciation and other basis differences related to plant and equipment	$	899		$	797
Deferred taxes on amounts to be collected through future rates		15			19
Federal and state net operating losses		(122	)		(115	)
Pension and other postretirement benefits		75			80
Electric restructuring liabilities		(4	)		(4	)
Other		78			101
Total Deferred Tax Liabilities, net	$	941		$	878

The net deferred tax liability represents the tax effect, at presently enacted tax rates, of temporary differences between the financial statement basis and tax basis of assets and liabilities. The portion of the net deferred tax liability applicable to DPL’s operations, which has not been reflected in current service rates, represents income taxes recoverable through future rates, net, and is recorded as a regulatory asset on the balance sheet. No valuation allowance for deferred tax assets was required or recorded at December 31, 2015 and 2014. Federal and state net operating losses generally expire over 20 years from 2029 to 2034.

The Tax Reform Act of 1986 repealed the investment tax credit for property placed in service after December 31, 1985, except for certain transition property. Investment tax credits previously earned on DPL’s property continue to be amortized to income over the useful lives of the related property.

Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits

	2015			2014			2013
	(millions of dollars)
Balance as of January 1	$	22		$	9		$	9
Tax positions related to current year:
Additions		—			1			—
Reductions		—			—			—
Tax positions related to prior years:
Additions		3			13			—
Reductions		(13	)(a)		(1	)		—
Settlements		(9	)(a)		—			—
Balance as of December 31	$	3		$	22		$	9

(a) Reductions and settlements in 2015 resulted from the Global Tax Settlement. Settlements represent unrecognized tax benefits that were satisfied with cash or use of net operating losses and tax credits.

Unrecognized Benefits That, If Recognized, Would Affect the Effective Tax Rate

Unrecognized tax benefits are related to tax positions that have been taken or are expected to be taken in tax returns that are not recognized in the financial statements because management has either measured the tax benefit at an amount less than the benefit claimed, or expected to be claimed, or has concluded that it is not more likely than not that the tax position will be ultimately sustained. For the majority of these tax positions, the ultimate deductibility is highly certain, but there is uncertainty about the timing of such deductibility. At December 31, 2015, DPL had $3 million of unrecognized tax benefits that, if recognized, would lower the effective tax rate.

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Interest and Penalties

DPL recognizes interest and penalties relating to its uncertain tax positions as an element of income tax expense. For each of the years ended December 31, 2015, 2014 and 2013, DPL recognized less than $1 million of pre-tax interest income as a component of income tax expense. As of December 31, 2015, 2014 and 2013, DPL had accrued interest receivable of zero, $2 million and $2 million, respectively, related to effectively settled and uncertain tax positions.

Possible Changes to Unrecognized Tax Benefits

It is reasonably possible that the amount of the unrecognized tax benefit with respect to some of DPL’s uncertain tax positions will significantly increase or decrease within the next 12 months. At this time, it is estimated that there will be no decrease in unrecognized tax benefits within the next 12 months.

Tax Years Open to Examination

DPL, as an indirect subsidiary of PHI, is included on PHI’s consolidated Federal tax return. As a result of the Global Tax Settlement described above, DPL’s federal income tax liabilities for all years through 2011 have been determined, subject to adjustment to the extent of any net operating loss or other loss or credit carrybacks from subsequent years. The open tax years for the significant states where DPL files state income tax returns (Maryland and Delaware) are the same as for the Federal returns.

Final IRS Regulations on Repair of Tangible Property

In August 2011, the IRS issued Revenue Procedure 2011-43 providing a safe harbor method of tax accounting for repair costs associated with electric transmission and distribution property. In September 2012, with the filing of its 2011 tax return, PHI adopted the safe harbor for the 2011 tax year. In September 2013, the IRS published final regulations regarding the tax treatment of costs incurred to acquire, produce or improve tangible property. In February 2014, the IRS issued revenue procedures that describe how taxpayers should implement the final regulations. The final repair regulations and the related revenue procedures did not modify the guidance set forth in Revenue Procedure 2011-43 that the Unit of Property for electric transmission and distribution network assets is determined by the taxpayer’s particular facts and circumstances. The final regulations did not have a material impact on DPL’s financial statements.

Other Taxes

Taxes other than income taxes for each year are shown below. These amounts are recoverable through rates.

	2015		2014		2013
	(millions of dollars)
Gross Receipts/Delivery	$	17	$	16	$	15
Property		28		24		24
Environmental, Use and Other		2		2		1
Total	$	47	$	42	$	40

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(12) DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

DPL uses derivative instruments in the form of futures primarily to reduce natural gas commodity price volatility and to limit its customers’ exposure to increases in the market price of natural gas under a hedging program approved by the DPSC. DPL uses these derivatives to manage the commodity price risk associated with its physical natural gas purchase contracts. The natural gas purchase contracts qualify as normal purchases, which are not required to be recorded in the financial statements until settled. All premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all gains and losses related to hedging activities, are deferred under FASB guidance on regulated operations (ASC 980) until recovered from its customers through a fuel adjustment clause approved by the DPSC.

The tables below identify the balance sheet location and fair values of derivative instruments as of December 31, 2015 and 2014:

	As of December 31, 2015
Balance Sheet Caption	Derivatives Designated as Hedging Instruments		Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting		Net Derivative Instruments
	(millions of dollars)
Derivative liabilities (current liabilities)	$	—	$	(2	)	$	(2	)	$	2	$	—

	As of December 31, 2014
Balance Sheet Caption	Derivatives Designated as Hedging Instruments		Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting		Net Derivative Instruments
	(millions of dollars)
Derivative liabilities (current liabilities)	$	—	$	(4	)	$	(4	)	$	4	$	—

All derivative liabilities available to be offset under master netting arrangements were netted as of December 31, 2015 and 2014. The amount of cash collateral that was offset against these derivative positions is as follows:

	December 31, 2015		December 31, 2014
	(millions of dollars)
Cash collateral pledged to counterparties with the right reclaim (a)	$	2	$	4

(a) Includes cash deposits on commodity brokerage accounts.

As of December 31, 2015 and 2014, all DPL cash collateral pledged related to derivative instruments accounted for at fair value was entitled to be offset under master netting agreements.

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Other Derivative Activity

DPL has certain derivatives that are not in hedge accounting relationships and are not designated as normal purchases or normal sales. These derivatives are recorded at fair value on the balance sheets with the gain or loss for changes in the fair value recorded in income. In addition, in accordance with FASB guidance on regulated operations, regulatory liabilities or regulatory assets of the same amount are recorded on the balance sheets and the recognition of the derivative gain or loss is deferred because of the DPSC-approved fuel adjustment clause. The following table shows the net unrealized and net realized derivative gains and losses arising during the period associated with these derivatives that were recognized in the statements of income (through Purchased energy and Gas purchased expense) and that were also deferred as regulatory liabilities and regulatory assets, respectively, for the years ended December 31, 2015, 2014 and 2013:

	For the Year Ended December 31,
	2015			2014			2013
	(millions of dollars)
Net unrealized (loss) gain arising during the period	$	(3	)	$	(3	)	$	1
Net realized (loss) gain recognized during the period		(5	)		2			(4	)

As of December 31, 2015 and 2014, the quantities and positions of DPL’s net outstanding natural gas commodity forward contracts that did not qualify for hedge accounting were:

	December 31, 2015			December 31, 2014
Commodity	Quantity		Net Position	Quantity		Net Position
Natural Gas (One Million British Thermal Units)		4,190,000	Long		3,892,500	Long

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(13) FAIR VALUE DISCLOSURES

Financial Instruments Measured at Fair Value on a Recurring Basis

DPL applies FASB guidance on fair value measurement (ASC 820) that established a framework for measuring fair value and expanded disclosures about fair value measurements. As defined in the guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). DPL utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. Accordingly, DPL utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1) and the lowest priority to unobservable inputs (level 3).

The following tables set forth, by level within the fair value hierarchy, DPL’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2015 and 2014. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. DPL’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Fair Value Measurements at December 31, 2015
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1) (a)		Significant Other Observable Inputs (Level 2) (a)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Derivative instruments (b)
Natural gas (c)	$	2	$	2	$	—	$	—
Executive deferred compensation plan liabilities
Life insurance contracts		1		—		1		—
Total	$	3	$	2	$	1	$	—

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2015.

(b) The fair value of derivative liabilities reflect netting by counterparty before the impact of collateral.

(c) Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.

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	Fair Value Measurements at December 31, 2014
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1) (a)		Significant Other Observable Inputs (Level 2) (a)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Restricted cash equivalents
Treasury funds	$	5	$	5	$	—	$	—
Executive deferred compensation plan assets
Money market funds		1		1		—		—
Life insurance contracts		1		—		—		1
Total	$	7	$	6	$	—	$	1
LIABILITIES
Derivative instruments (b)
Natural gas (c)	$	4	$	4	$	—	$	—
Executive deferred compensation plan liabilities
Life insurance contracts		1		—		1		—
Total	$	5	$	4	$	1	$	—

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2014.

(b) The fair value of derivative liabilities reflect netting by counterparty before the impact of collateral.

(c) Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.

DPL classifies its fair value balances in the fair value hierarchy based on the observability of the inputs used in the fair value calculation as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis, such as the Intercontinental Exchange.

Level 2 – Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using broker quotes in liquid markets and other observable data. Level 2 also includes those financial instruments that are valued using methodologies that have been corroborated by observable market data through correlation or by other means. Significant assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

Level 2 executive deferred compensation plan liabilities associated with the life insurance policies represent a deferred compensation obligation, the value of which is tracked via underlying insurance sub-accounts. The sub-accounts are designed to mirror existing mutual funds and money market funds that are observable and actively traded.

Level 3 – Pricing inputs that are significant and generally less observable than those from objective sources. Level 3 includes those financial instruments that are valued using models or other valuation methodologies.

Executive deferred compensation plan assets include certain life insurance policies that are valued using the cash surrender value of the policies, net of loans against those policies. The cash surrender values do not represent a quoted price in an active market; therefore, those inputs are unobservable and the policies are categorized as level 3. Cash surrender values are provided by third parties and reviewed by DPL for reasonableness.

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Reconciliations of the beginning and ending balances of DPL’s fair value measurements using significant unobservable inputs (Level 3) for the years ended December 31, 2015 and 2014 are shown below:

	Year Ended December 31, 2015			Year Ended December 31, 2014
	Life Insurance Contracts			Life Insurance Contracts
	(millions of dollars)
Balance as of January 1	$	1		$	1
Total gains (losses) (realized and unrealized):
Included in income		—			—
Included in accumulated other comprehensive loss		—			—
Included in regulatory liabilities		—			—
Purchases		—			—
Issuances		—			—
Settlements		(1	)		—
Transfers in (out) of Level 3		—			—
Balance as of December 31	$	—		$	1

Other Financial Instruments

The estimated fair values of DPL’s Long-term debt instruments that are measured at amortized cost in DPL’s financial statements and the associated levels of the estimates within the fair value hierarchy as of December 31, 2015 and 2014 are shown in the tables below. As required by the fair value measurement guidance, debt instruments are classified in their entirety within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. DPL’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, which may affect the valuation of fair value debt instruments and their placement within the fair value hierarchy levels.

The fair value of Long-term debt categorized as level 2 is based on a blend of quoted prices for the debt and quoted prices for similar debt on the measurement date. The blend places more weight on current pricing information when determining the final fair value measurement. The fair value information is provided by brokers, and DPL reviews the methodologies and results.

The fair value of Long-term debt categorized as level 3 is based on a discounted cash flow methodology using observable inputs, such as the U.S. Treasury yield, and unobservable inputs, such as credit spreads, because quoted prices for the debt or similar debt in active markets were insufficient.

	Fair Value Measurements at December 31, 2015
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	1,183	$	—	$	1,080	$	103

(a) The carrying amount for Long-term debt, including unamortized premium, was $1,170 million as of December 31, 2015.

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DPL

	Fair Value Measurements at December 31, 2014
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	1,123	$	—	$	1,016	$	107

(a) The carrying amount for Long-term debt, including unamortized premium, was $1,071 million as of December 31, 2014.

The carrying amounts of all other financial instruments in the accompanying financial statements approximate fair value.

(14) COMMITMENTS AND CONTINGENCIES

General Litigation

From time to time, DPL is named as a defendant in litigation, usually relating to general liability or auto liability claims that resulted in personal injury or property damage to third parties. DPL is self-insured against such claims up to a certain self-insured retention amount and maintains insurance coverage against such claims at higher levels, to the extent deemed prudent by management. In addition, DPL’s contracts with its vendors generally require the vendors to name DPL as an additional insured for the amount at least equal to DPL’s self-insured retention. Further, DPL’s contracts with its vendors require the vendors to indemnify DPL for various acts and activities that may give rise to claims against DPL. Loss contingency liabilities for both asserted and unasserted claims are recognized if it is probable that a loss will result from such a claim and if the amounts of the losses can be reasonably estimated. Although the outcome of the claims and proceedings cannot be predicted with any certainty, management believes that there are no existing claims or proceedings that are likely to have a material adverse effect on DPL’s financial condition, results of operations or cash flows. At December 31, 2015, DPL had recorded estimated loss contingency liabilities for general litigation totaling approximately $3 million.

Environmental Matters

DPL is subject to regulation by various federal, regional, state, and local authorities with respect to the environmental effects of its operations, including air and water quality control, solid and hazardous waste disposal and limitations on land use. Although penalties assessed for violations of environmental laws and regulations are not recoverable from DPL’s customers, environmental clean-up costs incurred by DPL generally are included in its cost of service for ratemaking purposes. The total accrued liabilities for the environmental contingencies of DPL described below at December 31, 2015 are summarized as follows:

	Transmission and Distribution			Legacy Generation - Regulated			Total
	(millions of dollars)
Balance as of January 1	$	1		$	2		$	3
Accruals		3			—			3
Payments		(2	)		(1	)		(3	)
Balance as of December 31		2			1			3
Less amounts in Other Current Liabilities		1			1			2
Amounts in Other Deferred Credits	$	1		$	—		$	1

310

DPL

Metal Bank Site

In the first quarter of 2013, the National Oceanic and Atmospheric Administration (NOAA) contacted DPL on behalf of itself and other federal and state trustees to request that DPL execute a tolling agreement to facilitate settlement negotiations concerning natural resource damages allegedly caused by releases of hazardous substances, including polychlorinated biphenyls, at the Metal Bank Cottman Avenue Superfund Site located in Philadelphia, Pennsylvania. DPL executed a tolling agreement, which has been extended to March 15, 2016, and will continue settlement discussions with the NOAA, the trustees and other potentially responsible parties.

The amount accrued for this matter is included in the table above in the column entitled “Transmission and Distribution.”

Virginia Department of Environmental Quality Notice of Violation

On February 3, 2015, the Virginia Department of Environmental Quality (VDEQ) issued a notice of violation (NOV) to DPL in connection with alleged violations of state water control laws and regulations associated with recent construction activities undertaken to replace certain transmission facilities. The NOV informed DPL of information on which VDEQ may rely to institute an administrative or judicial enforcement action, requested a meeting, and stated that DPL may be asked to enter into a consent order to formalize a plan and schedule of corrective action and settle any outstanding issues regarding the matter including the assessment of civil charges. At a February 20, 2015 meeting, VDEQ confirmed that the NOV would be resolved through a consent order, which will require the payment of a penalty, but did not specify the potential penalty amount. DPL will pursue recovery of the restoration costs for this matter from the contractor responsible for the vegetation management activities that gave rise to the alleged violations. DPL has substantially completed all remediation activities related to this matter and does not believe that the potential penalty to resolve this matter will have a material adverse effect on its financial condition, results of operations or cash flows.

Contractual Obligations

Power Purchase Contracts

As of December 31, 2015, DPL’s contractual obligations under non-derivative power purchase contracts were $64 million in 2016, $127 million in 2017 to 2018, $128 million in 2019 to 2020 and $296 million thereafter.

Lease Commitments

DPL leases an 11.9% interest in the Merrill Creek Reservoir. The lease is an operating lease and payments over the remaining lease term, which ends in 2032, are $75 million in the aggregate. DPL also has long-term leases for certain other facilities and equipment. Total future minimum operating lease payments for DPL, including the Merrill Creek Reservoir lease, as of December 31, 2015, are $13 million in 2016, $12 million in 2017, $16 million in 2018, $6 million in 2019, $9 million in 2020 and $118 million thereafter.

Rental expense for operating leases, including the Merrill Creek Reservoir lease, was $14 million, $14 million and $13 million for the years ended December 31, 2015, 2014 and 2013, respectively.

311

DPL

(15) RELATED PARTY TRANSACTIONS

PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries, including DPL. The cost of these services is allocated in accordance with cost allocation methodologies set forth in the service agreement using a variety of factors, including the subsidiaries’ share of employees, operating expenses, assets and other cost methods. These intercompany transactions are eliminated by PHI in consolidation and no profit results from these transactions at PHI. PHI Service Company costs directly charged or allocated to DPL for the years ended December 31, 2015, 2014 and 2013 were $179 million, $163 million and $154 million, respectively.

Pepco Energy Services, Inc. and its subsidiaries (Pepco Energy Services) performs high voltage underground transmission cabling, including services that are treated as capital costs, for DPL. Amounts charged to DPL by Pepco Energy Services for the years ended December 31, 2015, 2014 and 2013 were approximately $3 million, zero and zero, respectively.

In addition to the PHI Service Company charges described above, DPL’s financial statements include the following related party transactions in its statements of income:

	For the Year Ended December 31,
	2015		2014		2013
	(millions of dollars)
Intercompany lease transactions (a)	$	4	$	5	$	4

(a) Included in Electric revenue.

As of December 31, 2015 and 2014, DPL had the following balances on its balance sheets due to related parties:

	2015			2014
	(millions of dollars)
Payable to Related Party (current) (a)
PHI Service Company	$	(19	)	$	(18	)
Other		(1	)		1
Total	$	(20	)	$	(17	)

(a) Included in Accounts payable due to associated companies.

312

DPL

(16) QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

The quarterly data presented below reflect all adjustments necessary, in the opinion of management, for a fair presentation of the interim results. Quarterly data normally vary seasonally because of temperature variations and differences between summer and winter rates. Therefore, comparisons by quarter within a year are not meaningful.

	2015
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(millions of dollars)
Total Operating Revenue	$	423		$	275		$	317		$	303		$	1,318
Total Operating Expenses		361			251			285			256			1,153
Operating Income		62			24			32			47			165
Other Expenses		(9	)		(11	)		(8	)		(12	)		(40	)
Income Before Income Tax Expense		53			13			24			35			125
Income Tax Expense		21			5			9			14	(a)		49
Net Income	$	32		$	8		$	15		$	21		$	76

(a) Includes income tax charge of $3 million associated with the Global Tax Settlement.

	2014
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(millions of dollars)
Total Operating Revenue	$	397		$	279		$	309		$	308		$	1,293
Total Operating Expenses		326			239			264			257			1,086
Operating Income		71			40			45			51			207
Other Expenses		(9	)		(8	)		(9	)		(12	)		(38	)
Income Before Income Tax Expense		62			32			36			39			169
Income Tax Expense		25			13			13			14			65
Net Income	$	37		$	19		$	23		$	25		$	104

(17) VARIABLE INTEREST ENTITIES

DPL is required to consolidate a VIE in accordance with FASB ASC 810 if DPL is the primary beneficiary of the VIE. The primary beneficiary of a VIE is typically the entity with both the power to direct activities most significantly impacting economic performance of the VIE and the obligation to absorb losses or receive benefits of the VIE that could potentially be significant to the VIE. DPL performed a qualitative analysis to determine whether a variable interest provided a controlling financial interest in any of the VIEs in which DPL has an interest at December 31, 2015, as described below.

DPL is subject to Renewable Energy Portfolio Standards (RPS) in the state of Delaware that require it to obtain renewable energy credits (RECs) for energy delivered to its customers. DPL’s costs associated with obtaining RECs to fulfill its RPS obligations are recoverable from its customers by law. As of December 31, 2015, DPL is a party to three land-based wind PPAs in the aggregate amount of 128 MWs, one solar power PPA with a 10 MW facility, and a PPA with the Delaware Sustainable Energy Utility (DSEU) to purchase solar renewable energy credits (SRECs). Each of the facilities associated with these PPAs is operational, except for the facilities associated with the PPA with the DSEU, which are expected to be operational within one year. DPL is obligated to purchase energy and RECs in amounts generated and delivered by the wind facilities and SRECs from the solar facility and the DSEU, up to certain amounts (as set forth below) at rates that are primarily fixed under the respective agreements. DPL has concluded that while VIEs exist under these contracts, consolidation is not required under FASB ASC 810 as DPL is not the primary beneficiary. DPL has not provided financial or other support under these arrangements that it was not previously contractually required to provide during the periods presented, and DPL does not have any intention to provide such additional support.

313

DPL

Because DPL has no equity or debt interest in these renewable energy transactions, the maximum exposure to loss relates primarily to any above-market costs incurred for power, RECs or SRECs. Due to unpredictability in the amount of MWs ultimately purchased under the agreements for purchased renewable energy, RECs and SRECs, DPL is unable to quantify the maximum exposure to loss, however, the power purchase, REC and SREC costs are recoverable from DPL’s customers through regulated rates.

Wind PPAs

DPL is obligated to purchase energy and RECs from one of the wind facilities through 2024 in amounts not to exceed 50 MWs, from the second wind facility through 2031 in amounts not to exceed 40 MWs, and from the third wind facility through 2031 in amounts not to exceed 38 MWs. DPL’s aggregate purchases under the three wind PPAs totaled $29 million, $31 million and $30 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Solar PPAs

The term of the PPA with the solar facility is through 2030 and DPL is obligated to purchase SRECs in an amount up to 70 percent of the energy output at a fixed price. The DSEU may enter into 20-year contracts with solar facilities to purchase SRECs for resale to DPL. Under the PPA with DSEU, at December 31, 2015 and 2014, DPL was obligated to purchase SRECs in amounts not to exceed 28 MWs and 19 MWs, respectively, at annually determined auction rates. DPL’s purchases under these solar agreements totaled $6 million, $6 million and $3 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Fuel Cell Facilities

On October 18, 2011, the DPSC approved a tariff submitted by DPL in accordance with the requirements of the RPS specific to fuel cell facilities totaling 30 MWs to be constructed by a qualified fuel cell provider. The tariff and the RPS establish that DPL acts solely as an agent to collect payments in advance from its distribution customers and remit them to the qualified fuel cell provider for each megawatt hour (MWh) of energy produced by the fuel cell facilities through 2033. The RPS provides for a reduction in DPL’s REC requirements based upon the actual energy output of the facilities. DPL has concluded that while a VIE exists as a result of this relationship, consolidation is not required under FASB ASC 810 as DPL is not the primary beneficiary. For the years ended December 31, 2015 and 2014, 227,113 and 222,948 MWhs, respectively, were produced from fuel cell facilities placed in service under the tariff. DPL billed $37 million, $36 million and $23 million to distribution customers for the years ended December 31, 2015, 2014 and 2013, respectively.

314

ACE

Management’s Report on Internal Control Over Financial Reporting

The management of Atlantic City Electric Company (ACE) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management of ACE assessed ACE’s internal control over financial reporting as of December 31, 2015 based on criteria established in the Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its assessment, the management of ACE concluded that ACE’s internal control over financial reporting was effective as of December 31, 2015.

315

ACE

Report of Independent Registered Public Accounting Firm

To the Shareholder and Board of Directors of

Atlantic City Electric Company

In our opinion, the consolidated financial statements of Atlantic City Electric Company (a wholly owned subsidiary of Pepco Holdings, Inc.) listed in the accompanying index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Atlantic City Electric Company and its subsidiary at December 31, 2015 and December 31, 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule of Atlantic City Electric Company listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Washington, D.C.

February 18, 2016

316

ACE

ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME

For the Year Ended December 31,	2015			2014			2013
	(millions of dollars)
Operating Revenue	$	1,298		$	1,213		$	1,202
Operating Expenses
Purchased energy		685			653			660
Other operation and maintenance		272			246			230
Depreciation and amortization		176			157			136
Other taxes		5			2			14
Deferred electric service costs		30			20			26
Total Operating Expenses		1,168			1,078			1,066
Operating Income		130			135			136
Other Income (Expenses)
Interest expense		(64	)		(63	)		(68	)
Other income		3			1			1
Total Other Expenses		(61	)		(62	)		(67	)
Income Before Income Tax Expense		69			73			69
Income Tax Expense		31			28			19
Net Income	$	38		$	45		$	50

The accompanying Notes are an integral part of these Consolidated Financial Statements.

317

ACE

ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

	December 31, 2015			December 31, 2014
	(millions of dollars)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	3		$	2
Restricted cash equivalents		12			10
Accounts receivable, less allowance for uncollectible accounts of $17 million and $9 million, respectively		211			167
Inventories		23			23
Income taxes and related accrued interest receivable		199			151
Prepaid expenses and other		1			3
Total Current Assets		449			356
OTHER ASSETS
Regulatory assets		322			427
Prepaid pension expense		83			96
Income taxes and related accrued interest receivable		—			34
Restricted cash equivalents		18			14
Other		4			5
Total Other Assets		427			576
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		3,305			3,073
Accumulated depreciation		(764	)		(760	)
Net Property, Plant and Equipment		2,541			2,313
TOTAL ASSETS	$	3,417		$	3,245

The accompanying Notes are an integral part of these Consolidated Financial Statements.

318

ACE

ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

	December 31, 2015		December 31, 2014
	(millions of dollars, except shares)
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Short-term debt	$	5	$	127
Current portion of long-term debt		48		59
Accounts payable		25		20
Accrued liabilities		106		103
Accounts payable due to associated companies		16		15
Taxes accrued		22		1
Interest accrued		13		13
Customer deposits		30		21
Other		21		22
Total Current Liabilities		286		381
DEFERRED CREDITS
Regulatory liabilities		27		14
Deferred income tax liabilities, net		888		855
Investment tax credits		4		5
Other postretirement benefit obligations		33		36
Other		18		16
Total Deferred Credits		970		926
OTHER LONG-TERM LIABILITIES
Long-term debt		1,030		882
Transition bonds issued by ACE Funding		124		170
Total Other Long-Term Liabilities		1,154		1,052
COMMITMENTS AND CONTINGENCIES (NOTE 13)
EQUITY
Common stock, $3.00 par value, 25,000,000 shares authorized, 8,546,017 shares outstanding		26		26
Premium on stock and other capital contributions		746		651
Retained earnings		235		209
Total Equity		1,007		886
TOTAL LIABILITIES AND EQUITY	$	3,417	$	3,245

The accompanying Notes are an integral part of these Consolidated Financial Statements.

319

ACE

ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Year Ended December 31,	2015			2014			2013
	(millions of dollars)
OPERATING ACTIVITIES
Net income	$	38		$	45		$	50
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		176			157			136
Deferred income taxes		30			37			53
Investment tax credit amortization		—			—			(1	)
Changes in:
Accounts receivable		(44	)		18			7
Inventories		—			5			2
Regulatory assets and liabilities, net		21			13			19
Accounts payable and accrued liabilities		12			(13	)		(1	)
Pension contributions		—			—			(30	)
Income tax-related prepayments, receivables and payables		10			(16	)		(6	)
Other assets and liabilities		13			13			12
Net Cash From Operating Activities		256			259			241
INVESTING ACTIVITIES
Investment in property, plant and equipment		(300	)		(225	)		(261	)
Department of Energy capital reimbursement awards received		—			1			2
Net other investing activities		(6	)		—			3
Net Cash Used By Investing Activities		(306	)		(224	)		(256	)
FINANCING ACTIVITIES
Dividends paid to Parent		(12	)		(26	)		(60	)
Capital contributions from Parent		95			—			75
Issuances of long-term debt		150			150			100
Reacquisitions of long-term debt		(58	)		(48	)		(108	)
(Repayments) issuances of short-term debt, net		(122	)		(11	)		6
Repayment of term loan		—			(100	)		—
Net other financing activities		(2	)		(1	)		(1	)
Net Cash From (Used By) Financing Activities		51			(36	)		12
Net Increase (Decrease) In Cash and Cash Equivalents		1			(1	)		(3	)
Cash and Cash Equivalents at Beginning of Year		2			3			6
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	3		$	2		$	3
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for interest (net of capitalized interest of $1 million, $1 million, and less than $1 million, respectively)	$	63		$	61		$	67
Cash (received) paid for income taxes (includes payments to (from) PHI for Federal income taxes)		—			(3	)		(21	)

The accompanying Notes are an integral part of these Consolidated Financial Statements.

320

ACE

ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF EQUITY

					Premium on Stock		Retained Earnings			Total
(millions of dollars, except shares)	Common Stock
	Shares		Par Value
Balance as of December 31, 2012		8,546,017	$	26	$	576	$	200		$	802
Net Income		—		—		—		50			50
Dividends on common stock		—		—		—		(60	)		(60	)
Capital contribution from Parent		—		—		75		—			75
Balance as of December 31, 2013		8,546,017		26		651		190			867
Net Income		—		—		—		45			45
Dividends on common stock		—		—		—		(26	)		(26	)
Balance as of December 31, 2014		8,546,017		26		651		209			886
Net Income		—		—		—		38			38
Dividends on common stock		—		—		—		(12	)		(12	)
Capital contribution from Parent		—		—		95		—			95
Balance as of December 31, 2015		8,546,017	$	26	$	746	$	235		$	1,007

The accompanying Notes are an integral part of these Consolidated Financial Statements.

321

ACE

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ATLANTIC CITY ELECTRIC COMPANY

(1) ORGANIZATION

Atlantic City Electric Company (ACE) is engaged in the transmission and distribution of electricity in southern New Jersey. ACE also provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its service territory who do not elect to purchase electricity from a competitive energy supplier. Default Electricity Supply is known as Basic Generation Service in New Jersey. ACE is a wholly owned subsidiary of Conectiv, LLC (Conectiv), which is wholly owned by Pepco Holdings, Inc. (Pepco Holdings or PHI).

PHI entered into an Agreement and Plan of Merger, dated April 29, 2014, as amended and restated on July 18, 2014 (the Merger Agreement), with Exelon Corporation, a Pennsylvania corporation (Exelon), and Purple Acquisition Corp., a Delaware corporation and an indirect, wholly owned subsidiary of Exelon (Merger Sub), providing for the merger of Merger Sub with and into PHI (the Merger), with PHI surviving the Merger as an indirect, wholly owned subsidiary of Exelon. Pursuant to the Merger Agreement, at the effective time of the Merger, each outstanding share of common stock, par value $0.01 per share, of PHI (other than (i) shares owned by Exelon, Merger Sub or any other direct or indirect wholly owned subsidiary of Exelon and shares owned by PHI or any direct or indirect wholly owned subsidiary of PHI, and in each case not held on behalf of third parties (but not including shares held by PHI in any rabbi trust or similar arrangement in respect of any compensation plan or arrangement) and (ii) shares that are owned by stockholders who have perfected and not withdrawn a demand for appraisal rights pursuant to Delaware law), will be canceled and converted into the right to receive $27.25 in cash, without interest.

In connection with entering into the Merger Agreement, PHI entered into a Subscription Agreement, dated April 29, 2014 (the Subscription Agreement), with Exelon, pursuant to which on April 30, 2014, PHI issued to Exelon 9,000 originally issued shares of non-voting, non-convertible and non-transferable Series A preferred stock, par value $0.01 per share (the Preferred Stock), for a purchase price of $90 million. Exelon also committed pursuant to the Subscription Agreement to purchase 1,800 originally issued shares of Preferred Stock for a purchase price of $18 million at the end of each 90-day period following the date of the Subscription Agreement until the Merger closes or is terminated, up to a maximum of 18,000 shares of Preferred Stock for a maximum aggregate consideration of $180 million. In accordance with the Subscription Agreement, on each of July 29, 2014, October 27, 2014, January 26, 2015, April 27, 2015 and July 24, 2015, an additional 1,800 shares of Preferred Stock were issued by PHI to Exelon for an aggregate purchase price of $90 million. The holders of the Preferred Stock will be entitled to receive a cumulative, non-participating cash dividend of 0.1% per annum, payable quarterly, when, as and if declared by PHI’s board of directors. The proceeds from the issuance of the Preferred Stock are not subject to restrictions and are intended to serve as a prepayment of any applicable reverse termination fee payable from Exelon to PHI. The Preferred Stock will be redeemable on the terms and in the circumstances set forth in the Merger Agreement and the Subscription Agreement.

The Merger Agreement provides for certain termination rights for each of PHI and Exelon, and further provides that, upon termination of the Merger Agreement under certain specified circumstances, PHI will be required to pay Exelon a termination fee of $259 million or reimburse Exelon for its expenses up to $40 million (which reimbursement of expenses shall reduce on a dollar for dollar basis any termination fee subsequently payable by PHI), provided, however, that if the Merger Agreement is terminated in connection with an acquisition proposal made under certain circumstances by a person who made an acquisition proposal between April 1, 2014 and the date of the Merger Agreement, the termination fee will be $293 million plus reimbursement of Exelon for its expenses up to $40 million (not subject to offset). In addition, if the Merger Agreement is terminated under certain circumstances due to the failure to obtain required regulatory approvals with respect to the Merger or the breach by Exelon of its obligations in respect of obtaining such regulatory approvals (a Regulatory Termination), PHI will be able to redeem any issued and outstanding Preferred Stock at par value, and in that case, Exelon will be

322

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required to pay all documented out-of-pocket expenses incurred by PHI in connection with the Merger Agreement or the transactions contemplated thereby, up to $40 million. If the Merger Agreement is terminated, other than for a Regulatory Termination, PHI will be required to redeem the Preferred Stock at the purchase price of $10,000 per share, plus any unpaid accrued and accumulated dividends thereupon.

Consummation of the Merger is subject to the satisfaction or waiver of specified closing conditions, including (i) the approval of the Merger by the holders of a majority of the outstanding shares of common stock of PHI; (ii) the receipt of regulatory approvals required to consummate the Merger, including approvals from the Federal Energy Regulatory Commission (FERC), the Federal Communications Commission (FCC), the Delaware Public Service Commission (DPSC), the District of Columbia Public Service Commission (DCPSC), the Maryland Public Service Commission (MPSC), the New Jersey Board of Public Utilities (NJBPU) and the Virginia State Corporation Commission (VSCC); (iii) the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (the HSR Act); and (iv) other customary closing conditions, including (a) the accuracy of each party’s representations and warranties (subject to customary materiality qualifiers) and (b) each party’s compliance with its obligations and covenants contained in the Merger Agreement (including covenants that may limit, restrict or prohibit PHI and its subsidiaries from taking specified actions during the period between the date of the Merger Agreement and the closing of the Merger or the termination of the Merger Agreement). In addition, the obligations of Exelon and Merger Sub to consummate the Merger are subject to the required regulatory approvals not imposing terms, conditions, obligations or commitments, individually or in the aggregate, that constitute a burdensome condition (as defined in the Merger Agreement). For additional discussion, see Note (6), “Regulatory Matters – Merger Approval Proceedings.”

On September 23, 2014, the stockholders of PHI approved the Merger, on October 7, 2014, the VSCC approved the Merger, and on November 20, 2014, FERC approved the Merger. In addition, the transfer of control of certain communications licenses held by certain of PHI’s subsidiaries has been approved by the FCC. The NJBPU approved the Merger on February 11, 2015 and, on October 15, 2015, voted to extend the effectiveness of its approval until June 30, 2016. The DPSC approved the Merger on May 19, 2015.

The waiting period under the HSR Act expired on December 2, 2015, which allows for the closing of the Merger at any time on or before December 1, 2016.

On May 15, 2015, the MPSC approved the Merger, with conditions, including conditions that modify and supplement those originally proposed. On May 18, 2015, PHI and Exelon announced that they had committed to fulfill the modified, more stringent conditions and package of customer benefits imposed by the MPSC. In connection with these proceedings, the Maryland Office of People’s Counsel and several other parties to the Merger proceedings filed motions in the Circuit Court for Queen Anne’s County, Maryland, requesting a stay of the MPSC order. On August 7, 2015, the Circuit Court for Queen Anne’s County denied the motions for stay. On January 8, 2016, the Circuit Court affirmed the MPSC’s order in all respects. On January 20 and 22, 2016, respectively, the Maryland Office of People’s Counsel and environmental groups filed notices of appeal of the Circuit Court’s order to the Maryland Court of Special Appeals. Unless a motion to stay is filed and then granted by the court, the MPSC order will remain in effect during the appeals process.

On August 27, 2015, the DCPSC issued a written order denying the application seeking approval of the Merger. On September 28, 2015, Exelon, PHI and Potomac Electric Power Company (Pepco), and certain of their respective affiliates, filed an application for reconsideration with the DCPSC requesting reconsideration of the DCPSC order related to the Merger.

On October 6, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, entered into a Nonunanimous Full Settlement Agreement and Stipulation (the DC Settlement Agreement) with the District of Columbia Government, the Office of the People’s Counsel and other parties, which DC Settlement Agreement contains commitments from Exelon and PHI above those contained in their original merger application.

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Also on October 6, 2015, PHI, Exelon and Merger Sub entered into a Letter Agreement (the Letter Agreement), setting forth the terms and conditions under which the parties will file with the DCPSC (a) a Motion of Joint Applicants to Reopen the Record in Formal Case No. 1119 to Allow for Consideration of the DC Settlement Agreement (the Motion to Reopen), or (b) if the Motion to Reopen is not granted, a new merger application, requesting approval of the Merger on the terms and commitments agreed to in the DC Settlement Agreement. Pursuant to the Letter Agreement, PHI and Exelon each agrees, among other things, that neither party will exercise the termination rights each may have under the Merger Agreement on or after October 29, 2015, unless: (i) the DCPSC does not, by November 20, 2015, set a procedural schedule which allows for a final order for approval of the Merger by March 4, 2016, (ii) the DCPSC sets a schedule for action which does not allow for a final order for approval of the Merger by March 4, 2016, (iii) the DCPSC fails to issue a final order approving the Merger and the DC Settlement Agreement as filed without condition or modification by March 4, 2016, (iv) the DCPSC issues a final order denying approval of the Merger or the DC Settlement Agreement or adds conditions or makes modifications to the DC Settlement Agreement, (v) the DC Settlement Agreement is terminated for any reason, or (vi) after March 4, 2016 a condition to closing of the Merger has not been satisfied or waived (other than those conditions that by their nature are to be satisfied at the closing). The Letter Agreement also provides that, subject to certain conditions, Exelon may, following receipt of all regulatory approvals consistent with the DC Settlement Agreement, delay closing of the Merger for up to 30 days to engage in capital markets transactions to raise additional funds required to consummate the Merger.

On October 6, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, filed with the DCPSC the Motion to Reopen requesting consideration of the DC Settlement Agreement and approval of the Merger on such terms and conditions set forth in the DC Settlement Agreement, without condition or modification, and to stay further proceedings on the application for reconsideration filed by the parties on September 28, 2015 and suspend the time period for reconsideration pending the DCPSC’s consideration of the DC Settlement Agreement.

On October 28, 2015, the DCPSC approved the Motion to Reopen and set a procedural schedule for its review of this matter. Upon completion of the public input and evidentiary hearings, the record was closed as of December 23, 2015. Although District of Columbia law does not impose any time limit on the DCPSC’s review of the Merger, the parties requested a decision by March 4, 2016.

(2) SIGNIFICANT ACCOUNTING POLICIES

Consolidation Policy

The accompanying consolidated financial statements include the accounts of ACE and its wholly owned subsidiary Atlantic City Electric Transition Funding, LLC (ACE Funding). All intercompany balances and transactions between subsidiaries have been eliminated. ACE uses the equity method to report investments, corporate joint ventures, partnerships, and affiliated companies where it holds an interest and can exercise significant influence over the operations and policies of the entity. Certain transmission and other facilities currently held are consolidated in proportion to ACE’s percentage interest in the facility.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the consolidated financial statements and accompanying notes. Although ACE believes that its estimates and assumptions are reasonable, they are based upon information available to management at the time the estimates are made. Actual results may differ significantly from these estimates.

Significant matters that involve the use of estimates include the assessment of contingencies, the calculation of future cash flows and fair value amounts for use in asset impairment calculations, fair value calculations for derivative instruments, pension and other postretirement benefits assumptions, the assessment of the adequacy of the allowance for uncollectible accounts, the assessment of the probability

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of recovery of regulatory assets, accrual of storm restoration costs, accrual of unbilled revenue, recognition of changes in network service transmission rates for prior service year costs, accrual of loss contingency liabilities for general litigation and auto and other liability claims, and income tax provisions and reserves. Additionally, ACE is subject to legal, regulatory, and other proceedings and claims that arise in the ordinary course of its business. ACE records an estimated liability for these proceedings and claims when it is probable that a loss has been incurred and the loss is reasonably estimable.

Revenue Recognition

ACE recognizes revenue upon distribution of electricity to its customers, including unbilled revenue for electricity delivered but not yet billed. ACE’s unbilled revenue was $26 million and $32 million as of December 31, 2015 and 2014, respectively, and these amounts are included in Accounts receivable. ACE calculates unbilled revenue using an output-based methodology. This methodology is based on the supply of electricity intended for distribution to customers. The unbilled revenue process requires management to make assumptions and judgments about input factors such as customer sales mix, temperature, and estimated line losses (estimates of electricity expected to be lost in the process of its transmission and distribution to customers). The assumptions and judgments are inherently uncertain and susceptible to change from period to period, and if the actual results differ from the projected results, the impact could be material.

Taxes related to the consumption of electricity by ACE’s customers are a component of ACE’s tariffs and, as such, are billed to customers and recorded in Operating revenue. Accruals for the remittance of these taxes by ACE are recorded in Other taxes.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in ACE’s gross revenues were zero, $1 million and $11 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Long-Lived Asset Impairment Evaluation

ACE evaluates certain long-lived assets to be held and used (for example, equipment and real estate) for impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. Examples of such events or changes include a significant decrease in the market price of a long-lived asset or a significant adverse change in the manner in which an asset is being used or its physical condition. A long-lived asset to be held and used is written down to its estimated fair value if the expected future undiscounted cash flow from the asset is less than its carrying value.

For long-lived assets that can be classified as assets to be disposed of by sale, an impairment loss is recognized to the extent that the asset’s carrying value exceeds its estimated fair value including costs to sell.

Income Taxes

ACE, as an indirect subsidiary of Pepco Holdings, is included in the consolidated federal income tax return of PHI. Federal income taxes are allocated to ACE based upon the taxable income or loss amounts, determined on a separate return basis.

The consolidated financial statements include current and deferred income taxes. Current income taxes represent the amount of tax expected to be reported on ACE’s state income tax returns and the amount of federal income tax allocated from Pepco Holdings.

Deferred income tax assets and liabilities represent the tax effects of temporary differences between the financial statement basis and tax basis of existing assets and liabilities, and they are measured using presently enacted tax rates. The portion of ACE’s deferred tax liability applicable to its utility operations that has not been recovered from utility customers represents income taxes recoverable in the future and is included in Regulatory assets on the consolidated balance sheets. See Note (6), “Regulatory Matters,” for additional information.

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Deferred income tax expense generally represents the net change during the reporting period in the net deferred tax liability and deferred recoverable income taxes.

ACE recognizes interest on underpayments and overpayments of income taxes, interest on uncertain tax positions, and tax-related penalties in income tax expense.

Investment tax credits are being amortized to income over the useful lives of the related property.

Consolidation of Variable Interest Entities

ACE assesses its contractual arrangements with variable interest entities (VIEs) to determine whether it is the primary beneficiary and thereby has to consolidate the entities in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 810. The guidance addresses conditions under which an entity should be consolidated based upon variable interests rather than voting interests. See Note (16), “Variable Interest Entities,” for additional information.

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand, cash invested in money market funds and commercial paper held with original maturities of three months or less. Additionally, deposits in PHI’s money pool, which ACE and certain other PHI subsidiaries use to manage short-term cash management requirements, are considered cash equivalents. Deposits in the money pool are guaranteed by PHI. PHI deposits funds in the money pool to the extent that the pool has insufficient funds to meet the needs of its participants, which may require PHI to borrow funds for deposit from external sources.

Restricted Cash Equivalents

The Restricted cash equivalents included in Current assets and the Restricted cash equivalents included in Other assets consist of (i) cash held as collateral that is restricted from use for general corporate purposes and (ii) cash equivalents that are specifically segregated based on management’s intent to use such cash equivalents for a particular purpose. The classification as current or non-current conforms to the classification of the related liabilities.

Accounts Receivable and Allowance for Uncollectible Accounts

ACE’s Accounts receivable balance primarily consists of customer accounts receivable arising from the sale of goods and services to customers within its service territories, other accounts receivable, and accrued unbilled revenue. Accrued unbilled revenue represents revenue earned in the current period but not billed to the customer until a future date (usually within one month after the receivable is recorded).

ACE maintains an allowance for uncollectible accounts and changes in the allowance are recorded as an adjustment to Other operation and maintenance expense in the consolidated statements of income. ACE determines the amount of the allowance based on specific identification of material amounts at risk by customer and maintains a reserve based on its historical collection experience. The adequacy of this allowance is assessed on a quarterly basis by evaluating all known factors such as the aging of the receivables, historical collection experience, the economic and competitive environment and changes in the creditworthiness of its customers. Accounts receivable are written off in the period in which the receivable is deemed uncollectible and collection efforts have been exhausted. Recoveries of Accounts receivable previously written off are recorded when received. Although ACE believes its allowance is adequate, it cannot anticipate with any certainty the changes in the financial condition of its customers. As a result, ACE records adjustments to the allowance for uncollectible accounts in the period in which the new information that requires an adjustment to the reserve becomes known.

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Inventories

Included in inventories are transmission and distribution materials and supplies. ACE utilizes the weighted average cost method of accounting for inventory items. Under this method, an average price is determined for the quantity of units acquired at each price level and is applied to the ending quantity to calculate the total ending inventory balance. Materials and supplies are recorded in Inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed.

Regulatory Assets and Regulatory Liabilities

Certain aspects of ACE’s business are subject to regulation by the NJBPU. The transmission of electricity by ACE is regulated by FERC.

Based on the regulatory framework in which it has operated, ACE has historically applied, and in connection with its transmission and distribution business continues to apply, FASB guidance on regulated operations (ASC 980). The guidance allows regulated entities, in appropriate circumstances, to defer the income statement impact of certain costs that are expected to be recovered in future rates through the establishment of regulatory assets and defer certain revenues that are expected to be refunded to customers through the establishment of regulatory liabilities. Management’s assessment of the probability of recovery of regulatory assets requires judgment and interpretation of laws, regulatory commission orders and other factors. If management subsequently determines, based on changes in facts or circumstances, that a regulatory asset is not probable of recovery, the regulatory asset would be eliminated through a charge to earnings.

Property, Plant and Equipment

Property, plant and equipment is recorded at original cost, including labor, materials, asset retirement costs and other direct and indirect costs, including capitalized interest. The carrying value of Property, plant and equipment is evaluated for impairment whenever circumstances indicate that the carrying value of those assets may not be recoverable. Upon retirement, the cost of regulated property, net of salvage, is charged to accumulated depreciation.

The annual provision for depreciation on electric property, plant and equipment is computed on a straight-line basis using composite rates by classes of depreciable property. Non-operating and other property is generally depreciated on a straight-line basis over the useful lives of the assets. The system-wide composite annual depreciation rates for the years ended December 31, 2015, 2014 and 2013 for ACE’s property were approximately 2.6%, 2.6% and 2.8%, respectively.

Capitalized Interest and Allowance for Funds Used During Construction

In accordance with FASB guidance on regulated operations (ASC 980), utilities may capitalize the capital costs of financing the construction of plant and equipment as allowance for funds used during construction (AFUDC). This results in the debt portion of AFUDC being recorded as a reduction of Interest expense and the equity portion of AFUDC being recorded as an increase to Other income in the accompanying consolidated statements of income.

ACE recorded AFUDC for borrowed funds of $1 million, $1 million and less than $1 million for the years ended December 31, 2015, 2014 and 2013, respectively.

ACE recorded amounts for the equity component of AFUDC of $1 million, $1 million and less than $1 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Leasing Activities

ACE’s lease transactions include plant, office space, equipment, software, vehicles and elements of power purchase agreements (PPAs). In accordance with FASB guidance on leases (ASC 840), these leases are classified as operating leases.

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Operating Leases

An operating lease in which ACE is the lessee generally results in a level income statement charge over the term of the lease, reflecting the rental payments required by the lease agreement. If rental payments are not made on a straight-line basis, ACE’s policy is to recognize rent expense on a straight-line basis over the lease term unless another systematic and rational allocation basis is more representative of the time pattern in which the leased property is physically employed.

Arrangements Containing a Lease

PPAs are deemed to contain a lease if the arrangement conveys the right to control the use of property, plant or equipment. If so, ACE determines the appropriate lease accounting classification.

Amortization of Debt Issuance and Reacquisition Costs

ACE defers and amortizes debt issuance costs and long-term debt premiums and discounts over the lives of the respective debt issuances. When refinancing or redeeming existing debt, any unamortized premiums, discounts and debt issuance costs, as well as debt redemption costs, are classified as regulatory assets and are amortized generally over the life of the original issue.

Pension and Postretirement Benefit Plans

Pepco Holdings sponsors a non-contributory, defined benefit pension plan that covers substantially all employees of ACE and certain employees of other Pepco Holdings subsidiaries (the PHI Retirement Plan). Pepco Holdings also provides supplemental retirement benefits to certain eligible executives and key employees through nonqualified retirement plans and provides certain postretirement health care and life insurance benefits for eligible retired employees.

The PHI Retirement Plan is accounted for in accordance with FASB guidance on retirement benefits (ASC 715).

Dividend Restrictions

All of ACE’s shares of outstanding common stock are held by Conectiv, its parent company. In addition to its future financial performance, the ability of ACE to pay dividends to its parent company is subject to limits imposed by: (i) state corporate laws, which impose limitations on the funds that can be used to pay dividends and the regulatory requirement that ACE obtain the prior approval of the NJBPU before dividends can be paid if its equity as a percent of its total capitalization, excluding securitization debt, falls below 30%; (ii) the prior rights of holders of future preferred stock, if any, and existing and future mortgage bonds and other long-term debt issued by ACE and any other restrictions imposed in connection with the incurrence of liabilities; and (iii) certain provisions of ACE’s charter that impose restrictions on payment of common stock dividends for the benefit of preferred stockholders. Currently, the restriction in the ACE charter does not limit its ability to pay common stock dividends. ACE had approximately $235 million and $209 million of retained earnings available for payment of common stock dividends at December 31, 2015 and 2014, respectively. These amounts represent the total retained earnings balances at those dates.

Reclassifications

Certain prior period amounts have been reclassified in order to conform to the current period presentation.

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(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Business Combinations (ASC 805)

In November 2014, the FASB issued new recognition and disclosure requirements related to pushdown accounting. The new recognition requirements grant an acquired entity (or its subsidiaries) the option to elect whether and when a new accounting and reporting basis (pushdown accounting) will be applied when an acquirer obtains control of the acquired entity. This election may be made by the acquired entity (or its subsidiaries) for future change-in-control events or for its most recent change-in-control event, and the acquired entity will be required to determine whether pushdown accounting will be applied in the reporting period in which the change-in-control event occurs or in a subsequent reporting period.

The new required disclosures include information that enables financial statement users to evaluate the effects of pushdown accounting. Disclosures are required to be made in the period in which pushdown accounting is applied and are expected to include both qualitative and quantitative information.

The new recognition and disclosure requirements became effective on a prospective basis on November 18, 2014.

Presentation of Debt Issuance Costs (ASC 835)

In April 2015, the FASB issued new guidance for the presentation of debt issuance costs on the balance sheet. Debt issuance costs are currently required to be presented on the balance sheet as assets. However, under the new requirements, these debt issuance costs will be offset against the debt to which the costs relate. The new requirements are effective for ACE beginning January 1, 2016, and are required to be implemented on a retrospective basis for all periods presented; however, early adoption is permitted. ACE has elected to early adopt the new guidance in the fourth quarter of 2015. The table below illustrates the effects of the retrospective application on reported balances in ACE’s consolidated balance sheet as of December 31, 2014.

	December 31, 2014 As Filed		Reclassification ASC 835			December 31, 2014 As Adjusted
	(millions of dollars)
Other (within other assets)	$	12	$	(7	)	$	5
Long-term debt		888		(6	)		882
Transition bonds issued by ACE Funding		171		(1	)		170

Balance Sheet Classification of Deferred Taxes (ASC 740)

In November 2015, the FASB issued new requirements for the balance sheet classification of deferred taxes. Entities are currently required to present a current and noncurrent deferred tax balance on the balance sheet. Under the new requirements, deferred taxes will only be presented as noncurrent. The new requirements are effective for PHI beginning January 1, 2017, and may be implemented on either a prospective or retrospective basis; however, early adoption is permitted. PHI has elected to early adopt the new guidance on a retrospective basis in the fourth quarter of 2015. The table below illustrates the effects of the retrospective application on reported balances in ACE’s consolidated balance sheet as of December 31, 2014.

	December 31, 2014 As Filed		Reclassification ASC 740			December 31, 2014 As Adjusted
	(millions of dollars)
Prepaid expenses and other	$	13	$	(10	)	$	3
Deferred income tax liabilities, net		865		(10	)		855

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(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Revenue from Contracts with Customers (ASC 606)

In May 2014, the FASB issued new recognition and disclosure requirements for revenue from contracts with customers, which supersedes the existing revenue recognition guidance. The new recognition requirements focus on when the customer obtains control of the goods or services, rather than the current risks and rewards model of recognition. The core principle of the new standard is that an entity will recognize revenue when it transfers goods or services to its customers in an amount that reflects the consideration an entity expects to be entitled to for those goods or services. The new disclosure requirements will include information intended to communicate the nature, amount, timing and any uncertainty of revenue and cash flows from applicable contracts, including any significant judgments and changes in judgments and assets recognized from the costs to obtain or fulfill a contract. Entities will generally be required to make more estimates and use more judgment under the new standard.

The new requirements will be effective for ACE beginning January 1, 2018, and may be implemented either retrospectively for all periods presented, or as a cumulative-effect adjustment as of January 1, 2018. Early adoption is permitted, but not before January 1, 2017. ACE is currently evaluating the potential impact of this new guidance on its consolidated financial statements and which implementation approach to select.

Business Combination (ASC 805)

In September 2015, the FASB issued new guidance on adjustments to provisional amounts recognized in a business combination, which are currently recognized on a retrospective basis. Under the new requirements, adjustments will be recognized in the reporting period in which the adjustments are determined. The effects of changes in depreciation, amortization, or other income arising from changes to the provisional amounts, if any, are included in earnings of the reporting period in which the adjustments to the provisional amounts are determined. An entity is also required to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The new requirements will be effective for ACE beginning January 1, 2016, and are required to be implemented on a prospective basis. Early adoption is permitted. ACE currently anticipates it may be affected by the new guidance if its Merger with Exelon is consummated.

(5) SEGMENT INFORMATION

ACE operates its business as one regulated utility segment, which includes all of its services as described above.

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(6) REGULATORY MATTERS

Regulatory Assets and Regulatory Liabilities

The components of ACE’s regulatory asset and liability balances at December 31, 2015 and 2014 are as follows:

	2015		2014
	(millions of dollars)
Regulatory Assets
Securitized stranded costs	$	202	$	278
Recoverable income taxes		44		42
Deferred energy supply costs		27		58
Incremental storm restoration costs		18		15
Deferred debt extinguishment costs		7		8
Other		24		26
Total Regulatory Assets	$	322	$	427
Regulatory Liabilities
Federal and state tax benefits, related to securitized stranded costs	$	13	$	8
Reserves for FERC ROE transmission challenges		8		1
Deferred income taxes due to customers		3		3
Other		3		2
Total Regulatory Liabilities	$	27	$	14

A description for each category of regulatory assets and regulatory liabilities follows:

Securitized Stranded Costs: Certain contract termination payments under a contract between ACE and an unaffiliated non-utility generator (NUG) and costs associated with the regulated operations of ACE’s electricity generation business are no longer recoverable through customer rates (collectively referred to as “stranded costs”). The stranded costs are amortized over the life of Transition Bonds issued by ACE Funding to securitize the recoverability of these stranded costs (the Transition Bonds). These Transition Bonds mature between 2016 and 2023. A customer surcharge is collected by ACE to fund principal and interest payments on the Transition Bonds. ACE earns a return on these regulatory assets.

Recoverable Income Taxes: Represents amounts recoverable from ACE’s customers for tax benefits applicable to utility operations previously recognized in income tax expense before the company was ordered to record the tax benefits as deferred income taxes. As the temporary differences between the financial statement basis and tax basis of assets reverse, the deferred recoverable balances are reversed.

Deferred Energy Supply Costs: The regulatory asset represents primarily deferred costs associated with a net under-recovery of energy supply costs incurred by ACE that are being or are expected to be recovered from customers. ACE earns a return on these regulatory assets.

Incremental Storm Restoration Costs: Represents total incremental storm restoration costs incurred for repair work due to major storm events in 2015, 2012 and 2011, including the June 2015 storm, Hurricane Sandy, the June 2012 derecho, and Hurricane Irene, that are recoverable from customers. ACE’s costs related to Hurricane Sandy, the June 2012 derecho and Hurricane Irene are being amortized and recovered from customers, each over a three-year period. ACE does not earn a return on these regulatory assets.

Deferred Debt Extinguishment Costs: Represents deferred costs of debt extinguishment that are amortized to interest expense and recovered from customers. ACE generally earns a return on these regulatory assets.

Other: Represents miscellaneous regulatory assets that generally are being amortized over 1 to 20 years.

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Federal and State Tax Benefits, Related to Securitized Stranded Costs: Securitized stranded costs include a portion attributable to the future tax benefit expected to be realized when the higher tax basis of the generating facilities divested by ACE is deducted for New Jersey state income tax purposes, as well as the future benefit to be realized through the reversal of federal excess deferred taxes. To account for the possibility that these tax benefits may be given to ACE’s customers through lower rates in the future, ACE established a regulatory liability. The regulatory liability related to federal excess deferred taxes will remain until such time as the Internal Revenue Service (IRS) issues its final regulations with respect to normalization of these federal excess deferred taxes.

Reserves for FERC ROE Transmission Challenges: Represents reserves established under a settlement agreement filed with FERC for the resolution of certain challenges filed by a group of complainants of the base return on equity (ROE) currently authorized by FERC for the transmission service that ACE provides.

Deferred Income Taxes Due to Customers: Represents the portions of deferred income tax assets applicable to utility operations of ACE that have not been reflected in current customer rates for which future payment to customers is probable. As the temporary differences between the financial statement basis and tax basis of assets reverse, deferred recoverable income taxes are amortized.

Other: Represents miscellaneous regulatory liabilities.

Rate Proceedings

As further described in Note (1), “Organization,” on April 29, 2014, PHI entered into the Merger Agreement with Exelon and Merger Sub. Subject to certain exceptions, prior to the Merger or the termination of the Merger Agreement, PHI and its subsidiaries may not, without the consent of Exelon, initiate, file or pursue any rate cases, other than pursuing the conclusion of certain proceedings, as described below. To date, ACE has not requested such consent from Exelon and has not filed any new distribution base rate cases since entering into the Merger Agreement.

Bill Stabilization Adjustment

Although ACE proposed the adoption of a mechanism to decouple retail distribution revenue from the amount of power delivered to retail customers, this decoupling proposal has not to date been adopted.

New Jersey

Update and Reconciliation of Certain Under-Recovered Balances

In March 2015, ACE submitted its 2015 annual petition with the NJBPU seeking to reconcile and update (i) charges related to the recovery of above-market costs associated with ACE’s long-term power purchase contracts with the NUGs, and (ii) costs related to surcharges for the New Jersey Societal Benefit Program (a statewide public interest program that is intended to benefit low income customers and address other public policy goals) and for ACE’s uncollected accounts. As filed, the net impact of the proposed changes would have been an annual rate increase of approximately $52.0 million (revised to an increase of approximately $33.9 million on April 17, 2015, based upon updates for actual data through March 31, 2015). On May 19, 2015, the NJBPU approved a stipulation of settlement entered into by the parties providing for a provisional overall annual rate increase of $33.9 million effective June 1, 2015. On September 11, 2015, the NJBPU approved a stipulation of settlement in this proceeding, which made final the provisional rates that were placed into effect as of June 1, 2015, with an adjustment that decreased the rate applicable to the residential class by $1.3 million. This rate increase of approximately $32.6 million will have no effect on ACE’s operating income, since these revenues provide for recovery of deferred costs under an approved deferral mechanism.

On February 1, 2016, ACE submitted its 2016 annual petition with the NJBPU seeking to reconcile and update the same categories of charges and costs described in (i) and (ii) in the above paragraph. The net impact of adjusting the charges as proposed is an overall annual rate increase of approximately $8.8 million, including New Jersey Sales and Use Tax. The matter is pending at the NJBPU and will be updated for January through March 2016 actual data. ACE has requested that the NJBPU place the new rates into effect by June 1, 2016.

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Service Extension Contributions Refund Order

In July 2013, in compliance with a 2012 Superior Court of New Jersey Appellate Division (Appellate Division) court decision, the NJBPU released an order requiring utilities to issue refunds to persons or entities that paid non-refundable contributions for utility service extensions to certain areas described as “Areas Not Designated for Growth.” The order is limited to eligible contributions paid between March 20, 2005 and December 20, 2009. ACE is processing the refund requests that meet the eligibility criteria established in the order as they are received. Although ACE estimates that it received approximately $11 million of contributions between March 20, 2005 and December 20, 2009, it is currently unable to reasonably estimate the amount that it may be required to refund using the eligibility criteria established by the order. Since the July 2013 order was released, ACE has paid less than $1 million in refund claims, the validity of each of which is investigated by ACE prior to making any such refunds. In September 2014, the NJBPU commenced a rulemaking proceeding to further implement the directives of the Appellate Division decision. In November 2015, the NJBPU adopted new regulations that remove provisions distinguishing between growth areas and not-for-growth areas and provide formulae for allocating extension costs. At this time, ACE does not expect the amount it is ultimately required to refund will have a material effect on its consolidated financial condition, results of operations or cash flows, as the amount refunded will generally increase the value of ACE’s property, plant and equipment and may ultimately be recovered through depreciation expense and cost of service in future electric distribution base rate cases.

Generic Consolidated Tax Adjustment Proceeding

In January 2013, the NJBPU initiated a generic proceeding to examine whether a consolidated tax adjustment (CTA) should continue to be used, and if so, how it should be calculated in determining a utility’s cost of service. Under the NJBPU’s current policy, when a New Jersey utility is included in a consolidated group income tax return, an allocated amount of any reduction in the consolidated group’s taxes as a result of losses by affiliates is used to reduce the utility’s rate base, upon which the utility earns a return. This policy has negatively impacted ACE’s electric distribution base rate case outcomes and ACE’s position is that the CTA should be eliminated. In an order issued in October 2014, the NJBPU determined that it is appropriate for affected consolidated groups to continue to include a CTA in New Jersey base rate filings, but that the CTA calculation will be modified to limit the look-back period for the calculation to five years, exclude transmission assets from the calculation, and allocate 25 percent of the final CTA amount as a reduction to the distribution revenue requirement. ACE anticipates that this revised methodology will significantly reduce the negative effects of the CTA in future base rate cases. In November 2014, the New Jersey Division of Rate Counsel filed an appeal of the NJBPU’s CTA order in the Appellate Division. No stay of the October 2014 CTA order was requested in connection with the appeal. As such, barring an adverse finding by the Appellate Division, the order is in effect. The appeal remains pending.

FERC Transmission ROE Challenges

In February 2013, the public service commissions and public advocates of the District of Columbia, Maryland, Delaware and New Jersey, as well as the Delaware Municipal Electric Corporation, Inc., filed a joint complaint at FERC against ACE and its affiliates, Pepco and Delmarva Power & Light Company (DPL), as well as Baltimore Gas and Electric Company (BGE). The complainants challenged the base ROE and certain protocols regarding the formula rate process associated with the transmission service that the utilities provide. The complainants support an ROE within a zone of reasonableness of 6.78% and 10.33%, and have argued for a base ROE of 8.7%. The base ROE currently authorized by FERC for PHI’s utilities is (i) 11.3% for facilities placed into service after January 1, 2006, and (ii) 10.8% for facilities placed into service prior to 2006. The 10.8% base ROE for facilities placed into service prior to 2006 receives a 50-basis-point incentive adder for being a member of a regional transmission organization. In August 2014, FERC issued an order setting the matters in this proceeding for hearing, but holding the hearing in abeyance pending settlement discussions. The order also (i) directed that the

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evidence and analysis presented concerning ROE be guided by the new ROE methodology adopted by FERC in another proceeding (discussed below), and (ii) set a 15-month refund period that commenced on February 27, 2013, should a refund result from this proceeding. After settlement discussions among the parties in this matter reached an impasse, the settlement judge, in November 2014, issued an order terminating the settlement discussions and referring the matter to a presiding administrative law judge.

In June 2014, FERC issued an order in a proceeding in which ACE was not involved, in which it adopted a new ROE methodology for electric utilities. This new methodology replaces the existing one-step discounted cash flow analysis (which incorporates only short-term growth rates) traditionally used to derive ROE for electric utilities with the two-step discounted cash flow analysis (which incorporates both short-term and long-term measures of growth) used for natural gas and oil pipelines. As a result of the August 2014 FERC order discussed in the preceding paragraph, ACE applied an estimated ROE based on the two-step methodology announced by FERC for the 15-month period over which its transmission revenues would be subject to refund as a result of the challenge, and recorded estimated reserves for the entire 15-month refund period in the second quarter of 2014.

On December 8, 2014, the parties that filed the February 2013 complaint filed a second complaint against Pepco, DPL, ACE, as well as BGE, regarding the base transmission ROE, seeking a reduction from 10.8% to 8.8%. By order issued on February 9, 2015, FERC established a hearing on the second complaint and established a second 15-month refund period that commenced on December 8, 2014. Consistent with the prior challenge, ACE applied an estimated ROE based on the two-step methodology described above, and in the fourth quarter of 2014 and in the first, second and third quarters of 2015 established reserves for the estimated refund based on the effective date of the second refund period of December 8, 2014. On February 20, 2015, the chief judge issued an order consolidating the two complaint proceedings and established an initial decision issuance deadline of February 29, 2016. On March 2, 2015, the presiding administrative law judge issued an order establishing a procedural schedule for the consolidated proceedings that provided for the hearing to commence on October 20, 2015.

Also during the third quarter of 2015, ACE further evaluated the reserves established for each of the two refund periods and, based on an updated assessment of market conditions, developments in other cases before FERC, litigation risk and other factors, increased its reserves to reflect management’s best estimate of the refund that is expected to result from these consolidated proceedings. A settlement entered into by the parties regarding the protocols (but not the ROE) raised in the February 2013 complaint was submitted to FERC on July 31, 2015 and was approved by FERC in November 2015.

On November 6, 2015, the parties filed a settlement agreement with FERC regarding the ROE. This settlement agreement provides for (i) a base ROE of 10.0%, effective March 8, 2016, to which a 50-basis-point incentive adder will be applied for being a member of a regional transmission organization, and (ii) customer refunds in the amount of approximately $9.5 million for ACE covering the two 15-month refund periods described above. In addition, under this settlement agreement, no party may file to change the base ROE or any incentives prior to June 1, 2018. The parties have requested that FERC approve this settlement agreement by March 16, 2016, in order to incorporate the new ROE and applicable refunds into each utility’s 2016 transmission formula rate update. As of December 31, 2015, ACE’s reserves for both of the refund periods totaled $8 million as required under the settlement agreement.

ACE Standard Offer Capacity Agreements

In April 2011, ACE entered into three Standard Offer Capacity Agreements (SOCAs) by order of the NJBPU, each with a different generation company. ACE entered into the SOCAs under protest, as did the other electric distribution companies (EDCs) in New Jersey, arguing that the EDCs were denied due process and that the SOCAs violated certain of the requirements of the New Jersey law under which the SOCAs were established (the NJ SOCA Law). In October 2013, in light of the decision of the U.S. District Court for the District of New Jersey described below, the state appeals of the NJBPU implementation orders filed by the EDCs and generators were dismissed without prejudice, subject to the parties exercising their appellate rights in the Federal courts.

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In February 2011, ACE joined other plaintiffs in an action filed in the U.S. District Court for the District of New Jersey challenging the NJ SOCA Law on the grounds that it violates the Commerce Clause and the Supremacy Clause of the U.S. Constitution. In October 2013, the Federal district court ruled that the NJ SOCA Law is preempted by the Federal Power Act (FPA) and violates the Supremacy Clause, and is therefore null and void. In October 2013, the Federal district court issued an order ruling that the SOCAs are void, invalid and unenforceable, which order was affirmed by the U.S. Court of Appeals for the Third Circuit in September 2014. In November 2014 and December 2014, respectively, one of the generation companies and the NJBPU petitioned the U.S. Supreme Court to consider hearing an appeal of the Third Circuit decision. The U.S. Supreme Court has not yet agreed to review the Third Circuit decision and the petitions for such review remain pending.

ACE terminated one of the three SOCAs effective July 1, 2013 due to the occurrence of an event of default on the part of the generation company counterparty. ACE terminated the remaining two SOCAs effective November 19, 2013, in response to the October 2013 Federal district court decision.

In response to the October 2013 Federal district court order, ACE, in the fourth quarter of 2013, derecognized both the derivative assets (liabilities) for the estimated fair value of the SOCAs and the related regulatory liabilities (assets) that it had established with respect to the SOCAs.

Merger Approval Proceedings

New Jersey

On June 18, 2014, Exelon, PHI and ACE, and certain of their respective affiliates, filed a petition with the NJBPU seeking approval of the Merger. To approve the Merger, the NJBPU must find the Merger is in the public interest, and consider the impact of the Merger on (i) competition, (ii) rates of ratepayers affected by the Merger, (iii) ACE’s employees, and (iv) the provision of safe and reliable service at just and reasonable rates. On January 14, 2015, PHI, ACE, Exelon, certain of Exelon’s affiliates, the Staff of the NJBPU, and the Independent Energy Producers of New Jersey filed a stipulation of settlement (the Stipulation) with the NJBPU in this proceeding. On February 11, 2015, the NJBPU approved the Stipulation and the Merger and on March 6, 2015, the NJBPU issued a written order approving the Stipulation.

The NJBPU order states that the Merger must be closed by November 1, 2015 unless extended by the NJBPU. On October 15, 2015, the NJBPU voted to extend the effectiveness of its Merger approval until June 30, 2016.

Federal Energy Regulatory Commission

On May 30, 2014, Exelon, PHI, Pepco, DPL and ACE, and certain of their respective affiliates, submitted to FERC a Joint Application for Authorization of Disposition of Jurisdictional Assets and Merger under Section 203 of the FPA. Under that section, FERC shall approve a merger if it finds that the proposed transaction will be consistent with the public interest. On November 20, 2014, FERC issued an order approving the Merger.

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(7) PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment is comprised of the following:

	Original Cost		Accumulated Depreciation		Net Book Value
	(millions of dollars)
At December 31, 2015
Distribution	$	2,012	$	472	$	1,540
Transmission		968		228		740
Construction work in progress		158		—		158
Non-operating and other property		167		64		103
Total	$	3,305	$	764	$	2,541
At December 31, 2014
Generation	$	10	$	9	$	1
Distribution		1,931		450		1,481
Transmission		839		223		616
Construction work in progress		115		—		115
Non-operating and other property		178		78		100
Total	$	3,073	$	760	$	2,313

The non-operating and other property amounts include balances for general plant, plant held for future use, intangible plant and non-utility property. Utility plant is generally subject to a first mortgage lien.

Jointly Owned Plant

ACE’s consolidated balance sheets include its proportionate share of assets and liabilities related to jointly owned plant. At each of December 31, 2015 and 2014, ACE’s subsidiaries had a net book value ownership interest of $11 million in transmission and other facilities in which various parties also have ownership interests. ACE’s share of the operating and maintenance expenses of the jointly owned plant is included in the corresponding expenses in the consolidated statements of income. ACE is responsible for providing its share of the financing for the above jointly owned facilities.

(8) PENSION AND OTHER POSTRETIREMENT BENEFITS

ACE accounts for its participation in PHI’s single-employer plans, the PHI Retirement Plan and its other postretirement benefits plan, the Pepco Holdings, Inc. Welfare Plan for Retirees (the OPEB Plan), as participation in multiemployer plans. For 2015, 2014 and 2013, ACE was responsible for $15 million, $13 million and $17 million, respectively, of the pension and other postretirement net periodic benefit cost incurred by PHI. ACE made discretionary tax-deductible contributions of zero, zero and $30 million to the PHI Retirement Plan for the years ended December 31, 2015, 2014 and 2013, respectively. In addition, ACE made contributions of $3 million, $3 million and $6 million to the OPEB Plan for the years ended December 31, 2015, 2014 and 2013, respectively. At December 31, 2015 and 2014, ACE’s Prepaid pension expense of $83 million and $96 million, and Other postretirement benefit obligations of $33 million and $36 million, respectively, effectively represent assets and benefit obligations resulting from ACE’s participation in these PHI benefit plans.

Other Postretirement Benefit Plan Amendments

During 2013, PHI approved two amendments to its other postretirement benefits plan. These amendments impacted the retiree medical plan and the retiree life insurance benefits, and became effective on January 1, 2014. As a result of the amendments, which were cumulatively significant, PHI remeasured its projected benefit obligation for other postretirement benefits as of July 1, 2013. The remeasurement resulted in a $3 million reduction in ACE’s net periodic benefit cost for other postretirement benefits in 2014, when compared to 2013. Approximately 45% of net periodic other postretirement benefit costs were capitalized in 2014.

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(9) DEBT

Long-Term Debt

The components of long-term debt are shown in the table below:

Type of Debt	Interest Rate			Maturity	2015			2014
					(millions of dollars)
First Mortgage Bonds
		7.68	% (a)	2015-2016	$	2		$	17
		7.75	%	2018		250			250
		6.80	% (b)(c)	2021		39			39
		4.35	%	2021		200			200
		3.375	%	2024		150			150
		3.50	%	2025		150			—
		4.875	%(c)(d)	2029		23			23
		5.80	% (b)(e)	2034		120			120
		5.80	% (b)(e)	2036		105			105
Total long-term debt						1,039			904
Net unamortized discount						(1	)		(1	)
Unamortized debt issuance costs						(6	)		(6	)
Current portion of long-term debt						(2	)		(15	)
Total net long-term debt					$	1,030		$	882

(a) Represents a series of Collateral First Mortgage Bonds (as defined herein) securing a series of medium-term notes issued by ACE.

(b) Represents a series of Collateral First Mortgage Bonds which must be cancelled and released as security for ACE’s obligations under the corresponding series of issuer notes (as defined herein) or tax-exempt bonds, at such time as ACE does not have any first mortgage bonds outstanding (other than its Collateral First Mortgage Bonds).

(c) Represents a series of Collateral First Mortgage Bonds securing a series of tax-exempt bonds issued for the benefit of ACE.

(d) Represents a series of Collateral First Mortgage Bonds which must be cancelled and released as security for ACE’s obligations under the corresponding series of issuer notes or tax-exempt bonds, at such time as ACE does not have any first mortgage bonds outstanding (other than its Collateral First Mortgage Bonds), except that ACE may not permit such release of collateral unless ACE substitutes comparable obligations for such collateral.

(e) Represents a series of Collateral First Mortgage Bonds securing a series of senior notes issued by ACE.

The outstanding first mortgage bonds issued by ACE are issued under a mortgage and deed of trust and are secured by a first lien on substantially all of ACE’s property, plant and equipment, except for certain property excluded from the lien of the mortgage.

Maturities of ACE’s long-term debt outstanding at December 31, 2015 are $2 million in 2016, zero in 2017, $250 million in 2018, zero in 2019 and 2020, and $787 million thereafter.

ACE’s long-term debt is subject to certain covenants. As of December 31, 2015, ACE was in compliance with all such covenants.

The table above does not separately identify $227 million in aggregate principal amount of senior notes and medium term notes (issuer notes) issued by ACE and $62 million in aggregate principal amount of tax-exempt bonds issued for the benefit of ACE. These issuer notes and tax-exempt bonds are secured by a like amount of first mortgage bonds (Collateral First Mortgage Bonds) of ACE. The principal terms of each such series of issuer notes, or ACE’s obligations in respect of each such series of tax-exempt bonds, are identical to the same terms of the corresponding series of Collateral First Mortgage Bonds. Payments of principal and interest made on a series of such issuer notes, or the satisfaction of ACE obligations in respect of a series of such tax-exempt bonds, satisfy the corresponding obligations on the related series of Collateral First Mortgage Bonds. For these reasons, each such series of Collateral First Mortgage Bonds and the corresponding issuer notes or tax-exempt bonds together effectively represent a single financial obligation and are not identified in the table above separately.

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Bond Issuance

During 2015, ACE issued $150 million of 3.50% first mortgage bonds due December 1, 2025 in a private placement. The net proceeds from the issuance of the bonds were used by ACE to repay outstanding commercial paper and for general corporate purposes.

Bond Retirement

During 2015, ACE retired, at maturity, $15 million of its secured medium-term notes series C. The medium-term notes were secured by a like principal amount of its 7.68% first mortgage bonds due August 24, 2015, which under the mortgage and deed of trust were deemed to be satisfied when the medium-term notes were repaid.

Transition Bonds Issued by ACE Funding

The components of transition bonds are shown in the table below:

Type of Debt	Interest Rate			Maturity	2015			2014
					(millions of dollars)
Transition Bonds
		4.91	%	2017	$	—		$	17
		5.05	%	2020		39			51
		5.55	%	2023		132			147
						171			215
Unamortized debt issuance costs						(1	)		(1	)
Current portion of long-term debt						(46	)		(44	)
Total net long-term Transition Bonds					$	124		$	170

For a description of the Transition Bonds, see Note (16), “Variable Interest Entities – ACE Funding.” Maturities of ACE’s Transition Bonds outstanding at December 31, 2015 are $46 million in 2016, $35 million in 2017, $31 million in 2018, $18 million in 2019, $20 million in 2020 and $21 million thereafter.

Short-Term Debt

ACE has traditionally used a number of sources to fulfill short-term funding needs, such as commercial paper, short-term notes, and bank lines of credit. Proceeds from short-term borrowings are used primarily to meet working capital needs, but may also be used to temporarily fund long-term capital requirements. The components of ACE’s short-term debt at December 31, 2015 and 2014 are as follows:

	2015		2014
	(millions of dollars)
Commercial paper	$	5	$	127

Commercial Paper

ACE maintains an ongoing commercial paper program to address its short-term liquidity needs. As of December 31, 2015, the maximum capacity available under the program was $350 million, subject to available borrowing capacity under the credit facility.

ACE had $5 million and $127 million of commercial paper outstanding at December 31, 2015 and 2014, respectively. The weighted average interest rates for commercial paper issued by ACE during 2015 and 2014 were 0.46% and 0.27%, respectively. The weighted average maturity of all commercial paper issued by ACE during 2015 and 2014 was six days and five days, respectively.

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Variable Rate Demand Bonds

During 2014, ACE retired, at maturity, its last remaining Variable Rate Demand Bonds (VRDBs) in the amount of $18 million. The weighted average interest rate for VRDBs was 0.05% during 2014.

Credit Facility

PHI, Pepco, DPL and ACE maintain an unsecured syndicated credit facility to provide for their respective liquidity needs, including obtaining letters of credit, borrowing for general corporate purposes and supporting their commercial paper programs. On August 1, 2013, as permitted under the existing terms of the credit agreement, a request by PHI, Pepco, DPL and ACE to extend the credit facility termination date to August 1, 2018 was approved. All of the terms and conditions as well as pricing remained the same.

The aggregate borrowing limit under the amended and restated credit facility is $1.5 billion, all or any portion of which may be used to obtain loans and up to $500 million of which may be used to obtain letters of credit. The facility also includes a swingline loan sub-facility, pursuant to which each company may make same day borrowings in an aggregate amount not to exceed 10% of the total amount of the facility. Any swingline loan must be repaid by the borrower within fourteen days of receipt. The credit sublimit is $750 million for PHI and $250 million for each of Pepco, DPL and ACE. The sublimits may be increased or decreased by the individual borrower during the term of the facility, except that (i) the sum of all of the borrower sublimits following any such increase or decrease must equal the total amount of the facility, and (ii) the aggregate amount of credit used at any given time by (a) PHI may not exceed $1.25 billion, and (b) each of Pepco, DPL or ACE may not exceed the lesser of $500 million or the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the sublimit reallocations may not exceed eight per year during the term of the facility.

The interest rate payable by each company on utilized funds is, at the borrowing company’s election, (i) the greater of the prevailing prime rate, the federal funds effective rate plus 0.5% and the one month London Interbank Offered Rate plus 1.0%, or (ii) the prevailing Eurodollar rate, plus a margin that varies according to the credit rating of the borrower.

In order for a borrower to use the facility, certain representations and warranties must be true and correct, and the borrower must be in compliance with specified financial and other covenants, including (i) the requirement that each borrowing company maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the credit agreement, which calculation excludes from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) with certain exceptions, a restriction on sales or other dispositions of assets, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than permitted liens. The credit agreement contains certain covenants and other customary agreements and requirements that, if not complied with, could result in an event of default and the acceleration of repayment obligations of one or more of the borrowers thereunder. Each of the borrowers was in compliance with all covenants under this facility at December 31, 2015.

The absence of a material adverse change in PHI’s business, property, results of operations or financial condition is not a condition to the availability of credit under the credit agreement. The credit agreement does not include any rating triggers.

As of December 31, 2015 and 2014, the amount of cash plus borrowing capacity under the credit facility available to meet the liquidity needs of PHI’s utility subsidiaries in the aggregate was $576 million and $413 million, respectively. ACE’s borrowing capacity under the credit facility at any given time depends on the amount of the subsidiary borrowing capacity being utilized by Pepco and DPL and the portion of the total capacity being used by PHI.

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Credit Facility Amendment

During 2014, PHI, Pepco, DPL and ACE entered into an amendment of and consent with respect to the credit agreement (the Consent). PHI was required to obtain the consent of certain of the lenders under the credit facility in order to permit the consummation of the Merger. Pursuant to the Consent, certain of the lenders consented to the consummation of the Merger and the subsequent conversion of PHI from a Delaware corporation to a Delaware limited liability company, provided that the Merger and subsequent conversion are consummated on or before October 29, 2015. In addition, the Consent amends the definition of “Change in Control” in the credit agreement to mean, following consummation of the Merger, an event or series of events by which Exelon no longer owns, directly or indirectly, 100% of the outstanding shares of voting stock of Pepco Holdings. PHI requested and obtained an extension of the Consent to allow for completion of the Merger by June 30, 2016.

Term Loan Agreement

On May 10, 2013, ACE entered into a $100 million term loan agreement, pursuant to which ACE borrowed $100 million at a rate of interest equal to the prevailing Eurodollar rate, which was determined by reference to the London Interbank Offered Rate (LIBOR) with respect to the relevant interest period, all as defined in the loan agreement, plus a margin of 0.75%. On August 21, 2014, ACE repaid the term loan in full.

(10) INCOME TAXES

ACE, as an indirect subsidiary of PHI, is included in the consolidated federal income tax return of PHI. Federal income taxes are allocated to ACE pursuant to a written tax sharing agreement that was approved by the Securities and Exchange Commission in connection with the establishment of PHI as a holding company. Under this tax sharing agreement, PHI’s consolidated federal income tax liability is allocated based upon PHI’s and its subsidiaries’ separate taxable income or loss.

The provision for consolidated income taxes, reconciliation of consolidated income tax expense, and components of consolidated deferred income tax liabilities (assets) are shown below.

Provision for Consolidated Income Taxes

	For the Year Ended December 31,
	2015			2014			2013
	(millions of dollars)
Current Tax (Benefit) Expense
Federal	$	(2	)	$	(7	)	$	(23	)
State and local		3			(2	)		(10	)
Total Current Tax Benefit		1			(9	)		(33	)
Deferred Tax Expense (Benefit)
Federal		25			30			28
State and local		5			7			25
Investment tax credit amortization		—			—			(1	)
Total Deferred Tax Expense		30			37			52
Total Consolidated Income Tax Expense	$	31		$	28		$	19

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Reconciliation of Consolidated Income Tax Expense

	For the Year Ended December 31,
	2015					2014					2013
	(millions of dollars)
Income tax at Federal statutory rate	$	24		35.0	%	$	26		35.0	%	$	24		35.0	%
Increases (decreases) resulting from:
State income taxes, net of federal effect		4		5.8	%		4		5.5	%		5		7.2	%
Change in estimates and interest related to uncertain and effectively settled tax positions		3		4.3	%		(1	)	(1.4	)%		(9	)	(13.0	)%
Deferred tax basis adjustments		2		2.9	%		—		—			(2	)	(2.9	)%
Investment tax credit amortization		—		—			—		—			(1	)	(1.4	)%
Other, net		(2	)	(3.1	)%		(1	)	(0.7	)%		2		2.6	%
Consolidated Income Tax Expense	$	31		44.9	%	$	28		38.4	%	$	19		27.5	%

Global Tax Settlement

On November 18, 2015, PHI entered into a settlement with the IRS and the Department of Justice (DOJ) (the Global Tax Settlement) to provide for the resolution of the tax treatment of its previously held cross-border energy lease investments involving public utility assets located outside of the United States structured as sale-in, lease-out, or SILO, transactions. The Global Tax Settlement followed the acceptance by PHI on October 29, 2015 of IRS revenue agent reports covering adjustments incorporated in the terms of the Global Tax Settlement, as well as adjustments for all other tax matters in dispute with the IRS. The Global Tax Settlement and the revenue agent reports, together, effectively close all years open to examination of federal income tax liabilities for PHI and ACE through 2011, and all matters associated with the cross-border energy lease investments through 2013.

As a result of the Global Tax Settlement, ACE recorded in the fourth quarter of 2015 tax expense of $3 million which is included above in Change in estimates and interest related to uncertain and effectively settled tax positions. The tax charge recorded of $3 million primarily represents uncertain tax positions that were settled in favor of the IRS in the Global Tax Settlement. Included in the tax expense of $3 million was after-tax interest expense of less than $1 million associated with ACE’s uncertain tax positions. The interest expense represented ACE’s allocated share of an overall net interest benefit for PHI’s consolidated group of $21 million resulting from the Global Tax Settlement assuming ACE was a separate taxpayer.

Also during the fourth quarter of 2015, ACE completed its annual reconciliation of its deferred income tax accounts and corrected prior period errors by recording an after-tax charge of $2 million which is included above in Deferred tax basis adjustments. Management has determined that these errors, individually or in the aggregate, were not material to the current or prior periods.

Other Tax Matter

On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States (to which ACE is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. As a result of the court’s ruling in this case, PHI determined in the first quarter of 2013 that it could no longer support its current assessment with respect to the likely outcome of tax positions associated with its cross-border energy lease investments held by its wholly owned subsidiary Potomac Capital Investment Corporation, and PHI recorded an after-tax charge of $377 million in the first quarter of 2013. Included in the $377 million charge was an after-tax interest charge of $54 million and this amount was allocated to each member of PHI’s consolidated group as if each member was a separate taxpayer, resulting in ACE recording a $6 million (after-tax) interest benefit in the first quarter of 2013, which is included above in Change in estimates and interest related to uncertain and effectively settled tax positions.

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Components of Consolidated Deferred Income Tax Liabilities (Assets)

	As of December 31,
	2015			2014
	(millions of dollars)
Deferred Tax Liabilities (Assets)
Depreciation and other basis differences related to plant and equipment	$	773		$	691
Deferred taxes on amounts to be collected through future rates		17			16
Payment for termination of purchased power contracts with NUGs		34			38
Deferred electric service and electric restructuring liabilities		47			71
Pension and other postretirement benefits		20			25
Federal and state net operating losses		(9	)		(26	)
Other		6			40
Total Consolidated Deferred Tax Liabilities, net	$	888		$	855

The net deferred tax liability represents the tax effect, at presently enacted tax rates, of temporary differences between the financial statement basis and tax basis of assets and liabilities. The portion of the net deferred tax liability applicable to ACE’s operations, which has not been reflected in current service rates, represents income taxes recoverable through future rates, net, and is recorded as a regulatory asset on the balance sheet. No valuation allowance for deferred tax assets was required or recorded at December 31, 2015 and 2014. Federal and State net operating losses generally expire over 20 years from 2029 to 2032.

The Tax Reform Act of 1986 repealed the investment tax credit for property placed in service after December 31, 1985, except for certain transition property. Investment tax credits previously earned on ACE’s property continue to be amortized to income over the useful lives of the related property.

Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits

	2015			2014			2013
	(millions of dollars)
Balance as of January 1	$	13		$	9		$	17
Tax positions related to current year:
Additions		—			1			2
Reductions		—			—			—
Tax positions related to prior years:
Additions		—			5			1
Reductions		(10	)(a)		(2	)		(5	)
Settlements		(3	)(a)		—			(6	)
Balance as of December 31	$	—		$	13		$	9

(a) Reductions and settlements in 2015 resulted from the Global Tax Settlement. Settlements represent unrecognized tax benefits that were satisfied with cash or use of net operating losses and tax credits.

Unrecognized Benefits That, If Recognized, Would Affect the Effective Tax Rate

Unrecognized tax benefits are related to tax positions that have been taken or are expected to be taken in tax returns that are not recognized in the financial statements because management has either measured the tax benefit at an amount less than the benefit claimed, or expected to be claimed, or has concluded that it is not more likely than not that the tax position will be ultimately sustained. For the majority of these tax positions, the ultimate deductibility is highly certain, but there is uncertainty about the timing of such deductibility. At December 31, 2015, ACE had no unrecognized tax benefits that, if recognized, would lower the effective tax rate.

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Interest and Penalties

ACE recognizes interest and penalties relating to its uncertain tax positions as an element of income tax expense. For the years ended December 31, 2015, 2014 and 2013, ACE recognized less than $1 million of pre-tax interest income (less than $1 million after-tax), $1 million of pre-tax interest income (less than $1 million after-tax), and $12 million of pre-tax interest income ($7 million after-tax), respectively, as a component of income tax expense. As of December 31, 2015, 2014 and 2013, ACE had accrued interest receivable of zero, $14 million and $14 million, respectively, related to effectively settled and uncertain tax positions.

Possible Changes to Unrecognized Tax Benefits

It is reasonably possible that the amount of the unrecognized tax benefit with respect to some of ACE’s uncertain tax positions will significantly increase or decrease within the next 12 months. At this time, it is estimated that there will no decrease in unrecognized tax benefits within the next 12 months.

Tax Years Open to Examination

ACE, as an indirect subsidiary of PHI, is included on PHI’s consolidated Federal tax return. As a result of the Global Tax Settlement described above, ACE’s federal income tax liabilities for all years through 2011 have been determined, subject to adjustment to the extent of any net operating loss or other loss or credit carrybacks from subsequent years. The open tax years for the significant states where ACE files state income tax returns (New Jersey and Pennsylvania) are the same as for the Federal returns.

Final IRS Regulations on Repair of Tangible Property

In August 2011, the IRS issued Revenue Procedure 2011-43 providing a safe harbor method of tax accounting for repair costs associated with electric transmission and distribution property. In September 2012, with the filing of its 2011 tax return, PHI adopted the safe harbor for the 2011 tax year. In September 2013, the IRS published final regulations regarding the tax treatment of costs incurred to acquire, produce or improve tangible property. In February 2014, the IRS issued revenue procedures that describe how taxpayers should implement the final regulations. The final repair regulations and the related revenue procedures did not modify the guidance set forth in Revenue Procedure 2011-43 that the Unit of Property for electric transmission and distribution network assets is determined by the taxpayer’s particular facts and circumstances. The final regulations did not have a material impact on ACE’s consolidated financial statements.

Other Taxes

Taxes other than income taxes for each year are shown below. These amounts are recoverable through rates.

	2015		2014			2013
	(millions of dollars)
Gross Receipts/Delivery	$	—	$	—		$	10
Property		4		3			3
Environmental, Use and Other		1		(1	)		1
Total	$	5	$	2		$	14

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(11) DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

ACE was ordered to enter into the SOCAs by the NJBPU, and under the SOCAs, ACE would have received payments from or made payments to electric generation facilities based on (i) the difference between the fixed price in the SOCAs and the price for capacity that clears PJM Interconnection, LLC (PJM) and (ii) ACE’s annual proportion of the total New Jersey load relative to the other EDCs in New Jersey. ACE began applying derivative accounting to two of its SOCAs as of June 30, 2012 because these generators cleared the 2015-2016 PJM capacity auction in May 2012. The fair value of the derivatives embedded in the SOCAs were deferred as Regulatory assets or Regulatory liabilities because the NJBPU allowed full recovery from ACE’s distribution customers for any payments made by ACE, and ACE’s distribution customers would be entitled to any payments received by ACE.

As further discussed in Note (6), “Regulatory Matters,” in light of a Federal district court order, which ruled that the SOCAs are void, invalid and unenforceable, and ACE’s subsequent termination of the SOCAs in the fourth quarter of 2013, ACE derecognized the derivative assets and derivative liabilities related to the SOCAs.

(12) FAIR VALUE DISCLOSURES

Financial Instruments Measured at Fair Value on a Recurring Basis

ACE applies FASB guidance on fair value measurement (ASC 820) that established a framework for measuring fair value and expanded disclosures about fair value measurements. As defined in the guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). ACE utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. Accordingly, ACE utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1) and the lowest priority to unobservable inputs (level 3).

The following tables set forth by level within the fair value hierarchy ACE’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2015 and 2014. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. ACE’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Fair Value Measurements at December 31, 2015
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1) (a)		Significant Other Observable Inputs (Level 2) (a)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Cash equivalents and restricted cash equivalents
Treasury funds	$	30	$	30	$	—	$	—

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2015.

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	Fair Value Measurements at December 31, 2014
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1) (a)		Significant Other Observable Inputs (Level 2) (a)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Cash equivalents and restricted cash equivalents
Treasury funds	$	24	$	24	$	—	$	—

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2014.

ACE classifies its fair value balances in the fair value hierarchy based on the observability of the inputs used in the fair value calculation as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 – Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using broker quotes in liquid markets and other observable data. Level 2 also includes those financial instruments that are valued using methodologies that have been corroborated by observable market data through correlation or by other means. Significant assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

Level 3 – Pricing inputs that are significant and generally less observable than those from objective sources. Level 3 includes those financial instruments that are valued using models or other valuation methodologies.

Other Financial Instruments

The estimated fair values of ACE’s Long-term debt instruments that are measured at amortized cost in ACE’s consolidated financial statements and the associated levels of the estimates within the fair value hierarchy as of December 31, 2015 and 2014 are shown in the tables below. As required by the fair value measurement guidance, debt instruments are classified in their entirety within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. ACE’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, which may affect the valuation of fair value debt instruments and their placement within the fair value hierarchy levels.

The fair values of Long-term debt and Transition bonds categorized as level 2 are based on a blend of quoted prices for the debt and quoted prices for similar debt on the measurement date. The blend places more weight on current pricing information when determining the final fair value measurement. The fair value information is provided by brokers, and ACE reviews the methodologies and results.

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The fair value of Long-term debt categorized as level 3 is based on a discounted cash flow methodology using observable inputs, such as the U.S. Treasury yield, and unobservable inputs, such as credit spreads, because quoted prices for the debt or similar debt in active markets were insufficient.

	Fair Value Measurements at December 31, 2015
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	1,140	$	—	$	860	$	280
Transition Bonds (b)		185		—		185		—
Total	$	1,325	$	—	$	1,045	$	280

(a) The carrying amount for Long-term debt, net of unamortized discount, was $1,038 million as of December 31, 2015.

(b) The carrying amount for Transition Bonds, including amounts due within one year, was $171 million as of December 31, 2015.

	Fair Value Measurements at December 31, 2014
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	1,035	$	—	$	903	$	132
Transition Bonds (b)		235		—		235		—
Total	$	1,270	$	—	$	1,138	$	132

(a) The carrying amount for Long-term debt, net of unamortized discount, was $903 million as of December 31, 2014.

(b) The carrying amount for Transition Bonds, including amounts due within one year, was $215 million as of December 31, 2014.

The carrying amounts of all other financial instruments in the accompanying consolidated financial statements approximate fair value.

(13) COMMITMENTS AND CONTINGENCIES

General Litigation

From time to time, ACE is named as a defendant in litigation, usually relating to general liability or auto liability claims that resulted in personal injury or property damage to third parties. ACE is self-insured against such claims up to a certain self-insured retention amount and maintains insurance coverage against such claims at higher levels, to the extent deemed prudent by management. In addition, ACE’s contracts with its vendors generally require the vendors to name ACE as an additional insured for the amount at least equal to ACE’s self-insured retention. Further, ACE’s contracts with its vendors require the vendors to indemnify ACE for various acts and activities that may give rise to claims against ACE. Loss contingency liabilities for both asserted and unasserted claims are recognized if it is probable that a loss will result from such a claim and if the amounts of the losses can be reasonably estimated. Although the outcome of the claims and proceedings cannot be predicted with any certainty, management believes that there are no existing claims or proceedings that are likely to have a material adverse effect on ACE’s financial condition, results of operations or cash flows. At December 31, 2015, ACE had recorded estimated loss contingency liabilities for general litigation totaling approximately $5 million.

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ACE

Environmental Matters

ACE is subject to regulation by various federal, regional, state and local authorities with respect to the environmental effects of its operations, including air and water quality control, solid and hazardous waste disposal and limitations on land use. Although penalties assessed for violations of environmental laws and regulations are not recoverable from customers of ACE, environmental clean-up costs incurred by ACE generally are included in its cost of service for ratemaking purposes. The total accrued liabilities for the environmental contingencies of ACE described below at December 31, 2015 are summarized as follows:

	Legacy Generation - Regulated
	(millions of dollars)
Balance as of January 1	$	1
Accruals		—
Payments		—
Balance as of December 31		1
Less amounts in Other Current Liabilities		—
Amounts in Other Deferred Credits	$	1

Franklin Slag Pile Site

In November 2008, ACE received a general notice letter from the U.S. Environmental Protection Agency (EPA) concerning the Franklin Slag Pile site in Philadelphia, Pennsylvania, asserting that ACE is a potentially responsible party that may have liability for clean-up costs with respect to the site and for the costs of implementing an EPA-mandated remedy. EPA’s claims are based on ACE’s sale of boiler slag from the B.L. England generating facility, then owned by ACE, to MDC Industries, Inc. (MDC) during the period from June 1978 to May 1983. EPA claims that the boiler slag ACE sold to MDC contained copper and lead, which are hazardous substances under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA), and that the sales transactions may have constituted an arrangement for the disposal or treatment of hazardous substances at the site, which could be a basis for liability under CERCLA. The EPA letter also states that, as of the date of the letter, EPA’s expenditures for response measures at the site have exceeded $6 million. EPA’s feasibility study (FS) for this site conducted in 2007 identified a range of alternatives for permanent remedial measures with varying cost estimates, and the estimated cost of EPA’s preferred alternative is approximately $6 million.

ACE believes that the B.L. England boiler slag sold to MDC was a valuable material with various industrial applications and, therefore, the sale was not an arrangement for the disposal or treatment of any hazardous substances as would be necessary to constitute a basis for liability under CERCLA. ACE intends to contest any claims to the contrary made by EPA. In a May 2009 decision arising under CERCLA, which did not involve ACE, the U.S. Supreme Court rejected an EPA argument that the sale of a useful product constituted an arrangement for disposal or treatment of hazardous substances. While this decision supports ACE’s position, at this time ACE cannot predict how EPA will proceed with respect to the Franklin Slag Pile site, or what portion, if any, of the Franklin Slag Pile site response costs EPA would seek to recover from ACE. Costs to resolve this matter are not expected to be material and are expensed as incurred.

Contractual Obligations

Power Purchase Contracts

As of December 31, 2015, ACE’s contractual obligations under non-derivative power purchase contracts were $203 million in 2016, $341 million in 2017 to 2018, $344 million in 2019 to 2020 and $697 million thereafter.

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ACE

Lease Commitments

ACE leases certain types of property and equipment for use in its operations. Rental expense for operating leases was $13 million, $12 million and $12 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Total future minimum operating lease payments for ACE as of December 31, 2015 are $8 million in 2016, $8 million 2017, $7 million in 2018, $6 million in 2019, $6 million in 2020 and $30 million thereafter.

(14) RELATED PARTY TRANSACTIONS

PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries, including ACE. The cost of these services is allocated in accordance with cost allocation methodologies set forth in the service agreement using a variety of factors, including the subsidiaries’ share of employees, operating expenses, assets and other cost methods. These intercompany transactions are eliminated by PHI in consolidation and no profit results from these transactions at PHI. PHI Service Company costs directly charged or allocated to ACE for the years ended December 31, 2015, 2014 and 2013 were $143 million, $124 million and $115 million, respectively.

In addition to the PHI Service Company charges described above, ACE’s consolidated financial statements include the following related party transactions in its consolidated statements of income:

	For the Year Ended December 31,
	2015			2014			2013
	(millions of dollars)
Meter reading services provided by Millennium Account Services LLC (an ACE affiliate) (a)	$	(4	)	$	(4	)	$	(4	)
Intercompany lease transactions (a)		(1	)		(1	)		(1	)
Intercompany use revenue (b)		1			2			3

(a) Included in Other operation and maintenance expense.

(b) Included in Operating revenue.

As of December 31, 2015 and 2014, ACE had the following balances on its consolidated balance sheets due to related parties:

	2015			2014
	(millions of dollars)
Payable to Related Party (current) (a)
PHI Service Company	$	(15	)	$	(14	)
Other		(1	)		(1	)
Total	$	(16	)	$	(15	)

(a) Included in Accounts payable due to associated companies.

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ACE

(15) QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

The quarterly data presented below reflect all adjustments necessary, in the opinion of management, for a fair presentation of the interim results. Quarterly data normally vary seasonally because of temperature variations and differences between summer and winter rates. Therefore, comparisons by quarter within a year are not meaningful.

	2015
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(millions of dollars)
Total Operating Revenue	$	333		$	286		$	387		$	292		$	1,298
Total Operating Expenses		313			254			349			252			1,168
Operating Income		20			32			38			40			130
Other Expenses		(14	)		(15	)		(17	)		(15	)		(61	)
Income Before Income Tax Expense		6			17			21			25			69
Income Tax Expense		2			7			7			15	(a)		31
Net Income	$	4		$	10		$	14		$	10		$	38

(a) Includes income tax charge of $3 million associated with the Global Tax Settlement and a tax charge of $2 million to correct prior period errors.

	2014
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(millions of dollars)
Total Operating Revenue (a)	$	340		$	253		$	347		$	273		$	1,213
Total Operating Expenses		309			228			295			246	(b)		1,078
Operating Income		31			25			52			27			135
Other Expenses		(15	)		(15	)		(15	)		(17	)		(62	)
Income Before Income Tax Expense		16			10			37			10			73
Income Tax Expense		6			4			14			4			28
Net Income	$	10		$	6		$	23		$	6		$	45

(a) During the fourth quarter of 2014, ACE reversed unbilled revenue of $3 million ($2 million after-tax) to correct an error that had overstated operating revenue in the third quarter of 2014.

(b) Includes a charge of $3 million ($2 million after-tax) to correct a prior period error related to the recoverability of certain regulatory assets.

(16) VARIABLE INTEREST ENTITIES

ACE is required to consolidate a VIE in accordance with FASB ASC 810 if ACE or a subsidiary is the primary beneficiary of the VIE. The primary beneficiary of a VIE is typically the entity with both the power to direct activities most significantly impacting economic performance of the VIE and the obligation to absorb losses or receive benefits of the VIE that could potentially be significant to the VIE. ACE performed a qualitative analysis to determine whether a variable interest provided a controlling financial interest in any of the VIE’s in which ACE has an interest at December 31, 2015, as described below.

Power Purchase Agreements

ACE is a party to three PPAs with unaffiliated NUGs totaling 459 megawatts. One of the agreements ends in 2016 and the other two end in 2024. ACE has no equity or debt invested in these entities. In performing its VIE analysis, ACE has been unable to obtain sufficient information to determine whether these three entities were variable interest entities or if ACE was the primary beneficiary. As a result, ACE has applied the scope exemption from the consolidation guidance.

Because ACE has no equity or debt invested in the NUGs, the maximum exposure to loss relates primarily to any above-market costs incurred for power. Due to unpredictability in the pricing for purchased energy under the PPAs, ACE is unable to quantify the maximum exposure to loss. The power purchase costs are recoverable from ACE’s customers through regulated rates. Purchase activities with

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ACE

the NUGs, including excess power purchases not covered by the PPAs, for the years ended December 31, 2015, 2014 and 2013, were approximately $208 million, $233 million and $221 million, respectively, of which approximately $198 million, $208 million and $206 million, respectively, consisted of power purchases under the PPAs.

ACE Funding

In 2001, ACE established ACE Funding solely for the purpose of securitizing authorized portions of ACE’s recoverable stranded costs through the issuance and sale of Transition Bonds. The proceeds of the sale of each series of Transition Bonds were transferred to ACE in exchange for the transfer by ACE to ACE Funding of the right to collect a non-bypassable Transition Bond Charge (which is revenue ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds and related taxes, expenses and fees) from ACE customers pursuant to bondable stranded costs rate orders issued by the NJBPU in an amount sufficient to fund the principal and interest payments on the Transition Bonds and related taxes, expenses and fees (Bondable Transition Property). The assets of ACE Funding, including the Bondable Transition Property, and the Transition Bond Charges collected from ACE’s customers, are not available to creditors of ACE. The holders of Transition Bonds have recourse only to the assets of ACE Funding. ACE owns 100 percent of the equity of ACE Funding, and PHI and ACE consolidate ACE Funding in their consolidated financial statements as ACE is the primary beneficiary of ACE Funding under the variable interest entity consolidation guidance.

350

Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

Pepco Holdings, Inc.

None.

Potomac Electric Power Company

None.

Delmarva Power & Light Company

None.

Atlantic City Electric Company

None.

351

Item 9A. CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Each Reporting Company maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed in such Reporting Company’s reports under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and that such information is accumulated and communicated to management of such Reporting Company, including such Reporting Company’s Chief Executive Officer (CEO) and Chief Financial Officer (CFO), as appropriate, to allow timely decisions regarding required disclosure. This control system, no matter how well designed and operated, can provide only reasonable assurance that the objectives of the control system are met. Such Reporting Company’s disclosure controls and procedures were designed to provide reasonable assurance of achieving their stated objectives. Under the supervision, and with the participation of management, including the CEO and the CFO, each Reporting Company has evaluated the effectiveness of the design and operation of its disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2015, and, based upon this evaluation, the CEO and the CFO of such Reporting Company have concluded that these disclosure controls and procedures are effective to provide reasonable assurance that material information relating to such Reporting Company and its subsidiaries that is required to be disclosed in reports filed with, or submitted to, the SEC under the Exchange Act (i) is recorded, processed, summarized and reported within the time periods specified by the SEC rules and forms and (ii) is accumulated and communicated to management, including its CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.

Management’s Annual Report on Internal Control Over Financial Reporting

See “Management’s Report on Internal Control Over Financial Reporting” with respect to each Reporting Company.

Attestation Report of the Registered Public Accounting Firm

The “Report of Independent Registered Public Accounting Firm” with respect to the attestation report of PHI’s registered public accounting firm is hereby incorporated by reference in response to this Item 9A.

The Dodd-Frank Wall Street Reform and Consumer Protection Act enacted on July 21, 2010, exempts any company that is not a “large accelerated filer” or an “accelerated filer” (as defined by SEC rules) from the requirement that such company obtain an external audit of the effectiveness of its internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act. As a result, each of Pepco, DPL and ACE is exempt from the requirement that it include in its Annual Report on Form 10-K an attestation report on internal control over financial reporting by an independent registered public accounting firm; however, management’s annual report on internal control over financial reporting, pursuant to Section 404(a) of the Sarbanes-Oxley Act, is still required with respect to each of them.

Reports of Changes in Internal Control Over Financial Reporting

Under the supervision and with the participation of management, including the CEO and CFO of each Reporting Company, each such Reporting Company has evaluated changes in internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the three months ended December 31, 2015, and has concluded there was no change in such Reporting Company’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, such Reporting Company’s internal control over financial reporting.

352

Item 9B. OTHER INFORMATION

Pepco Holdings, Inc.

None.

Potomac Electric Power Company

None.

Delmarva Power & Light Company

None.

Atlantic City Electric Company

None.

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Part III

Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Pepco Holdings, Inc.

Other than the section entitled “Executive Officers of PHI” contained in Part I, Item 1. “Business,” of this Form 10-K, information required by this Item 10 will be (i) incorporated by reference to Pepco Holdings’ definitive proxy statement with respect to its 2016 Annual Meeting of Stockholders or (ii) provided in an amendment to this Form 10-K, to be filed with the SEC on or before April 29, 2016.

INFORMATION FOR THIS ITEM IS NOT REQUIRED FOR PEPCO, DPL AND ACE AS THEY MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS I(1)(a) AND (b) OF FORM 10-K AND THEREFORE ARE FILING THIS FORM WITH THE REDUCED FILING FORMAT.

Item 11. EXECUTIVE COMPENSATION

Pepco Holdings, Inc.

Other than as set forth below and on Exhibit 10.51 hereto, information required by this Item 11 will be (i) incorporated by reference to Pepco Holdings’ definitive proxy statement with respect to its 2016 Annual Meeting of Stockholders or (ii) provided in an amendment to this Form 10-K, to be filed with the SEC on or before April 29, 2016.

INFORMATION FOR THIS ITEM IS NOT REQUIRED FOR PEPCO, DPL AND ACE AS THEY MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS I(1)(a) AND (b) OF FORM 10-K AND THEREFORE ARE FILING THIS FORM WITH THE REDUCED FILING FORMAT.

Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Pepco Holdings, Inc.

Information required by this Item 12 will be (i) incorporated by reference to Pepco Holdings’ definitive proxy statement with respect to its 2016 Annual Meeting of Stockholders or (ii) provided in an amendment to this Form 10-K, to be filed with the SEC on or before April 29, 2016.

INFORMATION FOR THIS ITEM IS NOT REQUIRED FOR PEPCO, DPL AND ACE AS THEY MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS I(1)(a) AND (b) OF FORM 10-K AND THEREFORE ARE FILING THIS FORM WITH THE REDUCED FILING FORMAT.

Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Pepco Holdings, Inc.

Information required by this Item 13 will be (i) incorporated by reference to Pepco Holdings’ definitive proxy statement with respect to its 2016 Annual Meeting of Stockholders or (ii) provided in an amendment to this Form 10-K, to be filed with the SEC on or before April 29, 2016.

INFORMATION FOR THIS ITEM IS NOT REQUIRED FOR PEPCO, DPL AND ACE AS THEY MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS I(1)(a) AND (b) OF FORM 10-K AND THEREFORE ARE FILING THIS FORM WITH THE REDUCED FILING FORMAT.

354

Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Pepco Holdings, Pepco, DPL and ACE

Audit Fees

The aggregate fees billed by PricewaterhouseCoopers LLP for professional services rendered for the audit of the annual financial statements of Pepco Holdings and its subsidiary reporting companies for the 2015 and 2014 fiscal years, reviews of the financial statements included in the 2015 and 2014 Forms 10-Q of Pepco Holdings and its subsidiary reporting companies, reviews of other public filings, comfort letters and other attest services were $5,469,639 and $6,113,779, respectively. The amount for the 2014 fiscal year includes $301,108 for the 2014 audit that was billed after the 2014 amount was disclosed in Pepco Holdings’ 2014 Annual Report on Form 10-K.

Audit-Related Fees

The aggregate fees billed by PricewaterhouseCoopers LLP for audit-related services rendered for the 2015 and 2014 fiscal years were $735,670 and $667,907, respectively. The amount for the 2014 fiscal year includes $12,945 of audit-related fees that were billed after the 2014 amount was disclosed in Pepco Holdings’ 2014 Annual Report on Form 10-K. These fees generally consisted of amounts billed in connection with advice and recommendations related to financial and accounting systems implementations and for attest services performed in connection with public service commission rate case filings. In addition, the amounts for the 2015 and 2014 fiscal years included $382,764 and $343,771, respectively, for merger-related due diligence and audit services.

Tax Fees

The aggregate fees billed by PricewaterhouseCoopers LLP for tax services rendered for the 2015 and 2014 fiscal years were $709,193 and $759,767, respectively. These services generally consisted of tax compliance, tax advice and tax planning. In addition, the amounts for the 2015 and 2014 fiscal years included $72,306 and $363,048 in fees for assistance with issues related to the evaluation of potential settlement scenarios with respect to the former cross-border energy lease investments.

All Other Fees

The aggregate fees billed by PricewaterhouseCoopers LLP for services other than those covered under “Audit Fees,” “Audit-Related Fees” and “Tax Fees” were $7,200 for each of the 2015 and 2014 fiscal years, respectively. These fees for 2015 and 2014 represented the costs of an online accounting and financial reporting research tool.

All of the services described in “Audit Fees,” “Audit-Related Fees,” “Tax Fees” and “All Other Fees” were approved in advance by the Audit Committee, in accordance with the Audit Committee Policy on the Approval of Services Provided By the Independent Auditor, which has been filed as Exhibit 99 to this Form 10-K.

355

Part IV

Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) Documents List

1. Financial Statements

Pepco Holdings, Inc.

Consolidated Statements of Income (Loss) for each of the years ended December 31, 2015, 2014 and 2013

Consolidated Statements of Comprehensive Income (Loss) for each of the years ended December 31, 2015, 2014 and 2013

Consolidated Balance Sheets as of December 31, 2015 and 2014

Consolidated Statements of Cash Flows for each of the years ended December 31, 2015, 2014 and 2013

Consolidated Statements of Equity for each of the years ended December 31, 2015, 2014 and 2013

Notes to Consolidated Financial Statements

Potomac Electric Power Company

Statements of Income for each of the years ended December 31, 2015, 2014 and 2013

Balance Sheets as of December 31, 2015 and 2014

Statements of Cash Flows for each of the years ended December 31, 2015, 2014 and 2013

Statements of Equity for each of the years ended December 31, 2015, 2014 and 2013

Notes to Financial Statements

Delmarva Power & Light Company

Statements of Income for each of the years ended December 31, 2015, 2014 and 2013

Balance Sheets as of December 31, 2015 and 2014

Statements of Cash Flows for each of the years ended December 31, 2015, 2014 and 2013

Statements of Equity for each of the years ended December 31, 2015, 2014 and 2013

Notes to Financial Statements

Atlantic City Electric Company

Consolidated Statements of Income for each of the years ended December 31, 2015, 2014 and 2013

Consolidated Balance Sheets as of December 31, 2015 and 2014

Consolidated Statements of Cash Flows for each of the years ended December 31, 2015, 2014 and 2013

Consolidated Statements of Equity for each of the years ended December 31, 2015, 2014 and 2013

Notes to Consolidated Financial Statements

356

2. Financial Statement Schedules

The financial statement schedules specified by Regulation S-X, other than those listed below, are omitted because either they are not applicable or the required information is presented in the financial statements included in Part II, Item 8. “Financial Statements and Supplementary Data” of this Form 10-K.

	Registrants
Item	Pepco Holdings		Pepco		DPL		ACE
Schedule I, Condensed Financial Information of Parent Company		358		N/A		N/A		N/A
Schedule II, Valuation and Qualifying Accounts		364		364		365		365

357

Schedule I, Condensed Financial Information of Parent Company is submitted below.

PEPCO HOLDINGS, INC. (Parent Company)

STATEMENTS OF INCOME (LOSS)

	For the Year Ended December 31,
	2015			2014			2013
	(millions of dollars, except share data)
Operating Revenue	$	—		$	—		$	—
Operating Expenses
Other operation and maintenance		20			31			1
Total operating expenses		20			31			1
Operating Loss		(20	)		(31	)		(1	)
Other Income (Expenses)
Interest expense		(47	)		(43	)		(42	)
Income from equity investments		312			291			204
Other income		15			—			—
Total other income		280			248			162
Income from Continuing Operations Before Income Tax		260			217			161
Income Tax (Benefit) Expense Related to Continuing Operations		(58	)		(25	)		51
Net Income from Continuing Operations		318			242			110
Income (Loss) from Discontinued Operations, net of Income Taxes		9			—			(322	)
Net Income (Loss)	$	327		$	242		$	(212	)
Comprehensive Income (Loss)	$	337		$	230		$	(198	)
Earnings Per Share
Basic earnings per share of common stock from Continuing Operations	$	1.25		$	0.96		$	0.45
Basic earnings (loss) per share of common stock from Discontinued Operations		0.04			—			(1.31	)
Basic earnings (loss) per share of common stock	$	1.29		$	0.96		$	(0.86	)
Diluted earnings per share of common stock from Continuing Operations	$	1.25		$	0.96		$	0.45
Diluted earnings (loss) per share of common stock from Discontinued Operations		0.04			—			(1.31	)
Diluted earnings (loss) per share of common stock	$	1.29		$	0.96		$	(0.86	)

The accompanying Notes are an integral part of these Financial Statements.

358

PEPCO HOLDINGS, INC. (Parent Company)

BALANCE SHEETS

	As of December 31,
	2015			2014
	(millions of dollars, except share data)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	—		$	65
Prepayments of income taxes		171			152
Accounts receivable and other		18			9
Total Current Assets		189			226
INVESTMENTS AND OTHER ASSETS
Goodwill		1,398			1,398
Investment in consolidated companies		4,636			4,256
Other		127			82
Total Investments and Other Assets		6,161			5,736
TOTAL ASSETS	$	6,350		$	5,962
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Short-term debt	$	784		$	287
Current portion of long-term debt		190			250
Interest and taxes accrued		10			9
Accounts payable due to associated companies		8			13
Total Current Liabilities		992			559
DEFERRED CREDITS
Notes payable due to subsidiary companies		498			494
Liabilities and accrued interest related to uncertain tax positions		—			4
Total Deferred Credits		498			498
LONG-TERM DEBT		264			454
COMMITMENTS AND CONTINGENCIES (NOTE 4)
PREFERRED STOCK
Series A preferred stock, $.01 par value – 18,000 shares authorized, 18,000 and 12,600 shares outstanding, respectively		183			129
EQUITY
Common stock, $.01 par value – 400,000,000 shares authorized, 254,289,261 and 252,728,684 shares outstanding, respectively		3			3
Premium on stock and other capital contributions		3,829			3,800
Accumulated other comprehensive loss		(36	)		(46	)
Retained earnings		617			565
Total Equity		4,413			4,322
TOTAL LIABILITIES AND EQUITY	$	6,350		$	5,962

The accompanying Notes are an integral part of these Financial Statements.

359

PEPCO HOLDINGS, INC. (Parent Company)

STATEMENTS OF CASH FLOWS

	For the Year Ended December 31,
	2015			2014			2013
	(millions of dollars)
OPERATING ACTIVITIES
Net income (loss)	$	327		$	242		$	(212	)
(Income) loss from discontinued operations, net of income taxes		(9	)		—			322
Adjustments to reconcile net income to net cash from operating activities:
Distributions from related parties less than earnings		(74	)		(149	)		(127	)
Deferred income taxes		(33	)		(5	)		(7	)
Increase in fair value of preferred stock derivative		(15	)		—			—
Other		13			18			—
Changes in:
Prepaid and other		6			13			2
Accounts payable		(1	)		1			6
Interest and taxes		(23	)		—			(141	)
Other assets and liabilities		(22	)		1			3
Net Cash From (Used By) Operating Activities		169			121			(154	)
FINANCING ACTIVITIES
Dividends paid on common stock		(275	)		(272	)		(270	)
Common stock issued for the Direct Stock Purchase and Dividend Reinvestment Plan and employee-related compensation		18			34			50
Issuances of common stock		—			—			324
Issuances of Series A preferred stock		54			126			—
Capital contributions to subsidiaries, net		(282	)		(210	)		(250	)
Increase in notes payable due to associated companies		4			3			491
Reacquisitions of long-term debt		(250	)		—			—
Issuances (repayments) of short-term debt, net		197			263			(240	)
Borrowings under term loans		300			—			250
Repayments of term loans		—			—			(450	)
Costs of issuances		—			—			(13	)
Net Cash Used By Financing Activities		(234	)		(56	)		(108	)
Net (Decrease) Increase In Cash and Cash Equivalents		(65	)		65			(262	)
Cash and Cash Equivalents at Beginning of Year		65			—			262
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	—		$	65		$	—

The accompanying Notes are an integral part of these Financial Statements.

360

NOTES TO FINANCIAL INFORMATION

(1) BASIS OF PRESENTATION

Pepco Holdings, Inc. (Pepco Holdings or PHI) is a holding company and conducts substantially all of its business operations through its subsidiaries. These condensed financial statements and related footnotes have been prepared in accordance with Rule 12-04, Schedule I of Regulation S-X. These statements should be read in conjunction with the consolidated financial statements and notes thereto of Pepco Holdings included in Part II, Item 8 of this Form 10-K.

Pepco Holdings owns 100% of the common stock of all its significant subsidiaries.

(2) NEWLY ADOPTED ACCOUNTING STANDARDS

Presentation of Debt Issuance Costs (Accounting Standards Codification (ASC) 835)

In April 2015, the Financial Accounting Standards Board issued new guidance for the presentation of debt issuance costs on the balance sheet. Debt issuance costs are currently required to be presented on the balance sheet as assets. However, under the new requirements, these debt issuance costs will be offset against the debt to which the costs relate. The new requirements are effective for PHI beginning January 1, 2016, and are required to be implemented on a retrospective basis for all periods presented; however, early adoption is permitted. PHI has elected to early adopt the new guidance in the fourth quarter of 2015. The table below illustrates the effects of the retrospective application on reported balances in PHI’s balance sheet as of December 31, 2014.

	December 31, 2014 As Filed		Reclassification ASC 835			December 31, 2014 As Adjusted
	(millions of dollars)
Other (within investments and other assets)	$	84	$	(2	)	$	82
Long-term debt		456		(2	)		454

(3) DEBT

For information concerning Pepco Holdings’ long-term debt obligations, see Note (10), “Debt,” to the consolidated financial statements of Pepco Holdings.

(4) COMMITMENTS AND CONTINGENCIES

For information concerning Pepco Holdings’ material contingencies and guarantees, see Note (16), “Commitments and Contingencies” to the consolidated financial statements of Pepco Holdings.

Pepco Holdings guarantees the obligations of its wholly owned subsidiary, Pepco Energy Services, Inc. and its subsidiaries (Pepco Energy Services), under certain contracts in its energy savings performance contracting businesses and underground transmission and distribution construction business. At December 31, 2015, Pepco Holdings’ guarantees of Pepco Energy Services’ obligations under these contracts totaled $269 million. PHI also guarantees the obligations of Pepco Energy Services under surety bonds obtained by Pepco Energy Services for construction projects in these businesses. These guarantees totaled $177 million at December 31, 2015.

In addition, Pepco Holdings guarantees certain obligations of Potomac Electric Power Company (Pepco), Delmarva Power & Light Company (DPL), and Atlantic City Electric Company (ACE) under surety bonds obtained by these subsidiaries, for construction projects and self-insured workers compensation matters. These guarantees totaled $56 million at December 31, 2015.

Pepco Holdings, pursuant to an intercompany guarantee agreement with Potomac Capital Investment Corporation (PCI), guarantees certain intercompany obligations of PCI to its subsidiaries. This guarantee totaled $725 million at December 31, 2015.

361

(5) INVESTMENT IN CONSOLIDATED COMPANIES

Pepco Holdings’ majority owned subsidiaries are recorded using the equity method of accounting. A breakout of the balance in Investment in consolidated companies is as follows:

	2015		2014
	(millions of dollars)
Conectiv, LLC (a)	$	2,198	$	1,984
Potomac Electric Power Company		2,240		2,087
Potomac Capital Investment Corporation		40		30
Pepco Energy Services, Inc.		155		153
PHI Service Company		3		2
Total investment in consolidated companies	$	4,636	$	4,256

(a) Conectiv LLC, is the parent company of Delmarva Power & Light Company and Atlantic City Electric Company.

(6) DISCONTINUED OPERATIONS

During 2015, the income from discontinued operations, net of income taxes, resulted from the Global Tax Settlement reached with the Internal Revenue Service which resolves tax matters related to PHI’s cross-border energy lease investments and is discussed further in Note (11), “Income Taxes” to the consolidated financial statements of Pepco Holdings.

During 2014, there was no activity related to PHI’s discontinued operations.

During 2013, PHI completed the termination of its interest in its cross-border energy lease investments and, as a result, these investments have been accounted for as discontinued operations.

In December 2009, PHI announced the wind-down of the retail energy supply component of the Pepco Energy Services business which was comprised of the retail electric and natural gas supply businesses. In 2013, Pepco Energy Services completed the wind-down and, accordingly, the operations of Pepco Energy Services’ retail electric and natural gas supply businesses have been classified as discontinued operations.

(7) RELATED PARTY TRANSACTIONS

As of December 31, 2015 and 2014, PHI had the following balances on its balance sheets due (to) from related parties:

	2015			2014
	(millions of dollars)
(Payable to) Receivable from Related Party (current) (a)
Conectiv Communications, Inc.	$	(4	)	$	(4	)
PHI Service Company		(4	)		(10	)
Other		—			1
Total	$	(8	)	$	(13	)
Payable to Related Party (non-current) (b)
Potomac Capital Investment Corporation	$	(498	)	$	(494	)
Money Pool Balance (included in cash and cash equivalents)	$	—		$	65

(a) Included in Accounts payable due to associated companies.

(b) Included in Notes payable due to subsidiary companies.

362

(8) DIVIDEND RESTRICTIONS

PHI, on a stand-alone basis, generates no operating income of its own. Accordingly, its ability to pay dividends to its shareholders depends on dividends received from its subsidiaries. In addition to their future financial performance, the ability of PHI’s direct and indirect subsidiaries to pay dividends is subject to limits imposed by: (i) state corporate laws, which impose limitations on the funds that can be used to pay dividends and, in the case of ACE, the regulatory requirement that it obtain the prior approval of the New Jersey Board of Public Utilities before dividends can be paid if its equity as a percent of its total capitalization, excluding securitization debt, falls below 30%; (ii) the prior rights of holders of mortgage bonds and other long-term debt issued by the subsidiaries, and any other restrictions imposed in connection with the incurrence of liabilities; and (iii) certain provisions of ACE’s charter that impose restrictions on payment of common stock dividends for the benefit of preferred stockholders. Pepco, DPL and ACE have no shares of preferred stock outstanding at December 31, 2015. Currently, the capitalization ratio limitation to which ACE is subject and the restriction in the ACE charter do not limit ACE’s ability to pay common stock dividends. As further described in Note (10), “Debt,” to the consolidated financial statements of Pepco Holdings, PHI, Pepco, DPL and ACE have restrictions on total indebtedness in relation to total capitalization under the credit facility.

PHI had approximately $617 million and $565 million of retained earnings free of restrictions at December 31, 2015 and 2014, respectively. These amounts represent the total retained earnings balances at those dates. The amount of restricted net assets for PHI’s consolidated subsidiaries at December 31, 2015 is $2,633 million.

363

Schedule II, Valuation and Qualifying Accounts, for each registrant is submitted below.

Pepco Holdings, Inc.

Col. A	Col. B		Col. C				Col. D			Col. E
			Additions
Description	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts (a)		Deductions(b)			Balance at End of Period
			(millions of dollars)
Year Ended December 31, 2015 Allowance for uncollectible accounts - customer and other accounts receivable	$	40	$	59	$	5	$	(48	)	$	56
Year Ended December 31, 2014 Allowance for uncollectible accounts - customer and other accounts receivable	$	38	$	46	$	9	$	(53	)	$	40
Year Ended December 31, 2013 Allowance for uncollectible accounts - customer and other accounts receivable	$	34	$	37	$	5	$	(38	)	$	38

(a) Collection of accounts previously written off.

(b) Uncollectible accounts written off.

Potomac Electric Power Company

Col. A	Col. B		Col. C				Col. D			Col. E
			Additions
Description	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts (a)		Deductions(b)			Balance at End of Period
			(millions of dollars)
Year Ended December 31, 2015 Allowance for uncollectible accounts - customer and other accounts receivable	$	16	$	20	$	1	$	(20	)	$	17
Year Ended December 31, 2014 Allowance for uncollectible accounts - customer and other accounts receivable	$	16	$	17	$	2	$	(19	)	$	16
Year Ended December 31, 2013 Allowance for uncollectible accounts - customer and other accounts receivable	$	13	$	15	$	1	$	(13	)	$	16

(a) Collection of accounts previously written off.

(b) Uncollectible accounts written off.

364

Delmarva Power & Light Company

Col. A	Col. B		Col. C				Col. D			Col. E
			Additions
Description	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts (a)		Deductions(b)			Balance at End of Period
	(millions of dollars)
Year Ended December 31, 2015 Allowance for uncollectible accounts - customer and other accounts receivable	$	11	$	20	$	2	$	(16	)	$	17
Year Ended December 31, 2014 Allowance for uncollectible accounts - customer and other accounts receivable	$	12	$	13	$	4	$	(18	)	$	11
Year Ended December 31, 2013 Allowance for uncollectible accounts - customer and other accounts receivable	$	9	$	11	$	1	$	(9	)	$	12

(a) Collection of accounts previously written off.

(b) Uncollectible accounts written off.

Atlantic City Electric Company

Col. A	Col. B		Col. C				Col. D			Col. E
			Additions
Description	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts (a)		Deductions(b)			Balance at End of Period
	(millions of dollars)
Year Ended December 31, 2015 Allowance for uncollectible accounts - customer and other accounts receivable	$	9	$	18	$	2	$	(12	)	$	17
Year Ended December 31, 2014 Allowance for uncollectible accounts - customer and other accounts receivable	$	10	$	12	$	3	$	(16	)	$	9
Year Ended December 31, 2013 Allowance for uncollectible accounts - customer and other accounts receivable	$	11	$	11	$	3	$	(15	)	$	10

(a) Collection of accounts previously written off.

(b) Uncollectible accounts written off.

365

3. EXHIBITS

The documents listed below are being filed or furnished on behalf of PHI, Pepco, DPL and/or ACE, as indicated. The warranties, representations and covenants contained in any of the agreements included or incorporated by reference herein or which appear as exhibits hereto should not be relied upon by buyers, sellers or holders of PHI’s or its subsidiaries’ securities and are not intended as warranties, representations or covenants to any individual or entity except as specifically set forth in such agreement.

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
2.1	PHI Pepco DPL ACE	Agreement and Plan of Merger, dated as of April 29, 2014, among PHI, Exelon Corporation and Purple Acquisition Corp.	Exh. 2.1 to PHI’s Form 8-K, 4/30/14.
2.2	PHI Pepco DPL ACE	Amended and Restated Agreement and Plan of Merger, dated as of July 18, 2014, among PHI, Exelon Corporation and Purple Acquisition Corp.	Exh. 2.1 to PHI’s Form 8-K, 7/21/14.
2.3	PHI	Extension Letter, dated July 29, 2015	Exh. 2.1 to PHI’s Form 8-K, 7/29/15.
2.4	PHI	Letter Agreement, dated as of October 6, 2015, among PHI, Exelon Corporation and Purple Acquisition Corp.	Exh. 2 to PHI’s Form 8-K, dated 10/6/15.
2.5	PHI	Subscription Agreement, dated as of April 29, 2014, between PHI and Exelon Corporation	Exh. 2.2 to PHI’s Form 8-K, 4/30/14.
3.1	PHI	Restated Certificate of Incorporation (filed in Delaware 6/2/05)	Exh. 3.1 to PHI’s Form 10-K, 3/13/06.
3.2	PHI	Certificate of Designation for Series A Non-Voting Non-Convertible Preferred Stock (filed in Delaware 4/30/14)	Exh. 3.1 to PHI’s Form 8-K, 4/30/14.
3.3	Pepco	Restated Articles of Incorporation and Articles of Restatement (as filed in the District of Columbia)	Exh. 3.1 to Pepco’s Form 10-Q, 5/5/06.
3.4	Pepco	Restated Articles of Incorporation and Articles of Restatement (as filed in Virginia)	Exh. 3.3 to PHI’s Form 10-Q, 11/4/11.
3.5	DPL	Articles of Restatement of Certificate and Articles of Incorporation (filed in Delaware and Virginia 02/22/07)	Exh. 3.3 to DPL’s Form 10-K, 3/1/07.
3.6	ACE	Restated Certificate of Incorporation (filed in New Jersey 8/09/02)	Exh. B.8.1 to PHI’s Amendment No. 1 to Form U5B, 2/13/03.
3.7	PHI	Bylaws	Exh. 3 to PHI’s Form 8-K, 10/7/15.
3.8	Pepco	Bylaws	Exh. 3.2 to Pepco’s Form 10-Q, 5/5/06.
3.9	DPL	Bylaws	Exh. 3.2.1 to DPL’s Form 10-Q, 5/9/05.

366

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
3.10	ACE	Bylaws	Exh. 3.2.2 to ACE’s Form 10-Q, 5/9/05.
4.1	PHI Pepco	Mortgage and Deed of Trust, dated July 1, 1936, of Pepco to The Bank of New York Mellon as successor trustee, securing First Mortgage Bonds of Pepco, and Supplemental Indenture dated July 1, 1936	Exh. B-4 to First Amendment, 6/19/36, to Pepco’s Registration Statement No. 2-2232.
		Supplemental Indentures, to the aforesaid Mortgage and Deed of Trust, dated as of
		December 10, 1939	Exh. B to Pepco’s Form 8-K, 1/3/40.
		July 15, 1942	Exh. B-1 to Amendment No. 2, 8/24/42, and B-3 to Post-Effective Amendment, 8/31/42, to Pepco’s Registration Statement No. 2-5032.
		October 15, 1947	Exh. A to Pepco’s Form 8-K, 12/8/47.
		December 31, 1948	Exh. A-2 to Pepco’s Form 10-K, 4/13/49.
		December 31, 1949	Exh. (a)-1 to Pepco’s Form 8-K, 2/8/50.
		February 15, 1951	Exh. (a) to Pepco’s Form 8-K, 3/9/51.
		February 16, 1953	Exh. (a)-1 to Pepco’s Form 8-K, 3/5/53.
		March 15, 1954 and March 15, 1955	Exh. 4-B to Pepco’s Registration Statement No. 2-11627, 5/2/55.
		March 15, 1956	Exh. C to Pepco’s Form 10-K, 4/4/56.
		April 1, 1957	Exh. 4-B to Pepco’s Registration Statement No. 2-13884, 2/5/58.
		May 1, 1958	Exh. 2-B to Pepco’s Registration Statement No. 2-14518, 11/10/58.
		May 1, 1959	Exh. 4-B to Amendment No. 1, 5/13/59, to Pepco’s Registration Statement No. 2-15027.
		May 2, 1960	Exh. 2-B to Pepco’s Registration Statement No. 2-17286, 11/9/60.

367

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
		April 3, 1961	Exh. A-1 to Pepco’s Form 10-K, 4/24/61.
		May 1, 1962	Exh. 2-B to Pepco’s Registration Statement No. 2-21037, 1/25/63.
		May 1, 1963	Exh. 4-B to Pepco’s Registration Statement No. 2-21961, 12/19/63.
		April 23, 1964	Exh. 2-B to Pepco’s Registration Statement No. 2-22344, 4/24/64.
		May 3, 1965	Exh. 2-B to Pepco’s Registration Statement No. 2-24655, 3/16/66.
		June 1, 1966	Exh. 1 to Pepco’s Form 10-K, 4/11/67.
		April 28, 1967	Exh. 2-B to Post-Effective Amendment No. 1 to Pepco’s Registration Statement No. 2-26356, 5/3/67.
		July 3, 1967	Exh. 2-B to Pepco’s Registration Statement No. 2-28080, 1/25/68.
		May 1, 1968	Exh. 2-B to Pepco’s Registration Statement No. 2-31896, 2/28/69.
		June 16, 1969	Exh. 2-B to Pepco’s Registration Statement No. 2-36094, 1/27/70.
		May 15, 1970	Exh. 2-B to Pepco’s Registration Statement No. 2-38038, 7/27/70.
		September 1, 1971	Exh. 2-C to Pepco’s Registration Statement No. 2-45591, 9/1/72.
		June 17, 1981	Exh. 2 to Amendment No. 1 to Pepco’s Form 8-A, 6/18/81.
		November 1, 1985	Exh. 2B to Pepco’s Form 8-A, 11/1/85.
		September 16, 1987	Exh. 4-B to Pepco’s Registration Statement No. 33-18229, 10/30/87.
		May 1, 1989	Exh. 4-C to Pepco’s Registration Statement No. 33-29382, 6/16/89.
		May 21, 1991	Exh. 4 to Pepco’s Form 10-K, 3/27/92.

368

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
		May 7, 1992	Exh. 4 to Pepco’s Form 10-K, 3/26/93.
		September 1, 1992	Exh. 4 to Pepco’s Form 10-K, 3/26/93.
		November 1, 1992	Exh. 4 to Pepco’s Form 10-K, 3/26/93.
		July 1, 1993	Exh. 4.4 to Pepco’s Registration Statement No. 33-49973, 8/11/93.
		February 10, 1994	Exh. 4 to Pepco’s Form 10-K, 3/25/94.
		February 11, 1994	Exh. 4 to Pepco’s Form 10-K, 3/25/94.
		October 2, 1997	Exh. 4 to Pepco’s Form 10-K, 3/26/98.
		November 17, 2003	Exh. 4.1 to Pepco’s Form 10-K, 3/11/04.
		March 16, 2004	Exh. 4.3 to Pepco’s Form 8-K, 3/23/04.
		May 24, 2005	Exh. 4.2 to Pepco’s Form 8-K, 5/26/05.
		April 1, 2006	Exh. 4.1 to Pepco’s Form 8-K, 4/17/06.
		November 13, 2007	Exh. 4.2 to Pepco’s Form 8-K, 11/15/07.
		March 24, 2008	Exh. 4.1 to Pepco’s Form 8-K, 3/28/08.
		December 3, 2008	Exh. 4.2 to Pepco’s Form 8-K, 12/8/08.
		March 28, 2012	Exh. 4.2 to Pepco’s Form 8-K, 3/29/12.
		March 11, 2013	Exh. 4.2 to Pepco’s Form 8-K, 3/12/13.
		November 14, 2013	Exh. 4.2 to Pepco’s Form 8-K, 11/15/13.
		March 11, 2014	Exh. 4.2 to Pepco’s Form 8-K, 3/12/14.
		March 9, 2015	Exh. 4.3 to Pepco’s Form 8-K, 3/10/15.
4.2	PHI Pepco	Indenture, dated as of July 28, 1989, between Pepco and The Bank of New York Mellon, Trustee, with respect to Pepco’s Medium-Term Note Program	Exh. 4 to Pepco’s Form 8-K, 6/21/90.
4.3	PHI Pepco	Senior Note Indenture, dated November 17, 2003 between Pepco and The Bank of New York Mellon	Exh. 4.2 to Pepco’s Form 8-K, 11/21/03.
		Supplemental Indenture, to the aforesaid Senior Note Indenture, dated March 3, 2008	Exh. 4.3 to Pepco’s Form 10-K, 3/2/09.

369

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
4.4	PHI DPL	Mortgage and Deed of Trust of Delaware Power & Light Company to The Bank of New York Mellon (ultimate successor to the New York Trust Company), as trustee, dated as of October 1, 1943 and copies of the First through Sixty-Eighth Supplemental Indentures thereto	Exh. 4-A to DPL’s Registration Statement No. 33-1763, 11/27/85.
		Sixty-Ninth Supplemental Indenture	Exh. 4-B to DPL’s Registration Statement No. 33-39756, 4/03/91.
		Seventieth through Seventy-Fourth Supplemental Indentures	Exhs. 4-B to DPL’s Registration Statement No. 33-24955, 10/13/88.
		Seventy-Fifth through Seventy-Seventh Supplemental Indentures	Exhs. 4-D, 4-E and 4-F to DPL’s Registration Statement No. 33-39756, 4/03/91.
		Seventy-Eighth and Seventy-Ninth Supplemental Indentures	Exhs. 4-E and 4-F to DPL’s Registration Statement No. 33-46892, 4/1/92.
		Eightieth Supplemental Indenture	Exh. 4 to DPL’s Registration Statement No. 33-49750, 7/17/92.
		Eighty-First Supplemental Indenture	Exh. 4-G to DPL’s Registration Statement No. 33-57652, 1/29/93.
		Eighty-Second Supplemental Indenture	Exh. 4-H to DPL’s Registration Statement No. 33-63582, 5/28/93.
		Eighty-Third Supplemental Indenture	Exh. 99 to DPL’s Registration Statement No. 33-50453, 10/1/93.
		Eighty-Fourth through Eighty-Eighth Supplemental Indentures	Exhs. 4-J, 4-K, 4-L, 4-M and 4-N to DPL’s Registration Statement No. 33-53855, 1/30/95.
		Eighty-Ninth and Ninetieth Supplemental Indentures	Exhs. 4-K and 4-L to DPL’s Registration Statement No. 333-00505, 1/29/96.
		Ninety-First Supplemental Indenture	Exh. 4.L to DPL’s Registration Statement No. 333-24059, 3/27/97.
		Ninety-Second Supplemental Indenture	Exh. 4.4 to DPL’s Form 10-K, 2/24/12.
		Ninety-Third Supplemental Indenture	Exh. 4.4 to DPL’s Form 10-K, 2/24/12.
		Ninety-Fourth Supplemental Indenture	Exh. 4.4 to DPL’s Form 10-K, 2/24/12.

370

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
		Ninety-Fifth Supplemental Indenture	Exh. 4-K to DPL’s Post Effective Amendment No. 1 to Registration Statement No. 333-145691-02, 11/18/08.
		Ninety-Sixth Supplemental Indenture	Exh. 4.4 to DPL’s Form 10-K, 2/24/12.
		Ninety-Seventh Supplemental Indenture	Exh. 4.4 to DPL’s Form 10-K, 2/24/12.
		Ninety-Eighth Supplemental Indenture	Exh. 4.4 to DPL’s Form 10-K, 2/24/12.
		Ninety-Ninth Supplemental Indenture	Exh. 4.4 to DPL’s Form 10-K, 2/24/12.
		One Hundredth Supplemental Indenture	Exh. 4.4 to DPL’s Form 10-K, 2/24/12.
		One Hundred and First Supplemental Indenture	Exh. 4.4 to DPL’s Form 10-K, 2/24/12.
		One Hundred and Second Supplemental Indenture	Exh. 4.4 to DPL’s Form 10-K, 2/24/12.
		One Hundred and Third Supplemental Indenture	Exh. 4.4 to DPL’s Form 10-K, 2/24/12.
		One Hundred and Fourth Supplemental Indenture	Exh. 4.4 to DPL’s Form 10-K, 2/24/12.
		One Hundred and Fifth Supplemental Indenture	Exh. 4.4 to DPL’s Form 8-K, 10/1/09.
		One Hundred and Sixth Supplemental Indenture	Exh. 4.4 to DPL’s Form 10-K, 2/25/11.
		One Hundred and Seventh Supplemental Indenture	Exh. 4.2 to DPL’s Form 10-Q, 8/3/11.
		One Hundred and Eighth Supplemental Indenture	Exh. 4.2 to DPL’s Form 8-K, 6/3/11.
		One Hundred and Ninth Supplemental Indenture	Exh. 4.3 to DPL’s Form 10-Q, 8/7/12.
		One Hundred and Tenth Supplemental Indenture	Exh. 4.2 to DPL’s Form 8-K, 6/20/12.
		One Hundred and Eleventh Supplemental Indenture	Exh. 4.1 to DPL’s Form 10-Q, 8/6/13.
		One Hundred and Twelfth Supplemental Indenture	Exh. 4.2 to DPL’s Form 8-K, 11/8/13.
		One Hundred and Thirteenth Supplemental Indenture	Exhibit 4.4 to DPL’s Form 10-K, 2/27/15.
		One Hundred and Fourteenth Supplemental Indenture	Exh. 4.3 to DPL’s Form 8-K, 6/3/14.
		One Hundred and Fifteenth Supplemental Indenture	Filed herewith.
		One Hundred and Sixteenth Supplemental Indenture	Exh. 4.2 to DPL’s Form 8-K, 5/5/15.

371

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
4.5	PHI DPL	Indenture between DPL and The Bank of New York Mellon Trust Company, N.A. (ultimate successor to Manufacturers Hanover Trust Company), as trustee, dated as of November 1, 1988	Exh. No. 4-G to DPL’s Registration Statement No. 33-46892, 4/1/92.
4.6	PHI ACE	Mortgage and Deed of Trust, dated January 15, 1937, between ACE and The Bank of New York Mellon (formerly Irving Trust Company), as trustee	Exh. 2(a) to ACE’s Registration Statement No. 2-66280, 12/21/79.
		Supplemental Indentures, to the aforesaid Mortgage and Deed of Trust, dated as of -
		June 1, 1949	Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
		July 1, 1950	Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
		November 1, 1950	Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
		March 1, 1952	Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
		January 1, 1953	Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
		March 1, 1954	Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
		March 1, 1955	Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
		January 1, 1957	Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
		April 1, 1958	Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
		April 1, 1959	Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
		March 1, 1961	Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.

372

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
		July 1, 1962	Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
		March 1, 1963	Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
		February 1, 1966	Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
		April 1, 1970	Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
		September 1, 1970	Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
		May 1, 1971	Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
		April 1, 1972	Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
		June 1, 1973	Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
		January 1, 1975	Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
		May 1, 1975	Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
		December 1, 1976	Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
		January 1, 1980	Exh. 4(e) to ACE’s Form 10-K, 3/25/81.
		May 1, 1981	Exh. 4(a) to ACE’s Form 10-Q, 8/10/81.
		November 1, 1983	Exh. 4(d) to ACE’s Form 10-K, 3/30/84.
		April 15, 1984	Exh. 4(a) to ACE’s Form 10-Q, 5/14/84.
		July 15, 1984	Exh. 4(a) to ACE’s Form 10-Q, 8/13/84.
		October 1, 1985	Exh. 4 to ACE’s Form 10-Q, 11/12/85.
		May 1, 1986	Exh. 4 to ACE’s Form 10-Q, 5/12/86.
		July 15, 1987	Exh. 4(d) to ACE’s Form 10-K, 3/28/88.

373

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
		October 1, 1989	Exh. 4(a) to ACE’s Form 10-Q for quarter ended 9/30/89.
		March 1, 1991	Exh. 4(d)(1) to ACE’s Form 10-K, 3/28/91.
		May 1, 1992	Exh. 4(b) to ACE’s Registration Statement No. 33-49279, 1/6/93.
		January 1, 1993	Exh. 4.05(hh) to ACE’s Registration Statement No. 333-108861, 9/17/03.
		August 1, 1993	Exh. 4(a) to ACE’s Form 10-Q, 11/12/93.
		September 1, 1993	Exh. 4(b) to ACE’s Form 10-Q, 11/12/93.
		November 1, 1993	Exh. 4(c)(1) to ACE’s Form 10-K, 3/29/94.
		June 1, 1994	Exh. 4(a) to ACE’s Form 10-Q, 8/14/94.
		October 1, 1994	Exh. 4(a) to ACE’s Form 10-Q, 11/14/94.
		November 1, 1994	Exh. 4(c)(1) to ACE’s Form 10-K, 3/21/95.
		March 1, 1997	Exh. 4(b) to ACE’s Form 8-K, 3/24/97.
		April 1, 2004	Exh. 4.3 to ACE’s Form 8-K, 4/6/04.
		August 10, 2004	Exh. 4 to PHI’s Form 10-Q, 11/8/04.
		March 8, 2006	Exh. 4 to ACE’s Form 8-K, 3/17/06.
		November 6, 2008	Exh. 4.2 to ACE’s Form 8-K, 11/10/08.
		March 29, 2011	Exh. 4.2 to ACE’s Form 8-K, 4/1/11.
		August 18, 2014	Exh. 4.2 to ACE’s Form 8-K, 8/19/14.
		December 1, 2015	Exh. 4.2 to ACE’s Form 8-K, 12/2/15.
4.7	PHI ACE	Indenture, dated as of March 1, 1997 between ACE and The Bank of New York Mellon, as trustee	Exh. 4(e) to ACE’s Form 8-K, 3/24/97.
4.8	PHI ACE	Senior Note Indenture, dated as of April 1, 2004, with The Bank of New York Mellon, as trustee	Exh. 4.2 to ACE’s Form 8-K, 4/6/04.
4.9	PHI ACE	Indenture, dated as of December 19, 2002 between Atlantic City Electric Transition Funding LLC (ACE Funding) and The Bank of New York Mellon, as trustee	Exh. 4.1 to ACE Funding’s Form 8-K, 12/23/02.

374

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
4.10	PHI ACE	2002-1 Series Supplement, dated as of December 19, 2002 between ACE Funding and The Bank of New York Mellon, as trustee	Exh. 4.2 to ACE Funding’s Form 8-K, 12/23/02.
4.11	PHI ACE	2003-1 Series Supplement, dated as of December 23, 2003 between ACE Funding and The Bank of New York Mellon, as trustee	Exh. 4.2 to ACE Funding’s Form 8-K, 12/23/03.
4.12	PHI	Indenture, dated September 6, 2002, between PHI and The Bank of New York Mellon, as trustee	Exh. 4.03 to PHI’s Registration Statement No. 333-100478, 10/10/02.
4.13	PHI Pepco DPL ACE	Corporate Commercial Paper – Master Note	Exh. 4.13 to PHI’s Form 10-K, 2/24/12.
4.14	PHI	Certificate of Series A Non-Voting Non-Convertible Preferred Stock	Exh. 4.1 to PHI’s Form 8-K, 4/30/14.
10.1	ACE	Bondable Transition Property Sale Agreement, dated as of December 19, 2002, between ACE Funding and ACE	Exh. 10.1 to ACE Funding’s Form 8-K, 12/23/02.
10.2	ACE	Bondable Transition Property Servicing Agreement, dated as of December 19, 2002, between ACE Funding and ACE	Exh. 10.2 to ACE Funding’s Form 8-K, 12/23/02.
10.3	PHI	Purchase Agreement, dated as of April 20, 2010, by and among PHI, Conectiv, LLC, Conectiv Energy Holding Company, LLC and New Development Holdings, LLC	Exh. 2.1 to PHI’s Form 8-K, 7/8/10.
10.4	Pepco	Purchase Agreement, dated March 11, 2014, among Pepco and J.P. Morgan Securities LLC, RBS Securities Inc. and Wells Fargo Securities, LLC, as representatives of the several underwriters named therein	Exh. 1.1 to Pepco’s Form 8-K, 3/12/14.
10.5	Pepco	Purchase Agreement, dated March 9, 2015, among Pepco and BNY Mellon Capital Markets, LLC, Morgan Stanley & Co. LLC, and RBS Securities Inc., as representatives of the several underwriters named therein	Exh. 1.1 to Pepco’s Form 8-K, 3/10/15.
10.6	DPL	Purchase Agreement, dated June 2, 2014, among DPL, Morgan Stanley & Co. LLC and SunTrust Robinson Humphrey, Inc., as representatives of the several underwriters named therein	Exh. 1.1 to DPL’s Form 8-K, 6/3/14.

375

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
10.7	DPL	Purchase Agreement, May 4, 2015, among DPL and J.P. Morgan Securities LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, and Scotia Capital (USA) Inc., as representatives of the several underwriters named therein	Exh. 1.1 to DPL’s Form 8-K, 5/5/15.
10.8	ACE	Purchase Agreement, dated August 18, 2014, among ACE, and each of Barclays Capital Inc. and KeyBanc Capital Markets Inc., as representatives of the several underwriters named therein	Exh. 1.1 to ACE’s Form 8-K, 8/19/14.
10.9	ACE	Bond Purchase Agreement, dated December 1, 2015, among ACE and the purchasers signatory thereto	Exh. 1.1 to ACE’s Form 8-K, 12/2/15.
10.10	ACE	$100,000,000 Term Loan Agreement by and among ACE, KeyBank National Association, as Administrative Agent, SunTrust Bank, as Documentation Agent, and the Lenders Party Thereto, dated May 10, 2013	Exh. 10 to ACE’s Form 8-K, 5/10/13.
10.11	PHI	$250,000,000 Term Loan Agreement by and among PHI, JPMorgan Chase Bank, N.A., as Administrative Agent, The Bank of Nova Scotia, as Documentation Agent, and the Lenders Party Thereto, dated March 28, 2013	Exh. 10 to PHI’s Form 8-K, 3/28/13.
10.12	PHI	$300,000,000 Term Loan Agreement by and among PHI, The Bank of Nova Scotia, as Administrative Agent, and the lenders party thereto, dated July 30, 2015	Exh. 10 to PHI’s Form 8-K, 7/30/15.
10.13	PHI	First Amendment to Term Loan Agreement, dated as of October 29, 2015, by and among PHI, The Bank of Nova Scotia, as Administrative Agent, and the lenders party thereto	Exh. 10.2 to PHI’s Form 8-K, 10/29/15.
10.14	PHI	$500,000,000 Term Loan Agreement by and among PHI, The Bank of Nova Scotia, as Administrative Agent, and the lenders party thereto, dated January 13, 2016	Exh. 10 to PHI’s Form 8-K, 1/14/16.

376

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
10.15	PHI Pepco DPL ACE	Second Amended and Restated Credit Agreement, dated as of August 1, 2011, by and among PHI, Pepco, DPL and ACE, the lenders party thereto, Wells Fargo Bank, National Association, as agent, issuer and swingline lender, Bank of America, N.A., as syndication agent and issuer, The Royal Bank of Scotland plc and Citicorp USA, Inc., as co-documentation agents, Wells Fargo Securities, LLC and Merrill Lynch, Pierce, Fenner and Smith Incorporated, as active joint lead arrangers and joint book runners, and Citigroup Global Markets Inc. and RBS Securities, Inc. as passive joint lead arrangers and joint book runners	Exh. 10.1 to PHI’s Form 10-Q, 8/3/11.
10.15.1	PHI Pepco DPL ACE	First Amendment, dated as of August 2, 2012, to Second Amended and Restated Credit Agreement, dated as of August 1, 2011, by and among PHI, Pepco, DPL and ACE, the various financial institutions party thereto, Wells Fargo Bank, National Association, as agent, issuer of letters of credit and swingline lender, Bank of America, N.A., as syndication agent and issuer of letters of credit, and The Royal Bank of Scotland plc and Citibank, N.A., as co-documentation agents	Exh. 10.25.1 to PHI’s Form 10-K, 3/1/13.
10.15.2	PHI Pepco DPL ACE	Amendment and Consent to Second Amended and Restated Credit Agreement, dated as of May 20, 2014, by and among PHI, Pepco, DPL, ACE, the various financial institutions from time to time party thereto, Bank of America, N.A. and Wells Fargo Bank, National Association.	Exh. 10.1 to PHI’s Form 8-K, 5/20/14.
10.15.3	PHI Pepco DPL ACE	Third Amendment to Second Amended and Restated Credit Agreement, dated as of May 1, 2015, by and among PHI, Pepco, DPL, ACE, the various financial institutions from time to time party thereto, Bank of America, N.A. and Wells Fargo Bank, National Association.	Exhibit 10.1 to PHI’s Form 8-K, 5/1/15.

377

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
10.15.4	PHI Pepco DPL ACE	Consent, dated as of October 29, 2015, by and among PHI, Pepco, DPL, ACE, the various financial institutions from time to time party thereto, Bank of America, N.A. and Wells Fargo Bank, National Association.	Exh. 10.1 to PHI’s Form 8-K, 10/29/15.
10.16	DPL	Reoffering Agreement, dated May 18, 2011, by and among DPL and Morgan Stanley & Co. Incorporated, as remarketing agent, and Morgan Stanley & Co. Incorporated, as underwriter	Exh. 1.1 to DPL’s Form 8-K, 6/3/11.
10.17	PHI Pepco DPL ACE	Form of Issuing and Paying Agency Agreement, dated August 28, 2014, between Bank of America, National Association, and each Reporting Company	Exh. 10.14 to PHI’s Form 10-K, 2/27/15.
10.18	PHI	Employment Agreement of Joseph M. Rigby, dated December 20, 2011 (including forms of Restricted Stock Unit Award Agreements contained therein)*	Exh. 10 to PHI’s Form 8-K, 12/27/11.
10.18.1	PHI	Amendment to the 2013 Performance-Based Restricted Stock Unit Award Agreement, effective as of October 25, 2013*	Exh. 10.2 to PHI’s Form 8-K, 10/25/13.
10.19	PHI	Employment Extension Agreement, by and between PHI and Joseph M. Rigby, effective April 29, 2014*	Exh. 10.1 to PHI’s Form 8-K, 5/2/14.
10.19.1	PHI	Amendment to Pepco Holdings, Inc. Amended and Restated Annual Executive Incentive Compensation Plan*	Exh. 10.19.1 to PHI’s Form 10-K, 2/27/15.
10.20	PHI	Letter Agreement between Pepco Holdings, Inc. and Frederick J. Boyle*	Exh. 10 to PHI’s Form 8-K, 3/26/12.
10.21	PHI	Employment Agreement, dated September 7, 2012, by and between PHI and Kevin C. Fitzgerald (including forms of Restricted Stock Unit Award Agreements contained therein)*	Exh. 10.1 to PHI’s Form 10-Q, 11/6/12.
10.22	PHI	Extension Agreement, dated as of September 11, 2015, by and between PHI and Kevin C. Fitzgerald*	Exh. 10 to PHI’s Form 8-K, 9/11/15.
10.23	PHI	Pepco Holdings, Inc. Amended and Restated Annual Executive Incentive Compensation Plan*	Exh. 10.30.1 to PHI’s Form 10-K, 2/24/12.
10.24	PHI	Pepco Holdings, Inc. Long-Term Incentive Plan (as amended and restated)*	Exh. 10.5 to PHI’s Form 10-K, 3/2/09.

378

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
10.24.1	PHI	Amendment to the Pepco Holdings, Inc. Long-Term Incentive Plan*	Exh. 10.2.1 to PHI’s Form 10-K, 2/24/12.
10.25	PHI	Pepco Holdings, Inc. 2012 Long-Term Incentive Plan*	Exh. 10.10 to PHI’s Form 10-K, 3/1/13.
10.25.1	PHI	Amendment to Pepco Holdings, Inc. 2012 Long-Term Incentive Plan, effective as of March 28, 2014*	Exh. 10.2.2 to PHI’s Form 10-Q, 5/7/14.
10.25.2	PHI	Second Amendment to Pepco Holdings, Inc. 2012 Long-Term Incentive Plan*	Exh. 10.21.2 to PHI’s Form 10-K, 2/27/15.
10.26	PHI	Form of Restricted Stock Unit Agreement (Director Award) under the PHI 2012 Long-Term Incentive Plan*	Exh. 10.4 to PHI’s Form 10-Q, 8/7/12.
10.27	PHI	Form of 2014 Restricted Stock Unit Agreement (Time-Vested) under the PHI 2012 Long-Term Incentive Plan*	Exh. 10.3 to PHI’s Form 10-Q, 5/7/14.
10.28	PHI	Form of 2015 Restricted Stock Unit Agreement (Time-Vested) under the PHI 2012 Long-Term Incentive Plan*	Exh. 10.4 to PHI’s Form 10-Q, 5/1/15.
10.29	PHI	Form of 2014 Restricted Stock Unit Agreement (Time-Vested) under the PHI 2012 Long-Term Incentive Plan for Joseph M. Rigby*	Exh. 10.4 to PHI’s Form 10-Q, 5/7/14.
10.30	PHI	Form of 2015 Restricted Stock Unit Agreement (Time-Vested) under the PHI 2012 Long-Term Incentive Plan for Joseph M. Rigby*	Exh. 10.5 to PHI’s Form 10-Q, 5/1/15.
10.31	PHI	Form of 2014 Restricted Stock Unit Agreement (Time-Vested) under the PHI 2012 Long-Term Incentive Plan for Kevin C. Fitzgerald*	Exh. 10.5 to PHI’s Form 10-Q, 5/7/14.
10.32	PHI	Form of 2015 Restricted Stock Unit Agreement (Time-Vested) under the PHI 2012 Long-Term Incentive Plan for Kevin C. Fitzgerald*	Exh. 10.6 to PHI’s Form 10-Q, 5/1/15.
10.33	PHI	Form of 2014 Restricted Stock Unit Agreement (Performance-Based/162(m)) under the PHI 2012 Long-Term Incentive Plan*	Exh. 10.6 to PHI’s Form 10-Q, 5/7/14.
10.34	PHI	Form of 2014 Restricted Stock Unit Agreement (Performance-Based/162(m)) under the PHI 2012 Long-Term Incentive Plan for Joseph M. Rigby*	Exh. 10.7 to PHI’s Form 10-Q, 5/7/14.
10.35	PHI	Form of 2014 Restricted Stock Unit Agreement (Performance-Based/162(m)) under the PHI 2012 Long-Term Incentive Plan for Kevin C. Fitzgerald*	Exh. 10.8 to PHI’s Form 10-Q, 5/7/14.

379

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
10.36	PHI	Form of 2014 Restricted Stock Unit Agreement (Performance-Based/Non-162(m)) under the PHI 2012 Long-Term Incentive Plan*	Exh. 10.9 to PHI’s Form 10-Q, 5/7/14.
10.37	PHI	Form of Restricted Stock Award Agreement (Performance-Based/162(m)) under the 2012 Long-Term Incentive Plan*	Exh. 10.2 to PHI’s Form 10-Q, 10/31/14.
10.38	PHI	Pepco Holdings, Inc. Second Revised and Restated Executive and Director Deferred Compensation Plan*	Exh. 10.31.1 to PHI’s Form 10-K, 2/24/12.
10.39	PHI Pepco	Potomac Electric Power Company Director and Executive Deferred Compensation Plan*	Exh. 10.22 to PHI’s Form 10-K, 3/28/03.
10.40	PHI	Conectiv Deferred Compensation Plan*	Exh. 10.1 to PHI’s Form 10-Q, 8/6/04.
10.41	PHI	Form of 2015 Non-Management Director Compensation Election Agreement*	Exh. 10.42 to PHI’s Form 10-K, 2/27/15.
10.42	PHI	Form of 2015 Executive and Director Deferred Compensation Plan Executive Deferral Agreement*	Exh. 10.44 to PHI’s Form 10-K, 2/27/15.
10.43	PHI	Form of 2016 Executive and Director Deferred Compensation Plan Executive Deferral Agreement*	Filed herewith.
10.44	PHI	Non-Management Director Compensation Arrangements*	Exh. 10.13 to PHI’s Form 10-K, 3/1/13.
10.45	PHI Pepco	Change-in-Control Severance Plan for Certain Executive Employees*	Exh. 10.25 to PHI’s Form 10-K, 3/2/09.
10.45.1	PHI Pepco	Amended and Restated Change in Control / Severance Plan for Certain Executive Employees*	Exh. 10 to PHI’s Form 8-K, 7/31/13.
10.46	PHI	Pepco Holdings, Inc. Combined Executive Retirement Plan*	Exh. 10.28 to PHI’s Form 10-K, 3/2/09.
10.46.1	PHI	Amendment to the Pepco Holdings, Inc. Combined Executive Retirement Plan*	Exh. 10.3 to PHI’s Form 10-Q, 8/3/11.
10.47	PHI	The Pepco Holdings, Inc. 2011 Supplemental Executive Retirement Plan*	Exh. 10.2 to PHI’s Form 10-Q, 8/3/11.
10.48	PHI DPL ACE	Conectiv Supplemental Executive Retirement Plan*	Exh. 10.10 to PHI’s Form 10-K, 3/2/09.
10.48.1	PHI DPL ACE	Amendment to the Conectiv Supplemental Executive Retirement Plan*	Exh. 10.4 to PHI’s Form 10-Q, 8/3/11.
10.49	PHI	PHI Named Executive Officer 2015 Compensation Determinations*	Exh. 10.51 to PHI’s Form 10-K, 2/27/15.

380

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
10.50	PHI	PHI Named Executive Officer 2016 Compensation Determinations and Other Compensation Information*	Filed herewith.
10.51	PHI	Restricted Stock Award Agreement, by and between PHI and Joseph M. Rigby, effective April 30, 2014 (Immediate Vesting) *	Exh. 10.2 to PHI’s Form 8-K, 5/2/14.
10.52	PHI	Restricted Stock Award Agreement, by and between PHI and Joseph M. Rigby, effective April 30, 2014*	Exh. 10.3 to PHI’s Form 8-K, 5/2/14.
10.53	PHI	Pepco Holdings, Inc. 2014 Management Employee Severance Plan*	Exh. 10.4 to PHI’s Form 8-K, 5/2/14.
10.54	Pepco	Asset Purchase and Sale Agreement for Generating Plants and Related Assets, dated as of June 7, 2000, by and between Pepco and Southern Energy, Inc.	Exh. 10 to Pepco’s Form 8-K, 6/13/00.
10.54.1	Pepco	Amendment No. 1 to the Asset Purchase and Sale Agreement for Generating Plants and Related Assets, dated September 18, 2000, by and between Pepco and Southern Energy, Inc.	Exh. 10.1 to Pepco’s Form 8-K, 12/9/00.
10.54.2	Pepco	Amendment No. 2 to the Asset Purchase and Sale Agreement for Generating Plants and Related Assets, dated December 19, 2000, by and between Pepco and Southern Energy, Inc.	Exh. 10.2 to Pepco’s Form 8-K, 12/9/00.
11	PHI	Statements Re: Computation of Earnings Per Common Share	**
12.1	PHI	Statements Re: Computation of Ratios	Filed herewith.
12.2	Pepco	Statements Re: Computation of Ratios	Filed herewith.
12.3	DPL	Statements Re: Computation of Ratios	Filed herewith.
12.4	ACE	Statements Re: Computation of Ratios	Filed herewith.
21	PHI	Subsidiaries of the Registrant	Filed herewith.
23.1	PHI	Consent of Independent Registered Public Accounting Firm	Filed herewith.
23.2	Pepco	Consent of Independent Registered Public Accounting Firm	Filed herewith.
23.3	DPL	Consent of Independent Registered Public Accounting Firm	Filed herewith.
23.4	ACE	Consent of Independent Registered Public Accounting Firm	Filed herewith.
31.1	PHI	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	Filed herewith.
31.2	PHI	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	Filed herewith.

381

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
31.3	Pepco	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	Filed herewith.
31.4	Pepco	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	Filed herewith.
31.5	DPL	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	Filed herewith.
31.6	DPL	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	Filed herewith.
31.7	ACE	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	Filed herewith.
31.8	ACE	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	Filed herewith.
99	PHI	Audit Committee Policy on the Approval of Services Provided By the Independent Auditor	Filed herewith.
101. INS	PHI Pepco DPL ACE	XBRL Instance Document	Filed herewith.
101. SCH	PHI Pepco DPL ACE	XBRL Taxonomy Extension Schema Document	Filed herewith.
101. CAL	PHI Pepco DPL ACE	XBRL Taxonomy Extension Calculation Linkbase Document	Filed herewith.
101. DEF	PHI Pepco DPL ACE	XBRL Taxonomy Extension Definition Linkbase Document	Filed herewith.
101. LAB	PHI Pepco DPL ACE	XBRL Taxonomy Extension Label Linkbase Document	Filed herewith.
101. PRE	PHI Pepco DPL ACE	XBRL Taxonomy Extension Presentation Linkbase Document	Filed herewith.

* Management contract or compensatory plan or arrangement.

** The information required by this Exhibit is set forth in Note (12), “Stock-Based Compensation, Dividend Restrictions and Calculations of Earnings Per Share of Common Stock,” of the consolidated financial statements of Pepco Holdings, Inc. included in Part II, Item 8 “Financial Statements and Supplementary Data” of this Form 10-K.

382

Regulation S-K Item 10(d) requires registrants to identify the physical location, by SEC file number reference, of all documents incorporated by reference that are not included in a registration statement and have been on file with the SEC for more than five years. The SEC file number references for PHI and each of its subsidiaries that are currently registrants, Conectiv and ACE Funding are provided below:

Pepco Holdings, Inc. (File Nos. 001-31403 and 030-00359)

Potomac Electric Power Company (File No. 001-01072)

Delmarva Power & Light Company (File No. 001-01405)

Atlantic City Electric Company (File No. 001-03559)

Conectiv (File No. 001-13895)

Atlantic City Electric Transition Funding LLC (File No. 333-59558)

Certain instruments defining the rights of the holders of long-term debt of PHI, Pepco, DPL and ACE (including medium-term notes, unsecured notes, senior notes and tax-exempt financing instruments) have not been filed as exhibits in accordance with Regulation S-K Item 601(b)(4)(iii) because such instruments do not authorize securities in an amount which exceeds 10% of the total assets of the applicable registrant and its subsidiaries on a consolidated basis. Each of PHI, Pepco, DPL or ACE agrees to furnish to the SEC upon request a copy of any such instruments omitted by it.

383

INDEX TO FURNISHED EXHIBITS

The documents listed below are being furnished herewith:

Exhibit No.	Registrant(s)	Description of Exhibit
32.1	PHI	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350
32.2	Pepco	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350
32.3	DPL	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350
32.4	ACE	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350

(b) Exhibits.

The list of exhibits filed or furnished with this Form 10-K are set forth on the exhibit index appearing at the end of this Form 10-K

384

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, each of the registrants has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	PEPCO HOLDINGS, INC. (Registrant)
February 18, 2016	By	/s/ JOSEPH M. RIGBY
		Joseph M. Rigby Chairman of the Board, President and Chief Executive Officer
	POTOMAC ELECTRIC POWER COMPANY (Pepco) (Registrant)
February 18, 2016	By	/s/ DAVID M. VELAZQUEZ
		David M. Velazquez, President and Chief Executive Officer
	DELMARVA POWER & LIGHT COMPANY (DPL) (Registrant)
February 18, 2016	By	/s/ DAVID M. VELAZQUEZ
		David M. Velazquez, President and Chief Executive Officer
	ATLANTIC CITY ELECTRIC COMPANY (ACE) (Registrant)
February 18, 2016	By	/s/ DAVID M. VELAZQUEZ
		David M. Velazquez, President and Chief Executive Officer

385

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the above named registrants and in the capacities and on the dates indicated:

/s/ JOSEPH M. RIGBY Joseph M. Rigby	Chairman of the Board, President and Chief Executive Officer of Pepco Holdings, Director of Pepco, DPL and ACE (Principal Executive Officer of Pepco Holdings)	February 18, 2016
/s/ DAVID M. VELAZQUEZ David M. Velazquez	President and Chief Executive Officer of Pepco, DPL and ACE, Director of Pepco and DPL (Principal Executive Officer of Pepco, DPL and ACE)	February 18, 2016
/s/ FRED BOYLE Frederick J. Boyle	Senior Vice President and Chief Financial Officer of Pepco Holdings, Pepco, and DPL, Chief Financial Officer of ACE and Director of Pepco (Principal Financial Officer of Pepco Holdings, Pepco, DPL and ACE)	February 18, 2016
/s/ RONALD K. CLARK Ronald K. Clark	Vice President and Controller of Pepco Holdings, Pepco and DPL and Controller of ACE (Principal Accounting Officer of Pepco Holdings, Pepco, DPL and ACE)	February 18, 2016

386

Signature	Title	Date
/s/ PAUL M. BARBAS	Director, Pepco Holdings	February 18, 2016
Paul M. Barbas
/s/ J.B. DUNN	Director, Pepco Holdings	February 18, 2016
Jack B. Dunn, IV
/s/ H. RUSSELL FRISBY, JR.	Director, Pepco Holdings	February 18, 2016
H. Russell Frisby, Jr.
/s/ T. C. GOLDEN	Director, Pepco Holdings	February 18, 2016
Terence C. Golden
/s/ BARBARA J. KRUMSIEK	Director, Pepco Holdings	February 18, 2016
Barbara J. Krumsiek
/s/ LAWRENCE C. NUSSDORF	Director, Pepco Holdings	February 18, 2016
Lawrence C. Nussdorf
/s/ PATRICIA A. OELRICH	Director, Pepco Holdings	February 18, 2016
Patricia A. Oelrich
/s/ LESTER P. SILVERMAN	Director, Pepco Holdings	February 18, 2016
Lester P. Silverman
/s/ KEVIN C. FITZGERALD	Director, Pepco and DPL	February 18, 2016
Kevin C. Fitzgerald
/s/ CHARLES R. DICKERSON	Director, Pepco	February 18, 2016
Charles R. Dickerson
/s/ WILLIAM M. GAUSMAN	Director, Pepco	February 18, 2016
William M. Gausman
/s/ MICHAEL J. SULLIVAN	Director, Pepco	February 18, 2016
Michael J. Sullivan

387

INDEX TO EXHIBITS FILED HEREWITH

Exhibit No.	Registrant(s)	Description of Exhibit
4.4	PHI DPL	One Hundred and Fifteenth Supplemental Indenture
10.43	PHI	Form of 2016 Executive and Director Deferred Compensation Plan Executive Deferral Agreement*
10.50	PHI	PHI Named Executive Officer 2016 Compensation Determinations and Other Compensation Information*
12.1	PHI	Statements Re: Computation of Ratios
12.2	Pepco	Statements Re: Computation of Ratios
12.3	DPL	Statements Re: Computation of Ratios
12.4	ACE	Statements Re: Computation of Ratios
21	PHI	Subsidiaries of the Registrant
23.1	PHI	Consent of Independent Registered Public Accounting Firm
23.2	Pepco	Consent of Independent Registered Public Accounting Firm
23.3	DPL	Consent of Independent Registered Public Accounting Firm
23.4	ACE	Consent of Independent Registered Public Accounting Firm
31.1	PHI	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer
31.2	PHI	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer
31.3	Pepco	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer
31.4	Pepco	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer
31.5	DPL	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer
31.6	DPL	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer
31.7	ACE	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer
31.8	ACE	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer
99	PHI	Audit Committee Policy on the Approval of Services Provided By the Independent Auditor
101. INS	PHI Pepco DPL ACE	XBRL Instance Document
101. SCH	PHI Pepco DPL ACE	XBRL Taxonomy Extension Schema Document
101. CAL	PHI Pepco DPL ACE	XBRL Taxonomy Extension Calculation Linkbase Document

388

Exhibit No.	Registrant(s)	Description of Exhibit
101. DEF	PHI Pepco DPL ACE	XBRL Taxonomy Extension Definition Linkbase Document
101. LAB	PHI Pepco DPL ACE	XBRL Taxonomy Extension Label Linkbase Document
101. PRE	PHI Pepco DPL ACE	XBRL Taxonomy Extension Presentation Linkbase Document

* Management contract or compensatory plan or arrangement.

INDEX TO EXHIBITS FURNISHED HEREWITH

32.1	PHI	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350
32.2	Pepco	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350
32.3	DPL	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350
32.4	ACE	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350

389

EX-4.4

Exhibit 4.4

This Instrument Prepared By:

Christie D. Cannon

Delmarva Power & Light Company

Mailstop 92DC42

500 N. Wakefield Drive

Newark, DE 19702-5440

DELMARVA POWER & LIGHT COMPANY

TO

THE BANK OF NEW YORK MELLON,

Trustee.

ONE HUNDRED AND FIFTEENTH SUPPLEMENTAL

INDENTURE

Dated as of January 1, 2015

(but executed on the dates shown on the execution page)

1

This ONE HUNDRED AND FIFTEENTH SUPPLEMENTAL INDENTURE, dated as of the first day of January, 2015 (but executed on the dates hereinafter shown), made and entered into by and between DELMARVA POWER & LIGHT COMPANY, a corporation of the State of Delaware and the Commonwealth of Virginia, hereinafter called the Company and THE BANK OF NEW YORK MELLON, a New York banking corporation, hereinafter called the Trustee;

WITNESSETH:

WHEREAS, the Company heretofore executed and delivered its Indenture of Mortgage and Deed of Trust (hereinafter in this One Hundred and Fifteenth Supplemental Indenture called the “Original Indenture”), dated as of October 1, 1943, to The New York Trust Company, a corporation of the State of New York, as Trustee, to which The Bank of New York Mellon is successor Trustee, to secure the First Mortgage Bonds of the Company, unlimited in aggregate principal amount and issuable in series, from time to time, in the manner and subject to the conditions set forth in the Original Indenture granted and conveyed unto the Trustee, upon the trusts, uses and purposes specifically therein set forth, certain real estate, franchises and other property therein described, including property acquired after the date thereof, except as therein otherwise provided; and

WHEREAS, the Original Indenture has been supplemented by one hundred and fourteen supplemental indentures specifically subjecting to the lien of the Original Indenture as though included in the granting clause thereof certain property in said supplemental indentures specifically described and amending and modifying the provisions of the Original Indenture (the Original Indenture, as amended, modified and supplemented by all of the indentures supplemental thereto, including this One Hundred and Fifteenth Supplemental Indenture, is hereinafter in this One Hundred and Fifteenth Supplemental Indenture called the “Indenture”); and

WHEREAS, the execution and delivery of this One Hundred and Fifteenth Supplemental Indenture has been duly authorized by Unanimous Written Consent of the Board of Directors of the Company, and all conditions and requirements necessary to make this One Hundred and Fifteenth Supplemental Indenture a valid, binding and legal instrument in accordance with its terms, for the purposes herein expressed, and the execution and delivery hereof, have been in all respects duly authorized; and

WHEREAS, it is provided in and by the Original Indenture, inter alia, as follows:

“IT IS HEREBY AGREED by the Company that all the property, rights and franchises acquired by the Company after the date hereof (except any hereinbefore or hereinafter expressly excepted) shall (subject to the provisions of Section 9.01 hereof and to the extent permitted by law) be as fully embraced within the lien hereof as if such property, rights and franchises were now owned by the Company and/or specifically described herein and conveyed hereby;”

and

WHEREAS, the Company has acquired certain other property, real, personal and mixed, which heretofore has not been specifically conveyed to the Trustee;

NOW, THEREFORE, this ONE HUNDRED AND FIFTEENTH SUPPLEMENTAL INDENTURE WITNESSETH that for and in consideration of the premises and in pursuance of the provisions of the Indenture, the Company has granted, bargained, sold, released, conveyed, assigned, transferred, mortgaged, pledged, set over and confirmed, and by these presents does grant, bargain, sell, release, convey, assign, transfer, mortgage, pledge, set over and confirm unto the Trustee and to its successors in the trust in the Indenture created, to its and their assigns forever, all the following described properties of the Company, and does confirm that the Company will not cause or consent to a partition, either voluntary or through legal proceedings, of property, whether herein described or

2

heretofore or hereafter acquired, in which its ownership shall be as tenant in common, except as permitted by, and in conformity with, the provisions of the Indenture and particularly of Article IX thereof:

MARYLAND

Cecil County

Property Name	Instrument Date	Deed Records		Tax Map No.
		Liber	Folio
Theodore Substation	06/13/2014	3582	085	Map 23 Parcel 215, Lot 1
MARYLAND Wicomico County
Property Name	Instrument Date	Deed Records		Tax Map No.
		Liber	Folio
BRO Warehouse Expansion / Standard Register Storage Building (600 Marvel Rd, Salisbury MD 21801)	10/16/2014	3764	025	Map 102 Parcel 56

Together with all other property, real, personal and mixed, tangible and intangible (except such property as in said Indenture expressly excepted from the lien and operation thereof), acquired by the Company on or prior to December 31, 2014, and not heretofore specifically subjected to the lien of the Indenture.

3

Also without limitation of the generality of the foregoing, the easements and rights-of-way and other rights in or relating to real estate or the occupancy of the same owned by the Company, and whether used or not used in connection with the Company’s operations, which are conveyed to the Company and recorded in the following Real Property Deed Records to which reference is made for a more particular description, to wit:

DELAWARE

New Castle County

Instrument Date	Instrument No.	Tax ID No.
1/24/2013	20140520-0020762	0601400155
11/18/2013	20140520-0020768	1101700026
11/26/2013	20140520-0020769	0805010094
12/9/2013	20140520-0020761	1301800001
12/23/2013	20140602-0022462	0803000007 0802400060
1/7/2014	20140520-0020775	0802430169, 0802430185, 0803010378, 0803010397, 0803020181, 0803020212, 0802440413, 0802440423
1/31/2014	20140520-0020772	0701900003
2/4/2014	20140520-0020776	0805200003
2/6/2014	20140523-0021422	0803500017
3/10/2014	20140520-0020777	1501100019
4/3/2014	20140523-0021421	0702930001 0702930043
5/1/2014	20140819-0036343	1004000044
5/7/2014	20140819-0036350	0702600080
5/7/2014	20140819-0036348	0702600076
5/9/2014	20140819-0036354	0702600085
5/10/2014	20140819-0036353	0702600084
5/13/2014	20140819-0036351	0702600082
5/15/2014	20140819-0036355	0702600086
5/21/2014	20140819-0036347	0702600075
5/21/2014	20140819-0036352	0702600083
5/27/2014	20140819-0036349	0702600078
5/29/2014	20140611-0024401	0702600088
6/24/2014	20140819-0036357	0702600088
6/27/2014	20140819-0036356	0702600087
7/2/2014	20141007-0044838	0610200065
7/11/2014	20140819-0036346	0702600073
7/11/2014	20140819-0036345	0702600072
7/14/2014	20140721-0030974	1301914002, 1301914076, 1301932001, 1301932018, 1301932059, 1301932061, 1304932098, 1301932103, 1301932111, 1301932123, 1301932138, 1301932149, 1301932158, 1301932190

4

Instrument Date	Instrument No.	Tax ID No.
7/14/2014	20140721-0030975	1301932110, 1301932156, 1301932155, 1301932109, 1301932154, 1301932153, 1301932130, 1301932182, 1301932183, 1301932184, 1301932131, 1301932185, 1301932186, 1301932187, 1301932132, 1301932188, 1301932189, 1301932133, 1301932190, 1301932124, 1301932125, 1301932126, 1301932127, 1301932128, 1301932129, 1301932108, 1301932107, 1301932016, 1301932105, 1301932014, 1301932097, 1301932096, 1301932095, 1301932094, 1301932093, 1301932092, 1301932152, 1301932091 , 1301932151, 1301932150, 1301932090, 1301932019, 1301932020, 1301932022, 1301932023, 1301932024, 1301932025, 1301932026, 1301932107, 1301932108, 1301932029, 1301932030, 1301932031, 1301932032, 1301932033, 1301932034, 1301932035, 1301932036, 1301932037, 1301932038, 1301932039, 1301932040, 1301932041, 1301934001, 1301934002, 1301934003, 1301934004, 1301932042, 1301932043, 1301932044, 1301932045, 1301932046, 1301932047, 1301932048, 1301932049, 1301932050, 1301932051, 1301932052, 1301932053, 1301932054, 1301932055, 1301932056, 1301932057, 1301932058, 1301932062, 1301934005, 1301934006, 1301934007, 1301934008, 1301934020, 1301934021, 1301932063, 1301932064, 1301932065, 1301932066, 1301932067, 1301932068, 1301932069, 1301932072, 1301932073, 1301932074, 1301932075, 1301932076, 1301932077, 1301932078, 1301934018, 1301934019, 1301934009, 1301934010, 1301934011, 1301934012, 1301934013, 1301934014, 1301934015, 1301934016, 1301934017, 1301932079, 1301932080, 1301932081, 1301932082, 1301932083, 1301932084, 1301932085, 1301932086, 1301932087, 1301932088, 1301932089, 1301932071, 1301932070, 1301932136, 1301932137
7/15/2014	20141003-0044260	0702600074
7/21/2014	20140819-0036344	0611700001
7/26/2014	20140911-0040372	0611200187
9/6/2014	20148022-0036861	0803330166 0803330167
9/12/2014	20140926-0042914	0603000117
9/12/2014	20140926-0042913	0603000215
9/12/2014	20140926-0042912	0603000214
9/16/2014	20140926-0042915	0702930017
9/18/2014	20140926-0042916	0701300069
9/22/2014	20141003-0044259	0702600081
9/24/2014	20141003-0044262	0704140275
9/26/2014	20141006-0044459	0611600119
9/26/2014	20141007-0044839	0701700020
9/26/2014	20141016-0046458	2700100583
10/2/2014	20141007-0045008	0801800101

5

Instrument Date	Instrument No.	Tax ID No.
10/27/2014	20141113-0050973	0609100151
10/30/2014	20141106-0050063	1101300015
7/3/2014	20140721-0030976	0703810450 0703810451
9/24/2014	20141003-0044261	1003530049
3/4/2014	20140523-0021423	0701100092

DELAWARE

Sussex County

Instrument Date	Deed Records		Tax ID No.
	Book	Page
3/25/2014	4267	212	134-17.00-110.1
4/4/2014	4267	210	334-60.06-9.00
4/4/2014	4267	208	334-60.06-6.09
4/25/2014	4267	204	135-19.00-630.4
4/25/2014	4267	206	135-19.00-630.1
5/29/2014	4273	262	131-14.00-440.1
6/17/2014	4276	234	134-17.00-110.0
7/7/2014	4286	166	134-13.19-137.00
7/8/2014	4286	168	531-4.00-29.02
7/11/2014	4309	177	532-13.00-780.0
7/16/2014	4289	336	134-13.00-143.00
8/15/2014	4318	250	233-50.01-000
9/12/2014	4309	179	532-60.08-500
9/29/2014	4308	1	190-0.02-01.4
10/20/2014	4342	73	135-15.13-11.00
10/31/2014	4331	241	532-12.82-01.5

MARYLAND

Caroline County

Received For Record	Deed Records		Map/Parcel/Lot
	Book	Page
9/10/2013	1112	194	600/217
10/7/2013	1112	197	59/50
10/7/2013	1112	201	59/49
5/7/2014	1112	203	600/242

6

MARYLAND

Cecil County

Instrument Date	Deed Records		Map/Parcel/Lot
	Book	Page
6/12/2012	3593	537	8/16
7/12/2012	3593	519	21/189
7/27/2012	3593	512	21/625
9/10/2012	3593	515	21/805
12/7/2012	3593	517	21/611
1/2/2013	3593	488	67/7
1/4/2013	3593	535	8/13
1/18/2013	3593	531	25/791
1/18/2013	3593	547	67/15
1/22/2013	3593	533	26/667
1/30/2013	3593	543	12/17
2/6/2013	3593	539	3/211
2/21/2013	3593	541	18/280
2/27/2013	3593	481	21/104
3/18/2013	3593	525	3/27
3/18/2013	3593	521	3/55
3/26/2013	3593	507	316/2480
3/28/2013	3593	510	303/1128
4/29/2013	3593	495	25/809
5/14/2013	3593	502	9/295
5/23/2013	3593	529	31/142
6/6/2013	3593	500	18/20
6/7/2013	3593	497	18/432
6/13/2013	3593	504	11/15
6/21/2013	3593	493	31/1167
7/28/2013	3593	545	3/210
8/1/2013	3593	549	42/28
8/6/2013	3593	491	316/2443
8/28/2013	3629	200	46/6
9/12/2013	3572	393	30/42
10/22/2013	3572	402	53/35
11/10/2013	3572	387	16/16
11/12/2013	3629	204	46/210/2
11/19/2013	3572	398	23/712
12/1/2013	3572	408	48/125
12/2/2013	3572	374	42/87
12/2/2013	3572	405	17/536
12/16/2013	3594	345	9/366
1/24/2014	3572	377	41/101
1/24/2014	3572	411	25/95
2/4/2014	3629	197	46/210/1
2/6/2014	3593	486	100/54,310,311
3/12/2014	3593	484	100/305
3/24/2014	3629	202	46/200

7

Instrument Date	Deed Records		Map/Parcel/Lot
	Book	Page
4/11/2014	3572	383	5/195
4/29/2014	3629	194	46/134
5/19/2014	3583	495	2/24
5/28/2014	3594	343	12/332
6/16/2014	3591	367	6/60
7/8/2014	3639	202	52/19
7/25/2014	3639	206	52/20A
8/13/2014	3609	372	36/39
8/13/2014	3609	370	36/38
9/2/2014	3618	378	5/78
10/5/2014	3640	227	17/328
10/25/2014	3642	289	2/43
10/25/2014	3644	134	52/224
11/3/2014	3629	192	46/7
2/7/20014	3572	370	3/61

MARYLAND

Dorchester County

Instrument Date	Deed Records		Map/Parcel/Lot
	Liber	Folio
10/19/2012	1207	430	50/12
1/22/2013	1207	425	36/114
2/14/2013	1207	417	40/149
3/8/2013	1207	412	40/24
3/15/2013	1207	421	40/150
5/10/2013	1207	407	36/45
7/10/2013	1207	402	301/317
4/8/2014	1211	379	5/4
8/13/2014	1222	256	35/59
9/8/2014	1240	191	31/135
11/25/2014	1240	196	6/221

8

MARYLAND

Harford County

Instrument Date	Deed Records		Map/Parcel/Lot
	Liber	Folio
10/2/2012	10794	327	11/372
11/5/2012	10794	343	19/315
3/13/2013	10794	335	12/95
3/23/2013	10794	340	12/208
6/9/2013	10794	332	25/18
9/1/2013	10754	168	12/32
7/8/2014	10851	261	11/372
7/11/2014	10842	65	5/300
9/27/2014	10908	274	19/27

MARYLAND

Kent County

Instrument Date	Deed Records		Map/Parcel/Lot
	Liber	Folio
2/5/2013	0795	149	1A/42
3/19/2013	0796	211	45/47
3/20/2013	0796	244	4/100
3/22/2013	0796	242	4/109
3/28/2013	0796	215	1/41
4/30/2013	0795	152	42/97
5/9/2013	0796	207	45/6
5/14/2013	0795	154	42/86
5/14/2013	0796	240	48/22B
5/15/2013	0796	213	41/4
5/15/2013	0796	224	4/93
5/15/2013	0796	226	4/9
5/21/2013	0796	238	48/17
5/29/2013	0796	236	204/975
6/4/2013	0796	232	48/22A
6/4/2013	0796	234	48/22
6/14/2013	0796	228	27/16
6/14/2013	0796	230	48/67
6/19/2013	0796	222	27/471
7/18/2013	0796	217	27/98
7/18/2013	0796	219	201/979
8/28/2013	0795	158	42/6
8/28/2013	0795	156	42/7
10/9/2013	0796	209	12/50
10/23/2013	0796	203	44/146
11/14/2013	0796	205	45/4
1/8/2014	0803	380	20/270

9

Instrument Date	Deed Records	Map/Parcel/Lot
	Liber	Folio
2/26/2014	0796	199	37/161
3/10/2014	0800	461	12/161
3/13/2014	0800	467	12/171
3/13/2014	0800	465	12/230
3/13/2014	0800	469	12/163
3/13/2014	0800	471	12/178
3/13/2014	0800	463	12/121
3/17/2014	0796	197	51/72
4/4/2014	0810	047	12/65
4/9/2014	0810	056	12/113
4/14/2014	0794	334	13/74
4/15/2014	0810	058	12/148
4/23/2014	0794	336	46/124
5/10/2014	0810	053	12/96
5/27/2014	0810	050	12/88
6/9/2014	0797	369	36/146
7/8/2014	0800	473	12/181
7/25/2014	0810	060	16/33
7/25/2014	0810	062	16/38
7/25/2014	0810	064	16/47
7/30/2014	0804	003	12/118
8/5/2014	0804	001	20/6
9/17/2014	0808	213	203/1343
11/21/2014	0814	001	37/83

MARYLAND

Queen Anne’s County

Instrument Date	Deed Records		Map/Parcel/Lot
	Liber	Folio
2/14/2012	2290	462	51/34/2
6/6/2012	2290	438	21/199
6/11/2012	2290	446	9/58
8/24/2012	2290	449	28/155
10/13/2012	2290	442	28/44
10/10/2013	2290	474	35/28
10/31/2013	2290	470	35/25
11/1/2013	2290	466	57/144
3/14/2014	2309	188	48/11
6/2/2014	2294	411	44C/1111
7/3/2014	2339	284	10/88
7/7/2014	2306	455	28/76
7/7/2014	2339	290	35/51
7/9/2014	2307	35	35H/35
7/12/2014	2307	32	28/102

10

Instrument Date	Deed Records	Map/Parcel/Lot
	Liber	Folio
7/17/2014	2290	360	56/46
7/23/2014	2326	249	9/22
8/8/2014	2326	267	18/35
8/19/2014	2324	363	51/34
8/29/2014	2327	46	2203/622
9/4/2014	2324	381	65/31
9/4/2014	2324	375	65/51
9/5/2014	2323	239	5C/224
9/7/2014	2353	418	58D740
9/16/2014	2353	402	58D/418
9/16/2014	2353	405	58D/421
9/16/2014	2353	408	58D/422
9/16/2014	2353	411	58D/423
9/23/2014	2332	35	59/8
10/16/2014	2353	394	58D/429
10/16/2014	2353	398	58E/756
11/5/2014	2353	414	58D/654
11/24/2014	2353	421	58/381
12/3/2014	2354	178	44C/815

MARYLAND

Somerset County

Instrument Date	Deed Records		Map/Parcel/Lot
	Liber	Folio
5/21/2014	874	221	224/57
7/28/2014	878	580	23/166
9/8/2014	881	431	41/92
12/5/2014	887	305	42/89
12/8/2014	887	382	20/246
12/8/2014	887	385	41/126
12/8/2014	887	388	41/223

MARYLAND

Talbot County

Instrument Date	Deed Records		Map/Parcel/Lot
	Liber	Folio
4/15/2013	2174	444	22/90
4/26/2013	2174	432	405/400
5/11/2013	2174	436	22/19
5/23/2013	2174	441	22/65
5/30/2013	2174	424	21/43/2
5/30/2013	2174	428	21/26

11

Instrument Date	Deed Records	Map/Parcel/Lot
	Liber	Folio
6/13/2013	2174	402	22/62/6
6/20/2013	2174	406	22/61
7/5/2013	2174	411	22/111/1A
8/16/2013	2174	414	22/356/1
11/26/2013	2174	393	44A275/3
11/27/2013	2174	398	31/99
3/17/2014	2174	448	62/1
3/17/2014	2174	452	62/2
3/17/2014	2174	456	62/58
3/17/2014	2174	460	62/62
6/2/2014	2178	215	39/79/3
8/4/2014	2191	259	31/7
8/5/2014	2191	256	22/203
10/30/2014	2216	200	42/167
11/26/2014	2220	362	42/290

MARYLAND

Wicomico County

Instrument Date	Deed Records		Map/Parcel/Lot
	Liber	Folio
3/20/2013	3711	512	38/180
4/1/2013	3711	517	116/2524
5/8/2013	3711	507	117/3125
9/25/2013	3711	492	803/1459
10/23/2013	3711	498	302/1032
11/18/2013	3711	488	59/51
7/25/2014	3731	48	29/54
7/26/2014	3733	131	61/53
8/14/2014	3739	120	804/961
8/14/2014	3779	179	20/416
8/14/2014	3779	175	20/395
8/28/2014	3744	90	31/304
8/28/2014	3744	93	31/37
9/16/2014	3779	172	20/388
10/15/2014	3763	79	38/29
10/17/2014	3764	278	106/1120
10/27/2014	3779	169	20/383
10/30/2014	3770	71	37/409
11/10/2014	3779	166	20/351
11/13/2014	3779	163	600/246
11/25/2014	3779	160	38/284
11/25/2014	3779	157	20/196
11/25/2014	3779	154	20/194
11/25/2014	3779	151	20/193

12

Instrument Date	Deed Records	Map/Parcel/Lot
	Liber	Folio
11/25/2014	3779	145	20/189
11/25/2014	3779	141	21/142
11/25/2014	3779	138	21/126
11/25/2014	3779	135	21/126/1
11/25/2014	3779	132	21/126/7
11/25/2014	3779	129	21/61
12/4/2014	3786	383	106/1109

MARYLAND

Worcester County

Instrument Date	Deed Records		Map/Parcel/Lot
	Liber	Folio
3/11/2014	6467	355	10/311
3/25/2014	6384	100	113/6746
4/1/2014	6384	110	64/72
5/1/2014	6384	107	19/139
5/14/2014	6384	97	27/128
7/11/2014	6464	135	9/170
7/14/2014	6403	500	92/39
7/16/2014	6414	284	79/181
8/5/2014	6418	332	25/241
9/14/2014	6443	92	26/417
4/20/2014	6384	104	47/95

13

The following is a schedule of bonds issued under the Eighty-Eighth Supplemental Indenture and Credit Line Deed of Trust, effective as of October 1, 1994, that can be designated as First Mortgage Bonds, Series I, which may also be designated as Secured Medium Term Notes, Series I; and First Mortgage Bonds, Pledged Series I.

First Mortgage Bonds, Series I/Secured Medium Term Notes, Series I

Issuance Date	Tranche	Maturity	Principal
06/19/95	7.71% Bonds	06/01/25	$	100,000,000
06/19/95	6.95% Amortizing Bonds	06/01/08	$	25,800,000
11/25/08	6.40% Bonds	12/01/13	$	250,000,000

First Mortgage Bonds, Pledged Series I

Issuance Date	Tranche	Maturity	Principal
10/12/94	1994	10/01/29	$	33,750,000
Total Bonds Issued:			$	409,550,000

As supplemented and amended by this One Hundred and Fifteenth Supplemental Indenture, the Original Indenture and all indentures supplemental thereto are in all respects ratified and confirmed and the Original Indenture and the aforesaid supplemental indentures and this One Hundred and Fifteenth Supplemental Indenture shall be read, taken and construed as one and the same instrument.

This One Hundred and Fifteenth Supplemental Indenture shall be simultaneously executed in several counterparts, and all such counterparts executed and delivered, each as an original, shall constitute but one and the same instrument.

The recitals of fact contained herein shall be taken as the statements of the Company, and the Trustee assumes no responsibility for the correctness of the same.

The debtor and its mailing address are Delmarva Power & Light Company, Mailstop 92DC42, 500 N. Wakefield Drive, Newark, Delaware 19702-5440. The secured party and its address, from which information concerning the security interest hereunder may be obtained, is The Bank of New York Mellon, 525 William Penn Place, 38^th Floor, Pittsburgh, Pennsylvania 15259, Attn: Ms. Leslie Lockhart, Corporate Trust Officer.

The Company acknowledges that it received a true and correct copy of this One Hundred and Fifteenth Supplemental Indenture.

This One Hundred and Fifteenth Supplemental Indenture is executed and delivered pursuant to the provisions of Section 5.11 and paragraph (a) of Section 17.01 of the Indenture for the purpose of conveying, transferring and assigning to the Trustee and of subjecting to the lien of the Indenture with the same force and effect as though included in the granting clause thereof the above described property so acquired by the Company on or prior to the date of execution, and not heretofore specifically subject to the lien of the Indenture; but nothing contained in this One Hundred and Fifteenth Supplemental Indenture shall be deemed in any manner to affect (except for such purposes) or to impair the provisions, terms and conditions of the Original Indenture, or of any indenture supplemental thereto and the provisions, terms and conditions thereof are hereby expressly confirmed.

14

IN WITNESS WHEREOF, the Company has caused this instrument to be signed in its name and behalf by its President, and its corporate seal to be hereunto affixed and attested by its Assistant Secretary and the Trustee has caused this instrument to be signed in its name and behalf by a Vice President and its corporate seal to be hereunto affixed and attested by an authorized officer, effective as of the 1st day of January, 2015.

	DELMARVA POWER & LIGHT COMPANY
Date of Execution	By
		David M. Velazquez, President
April 8, 2015
	Attest:
		Jeffery E. Snyder, Assistant Secretary

DISTRICT OF COLUMBIA: SS.

BE IT REMEMBERED that on this 8^th day of April, 2015, personally came before me, a notary public for the District of Columbia, David M. Velazquez, President of DELMARVA POWER & LIGHT COMPANY, a corporation of the State of Delaware and the Commonwealth of Virginia (the “Company”), party to the foregoing instrument, known to me personally to be such, and acknowledged the instrument to be his own act and deed and the act and deed of the Company; that his signature is in his own proper handwriting; that the seal affixed is the common or corporate seal of the Company; and that his act of signing, sealing, executing and delivering such instrument was duly authorized by resolution of the Board of Directors of the Company.

GIVEN under my hand and official seal the day and year aforesaid.

Notary Public, District of Columbia

My commission expires                                    .

15

THE BANK OF NEW YORK MELLON,

as Trustee

Date of Execution	By
		Francine J. Kincaid, Vice President
April 8, 2015
	Attest:
		Arsala Kidwai, Vice President

STATE OF NEW YORK	)
	) SS.
COUNTY OF NEW YORK	)

BE IT REMEMBERED that on this 8th day of April, 2015, personally came before me, a Notary Public for the State of New York, Francine J. Kincaid, Vice President of THE BANK OF NEW YORK MELLON, a New York banking corporation (the “Trustee”), party to the foregoing instrument, known to me personally to be such, and acknowledged the instrument to be his own act and deed and the act and deed of the Trustee; that his signature is his own proper handwriting; that the seal affixed is the common or corporate seal of the Trustee; and that his act of signing, sealing, executing and delivering said instrument was duly authorized by resolution of the Board of Directors of the Trustee.

GIVEN under my hand and official seal the day and year aforesaid.

Notary Public, State of New York

My commission expires                                    .

16

CERTIFICATE OF RESIDENCE

THE BANK OF NEW YORK MELLON, successor Trustee to the Trustee within named, hereby certifies that it has a residence at 101 Barclay Street, in the Borough of Manhattan, in The City of New York, in the State of New York.

THE BANK OF NEW YORK MELLON
By
Name:	Francine J. Kincaid
Title:	Vice President

17

Certification

This document was prepared under the supervision of an attorney admitted to practice before the Court of Appeals of Maryland, or by or on behalf of one of the parties named in the within instrument.

Christie D. Cannon

18

EX-10.43

Exhibit 10.43

Pepco Holdings, Inc.

2016 NON-MANAGEMENT DIRECTOR COMPENSATION ELECTION AGREEMENT

I understand that I am permitted to elect, with respect to the compensation due me for my services as a director of Pepco Holdings, Inc. (the “Company”), either (i) to receive my cash compensation currently in the form of cash or (ii) to defer the receipt of my cash compensation under the terms of the Company’s Second Revised and Restated Executive and Director Deferred Compensation Plan (the “Deferred Compensation Plan”). In addition, I understand that I am permitted to elect to receive my stock-based compensation granted pursuant to the terms of the 2012 Long-Term Incentive Plan (the “2012 LTIP”), or to defer the settlement of such stock-based compensation as permitted by the 2012 LTIP pursuant to a deferral program approved by the Board of Directors. If I choose to defer the receipt of my cash compensation, I must also complete and return to the Company the attached Cash Retainer Deferral Allocation Form directing how the deferred funds are to be credited.

I understand that, upon the completion of the proposed merger of a wholly owned subsidiary of Exelon Corporation with and into the Company, with the Company being the surviving corporation (the “Merger”), each share of Company common stock and each share underlying stock-based awards of the Company will be converted in the right to receive $27.25 in cash, without interest (the “Cash Consideration”). I acknowledge that, if the Merger is consummated, each outstanding restricted stock unit (“RSU”) award (whether vested or unvested) will be automatically converted into the right to receive the Cash Consideration with respect to the number of shares underlying such RSU award in accordance with the terms and conditions of that certain Amended and Restated Agreement and Plan of Merger dated July 18, 2014 (the “Merger Agreement”). I understand that, if the Merger is completed, I will be entitled to receive the Cash Consideration with respect to shares underlying any RSU award I may receive in 2016, as well as all outstanding RSU awards, the settlement of which previously has been deferred by me (a “Deferred Award”). I will receive the Cash Consideration upon the closing of the Merger, or, if I made a prior irrevocable deferral election made with respect to a Deferred Award, at the time I specified in such deferral election.

As a result, with respect to any deferral elections to be made with respect to 2016, I understand that I am being afforded the opportunity hereby to: (i) provide for a contingent and alternate deferral election to the Company phantom shares account of the Deferred Compensation Plan if the Merger is completed during 2016; and (ii) elect to defer the payment of Cash Consideration with respect to Deferred Awards into the Deferred Compensation Plan (other than the Company phantom shares account), which amounts would then become subject to, and distributed to me in accordance with, all of the applicable terms and conditions of the Deferred Compensation Plan.

I am making the following elections with the understanding that the elections (i) will apply to all of the compensation paid to me for service as a director in 2016 (and, if the Merger is completed in 2016, with respect to my (A) prior deferrals of annual retainers and meeting fees that have been credited to my Company phantom shares account under the Deferred Compensation Plan and (B) Cash Consideration that will be deferred in accordance with election(s) I made in prior years with respect to Deferred Award(s)), (ii) once made, cannot be altered or revoked, and (iii) apply to any such compensation paid to me in subsequent years for services as a director of the Company, unless I notify the Company of any changes, either in writing or by execution of a new election form prior to January 1 of the year for which the changes are to take effect.

1. Current Receipt or Deferral Election.

I hereby elect to receive my compensation for services as a director of the Company as follows (the percentages for each type of compensation must total 100%):

a. Annual Cash Retainer

%	Cash (by check or direct deposit).
%	Credit to my account under the Deferred Compensation Plan, to be paid in cash at the time I elect in Item 2 below.

b. Retainer Paid in Form of Restricted Stock Units (“RSUs”)

I will receive an annual stock-based retainer award in the form of RSUs (and any associated dividend equivalents) under the 2012 LTIP, to be settled in Common Stock as indicated below:

%	Common Stock (registered as indicated herein) to be received upon settlement of the RSUs (and any associated dividend equivalents), shall be issued to me upon vesting of the RSUs as provided in the award agreement.
%	Common Stock (registered as indicated herein) to be received upon settlement of the RSUs (and any associated dividend equivalents), shall be deferred under the 2012 LTIP and paid in Common Stock at the time I elect in Item 3 below.

c. Meeting Fees

%	Cash (by check or direct deposit).
%	Credit to my account under the Deferred Compensation Plan, to be paid in cash at the time I elect in Item 2 below.

d. Committee Chairman Retainer (please complete whether or not you currently are a committee chairman):

%	Cash (by check or direct deposit).
%	Credit to my account under the Deferred Compensation Plan, to be paid in cash at the time I elect in Item 2 below.

2. Cash Deferral Instructions.

If you have elected to have all or any portion of your cash retainer(s) or meeting fees credited to your account under the Deferred Compensation Plan, please complete the following:

a. Payment Instructions Related to Cash Amounts Deferred

I hereby elect to have the cash amounts I have deferred under the Deferred Compensation Plan (and accruals thereon) paid to me beginning on the date selected below (check one):

On the first day of the month immediately following the month in which I cease to be a director.

On January 31 of the year immediately following the month in which I cease to be a director.

On January 31 of the year following the calendar year in which (i) I cease to be a director or (ii) I attain the age             , whichever is later.

On January 31 of              [insert year] or, if later, January 31 of the second calendar year following the calendar year which includes the first day of the Plan year for which the election is made.

2

b. Manner of Payment

I hereby elect to have the cash amounts I have deferred under the Deferred Compensation Plan (and accruals thereon) paid to me in the following manner (check one):

In a lump sum on the date of payment selected above.

In equal annual installments over              consecutive years [insert a number of years between 2 and 15]

beginning on the date selected above, with subsequent installments to be paid on each succeeding January 31.

In equal monthly installments over              consecutive months [insert a number of months between 24 and 180] beginning on the date selected above.

YOU MUST COMPLETE THE ATTACHED CASH RETAINER DEFERRAL ALLOCATION FORM TO INDICATE HOW YOU WISH TO HAVE PREVIOUS DEFERRALS OF CASH CREDITED UNDER THE DEFERRED COMPENSATION PLAN, IF THE MERGER IS COMPLETED IN 2016, AND:

• YOU ARE ELECTING TO DEFER CASH YOU WILL RECEIVE IN 2016 INTO THE PHANTOM SHARE ACCOUNT, OR

• YOU HAVE DEFERRED CASH PAYMENTS IN PRIOR YEARS INTO THE PHANTOM SHARE ACCOUNT.

IF YOU DO NOT COMPLETE THIS FORM AND YOU ARE DEFERRING OR HAVE DEFERRED CASH INTO THE PHANTOM SHARE ACCOUNT, IF THE MERGER IS COMPLETED IN 2016, SUCH DEFERRALS WILL NO LONGER BE CREDITED TO THE PHANTOM SHARE ACCOUNT AND WILL, BY DEFAULT, BE CREDITED TO THE PRIME RATE ACCOUNT.

3. Stock-Based Award Deferral Instructions

If I have elected to defer the settlement of my RSU award (and any associated dividend equivalents) under Item 1.b. above, I hereby elect payment to me (or, if applicable, my beneficiary) in a lump sum solely in shares of Common Stock on one of the dates I designate below (but only to the extent that such award has vested):

On the first day of the month immediately following the month in which I cease to be a director.

On January 31 of the year immediately following the month in which I cease to be a director.

On January 31 of the year following the calendar year in which (i) I cease to be a director or (ii) I attain age             , whichever is later.

On January 31 of             [insert year] or, if later, January 31 of the second calendar year following the calendar year which includes the first day of the Plan year for which the election is made.

3

More information on the deferral of Stock-Based Awards under the 2012 LTIP is provided in Item 6 below.

If I have elected under Item 1.b. above to defer the settlement of any RSU award that may be payable to me in 2015, or if I have a prior Deferred Award:

• I understand that if the Merger is consummated in 2016, the payment of shares of Common Stock under such RSU awards will be automatically converted into my right (or, if applicable, the right of my beneficiary) to defer the payment of the Cash Consideration per share with respect to such RSU award (and accruals thereon) under the Deferred Compensation Plan;

• I elect to have such Cash Consideration (and accruals thereon) paid to me beginning on the date selected above with respect to any 2016 Deferred Award; and

• With respect to any prior Deferred Award, the Cash Consideration payable with respect to such award upon completion of the Merger will be deferred under the Deferred Compensation Plan until the date I previously selected with respect to that award.

YOU MUST COMPLETE THE ATTACHED LTIP RSU CONVERSION DEFERRAL ALLOCATION FORM TO INDICATE HOW YOU WISH TO HAVE CASH CONSIDERATION CREDITED TO AN ACCOUNT FOR YOUR BENEFIT UNDER THE DEFERRED COMPENSATION PLAN IF:

• YOU ELECTED TO DEFER, TO A DATE LATER THAN THE COMPLETION OF THE MERGER, THE RECEIPT OF COMMON STOCK WITH RESPECT TO ANY RSU AWARD YOU MAY RECEIVE IN 2016, OR

• YOU HAVE AN RSU AWARD FROM PRIOR YEARS THAT HAS BEEN DEFERRED TO A DATE LATER THAN THE COMPLETION OF THE MERGER.

IF YOU DO NOT COMPLETE THIS FORM AND YOU HAVE A DEFERRED AWARD, THE CASH CONSIDERATION WILL BE DEFERRED UNDER THE DEFERRED COMPENSATION PLAN AND CREDITED BY DEFAULT TO THE PRIME RATE ACCOUNT.

More information on the deferral of Stock-Based Awards under the 2012 Long-Term Incentive Plan is provided in Item 6 below.

4. Registration of Stock Certificates.

With respect to any shares of Common Stock that may be issued upon settlement of an RSU (and any associated dividend equivalents) granted to me under the 2012 LTIP, whether or not deferred under Item 1.b above, please register the stock certificates for those shares in the name set forth below, and provide a mailing or street address for such person:

4

5. Beneficiary Designation.

I designate the following Beneficiary (or Beneficiaries) to receive any benefits due under the Deferred Compensation Plan and/or the 2012 LTIP in the event of my death (specify full name, relationship and address):

Primary:

Contingent:

6. Material Terms Related to My Deferral of an Annual Stock-Based Retainer Award.

If I have elected in Item 1.b. above to defer settlement of my annual stock-based retainer award (and any associated dividend equivalents), I hereby acknowledge and agree that such deferral shall be subject to the following material terms, which have been approved by the Board of Directors:

a. This deferral election applies only to Common Stock underlying RSUs and/or performance shares or units granted under the 2012 LTIP.

b. Such award will be settled, to the extent vested, in accordance with my irrevocable deferral election set forth herein.

c. Subject to item i. below, to the extent vested, such retainer will be paid in a lump sum and solely in shares of Common Stock, and will not be credited to any of the options set forth on the Cash Retainer Deferral Allocation Form provided herewith.

d. If a dividend equivalent award has been granted with a deferred RSU or performance share or unit award, such dividend equivalent award shall also be deferred under the terms provided herein. Such dividends shall continue to be credited, when and as declared and paid by the Board of Directors, in additional shares or units of the same type and tenor as the stock-based award, based on the Fair Market Value (as defined in the 2012 LTIP) on the business day prior to the payment date of such dividend.

e. Upon payment of deferred awards, fractional shares shall be eliminated without compensation. Any fractional shares shall be rounded up to the next whole share if greater than or equal to a half-share, and rounded down to the next whole share if less than a half-share.

f. The award and deferral is subject to the other terms and conditions of the 2012 LTIP, as well as vesting, forfeiture, tax withholding and other legal requirements and conditions with respect to such award and deferral.

g. The Board of Directors retains full discretion over the terms of this deferral arrangement and may amend, suspend or terminate such arrangement at any time or from time to time, or impose additional or different restrictions, conditions or limitations on such deferral at any time as permitted or not prohibited by the terms of 2012 LTIP.

h. The terms of my deferral election are intended to comply, and should be interpreted consistently with, Section 409A of the Internal Revenue Code of 1986, as amended.

5

i. If the Merger is consummated during 2016, the cash consideration payable under the Merger Agreement with respect to RSUs which are the subject of my 2016 deferral election, as well as under any previously deferred RSU awards, will automatically be (1) deferred pursuant to the terms of the Deferred Compensation Plan and (2) credited to the accounts specified by me on the LTIP RSU Conversion Deferral Allocation Form, or if no such accounts have been specified, the prime rate account described therein.

[Signatures appear on following page]

6

IN WITNESS WHEREOF, the undersigned has executed this Agreement effective for all purposes as of the          day of                     , 2015.

Signature

Name (Please Print)

Acknowledged and confirmed this          day of                     , 2015

Pepco Holdings, Inc.

Signature

Name (Please Print)

7

Pepco Holdings, Inc.

CASH RETAINER DEFERRAL ALLOCATION FORM

Name:                                                                                                                                                             (the “Participant”)

                                     Last                                     First                                     Middle Initial

Social Security Number:             -            -            

I request that the Company credit my election of my 2016 cash deferred amounts in the Second Revised and Restated Executive and Director Deferred Compensation Plan to the options indicated below:

(Minimum per fund – 10%) (Please be sure your percentages total = 100%)

%	Money Market	%	High Yield Bond
%	Equity	%	Diversified Bond
%	Government Income	%	Stock Index
%	Value	%	Natural Resources
%	Conserv. Balanced	%	Flexible Managed
%	Global	%	Prudential Jennison
%	Small Cap Stock	%	Prime Rate
%	Am Cent. Value Fund	%	Janus Aspen Growth
%	MFS Emerg. Growth	%	TRP Int’l Stock
%	Pepco Holdings Phantom Shares

NOTE: If you have selected the Pepco Holdings Phantom Shares option above for 2016 or prior years, you must also indicate below an alternative election in the event that the Merger is completed during 2016. The alternative election must include at least one of the options indicated below.

8

Alternative Election for 2016 and Prior Year Deferrals to the Pepco Holdings Phantom Shares Account:

Please indicate below alternative allocation option(s) and percentage(s) for the total amount of amounts credited to the Pepco Holdings Phantom Shares option (including accruals thereon) for 2016 and prior years, which will take effect if and when the Merger is completed during 2016. The total percentages must total to 100%.

%	Money Market	%	High Yield Bond
%	Equity	%	Diversified Bond
%	Government Income	%	Stock Index
%	Value	%	Natural Resources
%	Conserv. Balanced	%	Flexible Managed
%	Global	%	Prudential Jennison
%	Small Cap Stock	%	Prime Rate
%	Am Cent. Value Fund	%	Janus Aspen Growth
%	MFS Emerg. Growth	%	TRP Int’l Stock

Participant

Signature

Date

9

Pepco Holdings, Inc.

LTIP RSU CONVERSION DEFERRAL ALLOCATION FORM

Name:                                                                                                                                                             (the “Participant”)

                                     Last                                     First                                     Middle Initial

Social Security Number:             -            -            

I wish to defer the receipt of common stock in connection with a 2016 RSU annual retainer award under the 2012 LTIP that I may receive as part of my annual retainer. I understand that my deferral election shall apply to the Cash Consideration payable, upon the completion of the Merger, with respect to such RSU award, which Cash Consideration shall be automatically deferred into the Deferred Compensation Plan. I request that the Company credit my election of such deferred amounts to the options indicated below:

I understand that, if the Merger is completed in 2016, these elections will also apply to Cash Consideration to be received in connection with any of my prior Deferred Awards.

(Minimum per fund – 10%) (Please be sure your percentages total = 100%)

%	Money Market	%	High Yield Bond
%	Equity	%	Diversified Bond
%	Government Income	%	Stock Index
%	Value	%	Natural Resources
%	Conserv. Balanced	%	Flexible Managed
%	Global	%	Prudential Jennison
%	Small Cap Stock	%	Prime Rate
%	Am Cent. Value Fund	%	Janus Aspen Growth
%	MFS Emerg. Growth	%	TRP Int’l Stock

NOTE: If you have elected to defer the settlement of your annual cash retainer and/or meeting fees, you do not need to complete this Form unless you are also deferring in whole or in part any 2016 RSU annual retainer award under the 2012 LTIP that you may receive, or you have a prior Deferred Award. However, you MUST complete the Cash Retainer Deferral Allocation Form on the previous page.

Participant

Signature

Date

10

EX-10.50

Exhibit 10.50

2016 Named Executive Officer Compensation Determinations and Other Compensation Information

The following is a description of certain compensation decisions made in 2016 by the Pepco Holdings, Inc. (PHI) Board of Directors (the Board) and/or the Compensation/Human Resources Committee of the Board (the Committee) with respect to compensation to be earned or payable in 2016 to persons set forth in the table below who are identified as named executive officers (each, a Named Executive Officer) in the Summary Compensation Table in PHI’s proxy statement for its 2015 Annual Meeting of Stockholders (the 2015 Proxy Statement).

2016 Annual Compensation Determinations

As to each Named Executive Officer, the compensation decisions consisted of (i) the establishment of annual base salary for 2016; (ii) the establishment of the Named Executive Officer’s 2016 annual cash incentive award opportunities under the Amended and Restated Annual Executive Incentive Compensation Plan (the EICP); and (iii) the grant of long-term restricted stock unit (RSU) awards under the Pepco Holdings, Inc. 2012 Long-Term Incentive Plan (the LTIP).

							LTIP Awards (2)
Named Executive Officer	Title	2016 Annual Base Salary		Target 2016 Annual Cash EICP Award Opportunity as a Percentage of Annual Base Salary (1)			TSR Performance-Based RSU Awards (# of RSUs) (3)						ROIC Performance-Based RSU Awards (# of RSUs) (4)						Time-Based RSU Award (# of RSUs)(5)
							Threshold		Target		Maximum		Threshold		Target		Maximum
Joseph M. Rigby	Chairman of the Board, President and Chief Executive Officer	$	1,015,000		100	%		8,129		32,519		65,038		16,259		32,519		65,038		32,519
David M. Velazquez	Executive Vice President	$	563,000		60	%		2,254		9,018		18,036		4,509		9,018		18,036		9,018
Frederick J. Boyle	Senior Vice President and Chief Financial Officer	$	528,000		60	%		2,114		8,458		16,916		4,229		8,458		16,916		8,458
Kevin C. Fitzgerald	Executive Vice President and General Counsel	$	563,000		60	%		2,254		9,018		18,036		4,509		9,018		18,036		9,018
John U. Huffman	President, Pepco Energy Services	$	406,000		60	%		1,300		5,203		10,406		2,601		5,203		10,406		5,203

(1) Each executive may earn a cash incentive award of up to 180% of his target award opportunity under the EICP as determined by the Committee, depending on the extent to which the pre-established performance goals are achieved. See “Amended and Restated Annual Executive Incentive Compensation Plan” below for a discussion of 2016 performance goals.

(2) The shares of PHI common stock, $.01 par value per share (Common Stock), underlying performance-based and time-based RSU awards in the aggregate had a fair market value on the date of grant equal to the following percentage of the Named Executive Officer’s 2016 annual base salary: 250% for Mr. Rigby, 125% for each of Messrs. Velazquez, Boyle and Fitzgerald, and 100% for Mr. Huffman.

(3) See “2016 LTIP Awards — Performance-Based RSU Awards – TSR-Based Awards” below for a description of the annual performance-based RSU awards granted under the LTIP.

(4) See “2016 LTIP Awards — Performance-Based RSU Awards – ROIC-Based Awards” below for a description of the annual performance-based RSU awards granted under the LTIP.

(5) See “2016 LTIP Awards — Time-Based RSU Awards” below for a description of the annual time-based RSU awards granted under the LTIP.

Amended and Restated Annual Executive Incentive Compensation Plan

Each of the executives listed in the table above is a participant in the EICP. The EICP is a cash-based incentive program designed to align executive compensation with the performance of PHI and its subsidiaries. Participants in the EICP for any calendar year may include any executive or employee of the Company or any subsidiary selected by the administrator, upon the recommendation of the Company’s chief executive officer, to participate in the EICP. On February 3, 2016, the Committee established the following performance goals to be used for the determination of 2016 EICP awards for each of the executives named below:

• Messrs. Rigby, Boyle and Fitzgerald: (1) adjusted net earnings per share, (2) electric system reliability, (3) customer satisfaction, (4) diversity, and (5) safety.

• Mr. Velazquez: (1) Power Delivery adjusted earnings per share, (2) core capital expenditures, compared to budget (excluding certain items), (3) operation and maintenance spending, compared to budget, (4) compliance results, (5) electric system reliability, (6) customer satisfaction, (7) diversity, and (8) safety.

• Mr. Huffman: (1) Pepco Energy Services’ adjusted net income (excluding power plants and retail energy), (2) performance of Pepco Energy Services’ energy savings performance contracting business, (3) performance of Pepco Energy Services’ undergrounding transmission and distribution business, (4) diversity, and (5) safety.

The payment of awards under the EICP to each of these PHI executives is also conditioned upon the achievement of specified threshold earnings requirements in order for an EICP award to be paid to the executive, regardless of the extent to which the other performance goals may be achieved.

2016 LTIP Awards

The Committee has granted awards of performance-based RSUs and time-based RSUs under the LTIP with respect to the 2016 to 2018 performance/retention cycle. Participants in the LTIP are key employees and officers of PHI and its subsidiaries selected by the Chairman of the Board of PHI and approved by the Committee, as well as non-management directors of PHI, including each of the persons listed in the tables above. Subject to the terms and conditions of each RSU award, each RSU represents a contractual right to receive one share of PHI common stock, $0.01 par value per share (“Common Stock”), at the end of the restriction or performance period. When a dividend is paid on the Common Stock, the award is credited with additional RSUs equal to the number of RSUs subject to such award multiplied by the per share cash dividend, divided by the then current market price of a share of Common Stock. Additional RSUs credited as dividend equivalents will vest only to the extent the underlying RSUs vest.

Performance-Based RSU Awards

Two performance-based RSU awards each account for one-third of an executive’s aggregate 2016 equity award under the LTIP. As described in detail below, the first performance-based RSU award utilizes PHI’s total shareholder return (TSR) relative to a PHI-selected group of peer companies (the 2016 Utility Peer Group) over a three-year period beginning on January 1, 2016 and ending on December 31, 2018, and the second performance-based RSU award utilizes return on invested capital (ROIC). If during the course of the three-year performance period, a significant event occurs, as determined in the discretion of the Committee, which the Committee expects to have a substantial effect on TSR or ROIC, as applicable, during the period, the Committee may revise such measures, other than with respect to awards to “covered employees” subject to Section 162(m) under the Internal Revenue Code. No adjustment shall be made that causes an award to fail to comply with Section 162(m) of the Code.

TSR-Based Awards

For awards based on TSR, depending on the extent to which the pre-established TSR performance goal has been met, an amount of each award ranging from 25% to 200% of the target number of RSUs (including dividend equivalents credited in the form of additional RSUs) subject to the award may vest. Vesting amounts related to threshold (representing 25% of the target award opportunity), target and maximum (representing 200% of the target award opportunity), with respect to each TSR performance-based award of RSUs for each executive, is shown in the table above.

ROIC-Based Awards

For awards based on ROIC, depending on the extent to which the pre-established ROIC performance goal has been met, an amount of each award ranging from 50% to 200% of the target number of RSUs (including dividend equivalents credited in the form of additional RSUs) subject to the award may vest. Vesting amounts related to threshold (representing 50% of the target award opportunity), target and maximum (representing 200% of the target award opportunity), with respect to each ROIC performance-based award of RSUs for each executive, is shown in the table above.

Time-Based RSU Awards

Each executive listed above has received a grant of time-based RSUs, which accounts for one-third of the executive’s aggregate 2016 equity award under the LTIP. Subject to certain exceptions provided for in the LTIP or in the award agreement (or, with respect to Mr. Rigby, his employment agreement), time-based RSUs are subject to forfeiture if the employment of the executive terminates prior to the third anniversary of the date of grant.

Performance Goals for 2015 RSU Awards Pursuant to Employment Agreement

In February 2015, the Compensation Committee will determine the satisfaction of performance goals associated with Mr. Fitzgerald’s 2015 performance-based RSU award under his employment agreement and set forth below.

Mr. Fitzgerald’s Performance Criteria	Weight (%)
Achievement of state-mandated reliability standards		40
Residential utility customer satisfaction		40
Achievement of all key regulatory dates related to the 2015 project plan in connection with the Company’s DC Power Line Undergrounding Initiative		20

EX-12.1

Exhibit 12.1 Statements Re: Computation of Ratios

PEPCO HOLDINGS, INC.

	For the Year Ended December 31,
	2015		2014		2013			2012			2011
	(millions of dollars)
Earnings
Net income from continuing operations	$	318	$	242	$	110		$	218		$	222
Preferred stock dividend		—		—		—			—			—
(Income) loss from equity investees		—		—		(2	)		(1	)		3
Minority interest loss		—		—		—			—			—
Income tax expense related to continuing operations		129		138		319			103			114
Pre-tax income for common stock		447		380		427			320			339
Add: Fixed charges*		312		300		301			286			275
Add: Distributed income of equity investees		—		—		—			—			—
Subtract: Interest capitalized		—		—		—			—			—
Subtract: Pre-tax preferred stock dividend requirement		—		—		—			—			—
Earnings	$	759	$	680	$	728		$	606		$	614
*Fixed Charges Interest on long-term debt	$	274	$	264	$	265		$	249		$	239
Interest capitalized		—		—		—			—			—
Other interest		—		—		—			—			—
Amortization of debt discount, premium, and expense		14		12		14			16			14
Interest component of rentals		24		24		22			21			22
Pre-tax preferred stock dividend requirement		—		—		—			—			—
Fixed charges	$	312	$	300	$	301		$	286		$	275
Ratio of earnings to fixed charges (a)		2.43		2.27		2.42			2.12			2.23

(a) Pepco Holdings, Inc. issued certain preferred equity securities during 2015 and 2014 that are excluded from equity since the securities contain conditions for redemption that are not solely within the control of PHI. The cumulative and unpaid dividends associated with the preferred equity securities, which were immaterial for the years ended December 31, 2015 and 2014, are included in fixed charges as a component of interest on long-term debt. Accordingly, the ratio of earnings to fixed charges is equal to the ratio of earnings to combined fixed charges and preferred stock dividends.

EX-12.2

Exhibit 12.2 Statements Re: Computation of Ratios

POTOMAC ELECTRIC POWER COMPANY

	For the Year Ended December 31,
	2015		2014		2013		2012		2011
	(millions of dollars)
Earnings
Net income for common stock	$	187	$	171	$	150	$	126	$	99
Preferred stock dividend		—		—		—		—		—
(Income) loss from equity investees		—		—		—		—		—
Minority interest loss		—		—		—		—		—
Income tax expense		98		92		79		48		36
Pre-tax income for common stock		285		263		229		174		135
Add: Fixed charges*		137		128		121		113		111
Add: Distributed income of equity investees		—		—		—		—		—
Subtract: Interest capitalized		—		—		—		—		—
Subtract: Pre-tax preferred stock dividend requirement		—		—		—		—		—
Earnings	$	422	$	391	$	350	$	287	$	246
*Fixed Charges Interest on long-term debt	$	125	$	116	$	109	$	101	$	97
Interest capitalized		—		—		—		—		—
Other interest		—		—		—		—		—
Amortization of debt discount, premium, and expense		5		5		5		5		4
Interest component of rentals		7		7		7		7		10
Pre-tax preferred stock dividend requirement		—		—		—		—		—
Fixed charges	$	137	$	128	$	121	$	113	$	111
Ratio of earnings to fixed charges (a)		3.08		3.05		2.89		2.54		2.22

(a) Pepco has no preferred equity securities outstanding, therefore the ratio of earnings to fixed charges is equal to the ratio of earnings to combined fixed charges and preferred stock dividends.

EX-12.3

Exhibit 12.3 Statements Re: Computation of Ratios

DELMARVA POWER & LIGHT COMPANY

	For the Year Ended December 31,
	2015		2014		2013		2012		2011
	(millions of dollars)
Earnings
Net income for common stock	$	76	$	104	$	89	$	73	$	71
Preferred stock dividend		—		—		—		—		—
(Income) loss from equity investees		—		—		—		—		—
Minority interest loss		—		—		—		—		—
Income tax expense		49		65		56		44		42
Pre-tax income for common stock		125		169		145		117		113
Add: Fixed charges*		54		53		55		52		49
Add: Distributed income of equity investees		—		—		—		—		—
Subtract: Interest capitalized		—		—		—		—		—
Subtract: Pre-tax preferred stock dividend requirement		—		—		—		—		—
Earnings	$	179	$	222	$	200	$	169	$	162
*Fixed Charges Interest on long-term debt	$	48	$	46	$	49	$	45	$	42
Interest capitalized		—		—		—		—		—
Other interest		—		—		—		—		—
Amortization of debt discount, premium, and expense		2		3		3		4		4
Interest component of rentals		4		4		3		3		3
Pre-tax preferred stock dividend requirement		—		—		—		—		—
Fixed charges	$	54	$	53	$	55	$	52	$	49
Ratio of earnings to fixed charges (a)		3.31		4.19		3.64		3.25		3.31

(a) DPL has no preferred equity securities outstanding, therefore the ratio of earnings to fixed charges is equal to the ratio of earnings to combined fixed charges and preferred stock dividends.

EX-12.4

Exhibit 12.4 Statements Re: Computation of Ratios

ATLANTIC CITY ELECTRIC COMPANY

	For the Year Ended December 31,
	2015		2014		2013		2012		2011
	(millions of dollars)
Earnings
Net income for common stock	$	38	$	45	$	50	$	35	$	39
Preferred stock dividend		—		—		—		—		—
(Income) loss from equity investees		—		—		—		—		—
Minority interest loss		—		—		—		—		—
Income tax expense		31		28		19		18		33
Pre-tax income for common stock		69		73		69		53		72
Add: Fixed charges*		69		68		72		75		74
Add: Distributed income of equity investees		—		—		—		—		—
Subtract: Interest capitalized		—		—		—		—		—
Subtract: Pre-tax preferred stock dividend requirement		—		—		—		—		—
Earnings	$	138	$	141	$	141	$	128	$	146
*Fixed Charges Interest on long-term debt	$	62	$	61	$	65	$	69	$	69
Interest capitalized		—		—		—		—		—
Other interest		—		—		—		—		—
Amortization of debt discount, premium, and expense		3		3		3		2		2
Interest component of rentals		4		4		4		4		3
Pre-tax preferred stock dividend requirement		—		—		—		—		—
Fixed charges	$	69	$	68	$	72	$	75	$	74
Ratio of earnings to fixed charges (a)		2.00		2.07		1.96		1.71		1.97

(a) ACE has no preferred equity securities outstanding, therefore the ratio of earnings to fixed charges is equal to the ratio of earnings to combined fixed charges and preferred stock dividends.

EX-21

Exhibit 21 Subsidiaries of the Registrants*

Name of Company	Jurisdiction of Incorporation or Organization
Pepco Holdings, Inc.	DE
Potomac Electric Power Company	DC and VA
POM Holdings, Inc.	DE
Pepco Energy Services, Inc.	DE
Conectiv Thermal Systems, Inc. (d/b/a Pepco Energy Services)	DE
ATS Operating Services, Inc.	DE
Atlantic Jersey Thermal Systems, Inc.	DE
Thermal Energy Limited Partnership I	DE
Potomac Power Resources, LLC	DE
Pepco Government Services LLC	DE
Pepco Energy Solutions LLC	DE
Pepco Energy Cogeneration LLC	DE
Fauquier Landfill Gas, L.L.C.	DE
Distributed Generation Partners, LLC	DE
Bethlehem Renewable Energy, LLC	DE
Rolling Hills Landfill Gas, LLC	DE
Blue Ridge Renewable Energy, LLC	DE
Eastern Landfill Gas, LLC	DE
Pepco Building Services Inc.	DE
Severn Construction Services, L.L.C.	DE
W.A. Chester, L.L.C.	DE
W.A. Chester Corporation	DE
Chester Transmission Construction Canada, Inc.	Canada
Potomac Capital Investment Corporation	DE
PCI Energy Corporation	DE
AMP Funding, L.L.C.	DE
RAMP Investments, L.L.C.	DE
PCI Air Management Partners, L.L.C.	DE
PCI Ever, Inc.	DE
Kinetic Ventures VI, L.L.C.	DE
Kinetic Ventures VII, L.L.C.	DE
Friendly Skies, Inc.	Virgin Islands
PCI Air Management Corporation, a Nevada Corporation	NV
PCI-BT Investing, L.L.C.	DE
American Energy Corporation	DE
PCI Engine Trading Ltd.	Bermuda
Potomac Delaware Leasing Corporation	DE
Potomac Leasing Associates, L.P.	DE
PHI Service Company	DE
Conectiv, LLC	DE
Delmarva Power & Light Company (d/b/a Delmarva Power)	DE and VA
Conectiv Properties and Investments, Inc.	DE
Atlantic City Electric Company (d/b/a Atlantic City Electric)	NJ
Atlantic City Electric Transition Funding LLC	DE
Conectiv Solutions LLC	DE
Blacklight Power, Inc.	DE
Millennium Account Services, LLC	DE
Conectiv Services, Inc.	DE
ATE Investment, Inc.	DE
Enertech Capital Partners II L.P.	DE

Name of Company	Jurisdiction of Incorporation or Organization
Conectiv Communications, Inc.	DE
Atlantic Generation, Inc.	NJ
Project Finance Fund III, L.P.	DE
Vineland Ltd., Inc.	DE
Vineland Cogeneration Limited Partnership	DE
Vineland General, Inc.	DE
Atlantic Southern Properties, Inc.	NJ
Technology Leaders II, L.P.	DE
Delaware Operating Services Company, LLC	DE
Conectiv Energy Supply, Inc. (d/b/a Conectiv Energy and Petron Oil)	DE
Conectiv North East, LLC	DE

* As of December 31, 2015.

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (Nos. 333-190917 and 333-190923) and the Registration Statements on Form S-8 (Nos. 333-96675, 333-181505 and 333-189291) of Pepco Holdings, Inc. of our report dated February 18, 2016, for Pepco Holdings, Inc. relating to the financial statements, financial statement schedules and the effectiveness of internal control over financial reporting, which appear in this Form 10-K.

/s/ PricewaterhouseCoopers LLP

Washington, D.C.

February 18, 2016

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-190917-03) of Potomac Electric Power Company of our report dated February 18, 2016, for Potomac Electric Power Company relating to the financial statements and financial statement schedule, which appear in this Form 10-K.

/s/ PricewaterhouseCoopers LLP

Washington, D.C.

February 18, 2016

EX-23.3

Exhibit 23.3

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-190917-02) of Delmarva Power & Light Company of our report dated February 18, 2016, for Delmarva Power & Light Company relating to the financial statements and financial statement schedule, which appear in this Form 10-K.

/s/ PricewaterhouseCoopers LLP

Washington, D.C.

February 18, 2016

EX-23.4

Exhibit 23.4

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-190917-01) of Atlantic City Electric Company of our report dated February 18, 2016, for Atlantic City Electric Company relating to the financial statements and financial statement schedule, which appear in this Form 10-K.

/s/ PricewaterhouseCoopers LLP

Washington, D.C.

February 18, 2016

EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, Joseph M. Rigby, certify that:

1. I have reviewed this report on Form 10-K of Pepco Holdings, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 18, 2016	/s/ JOSEPH M. RIGBY
	Joseph M. Rigby Chairman of the Board, President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATIONS

I, Frederick J. Boyle, certify that:

1. I have reviewed this report on Form 10-K of Pepco Holdings, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 18, 2016	/s/ FRED BOYLE
	Frederick J. Boyle Senior Vice President and Chief Financial Officer

EX-31.3

Exhibit 31.3

CERTIFICATIONS

I, David M. Velazquez, certify that:

1. I have reviewed this report on Form 10-K of Potomac Electric Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 18, 2016	/s/ DAVID M. VELAZQUEZ
	David M. Velazquez President and Chief Executive Officer

EX-31.4

Exhibit 31.4

CERTIFICATIONS

I, Frederick J. Boyle, certify that:

1. I have reviewed this report on Form 10-K of Potomac Electric Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 18, 2016	/s/ FRED BOYLE
	Frederick J. Boyle Senior Vice President and Chief Financial Officer

EX-31.5

Exhibit 31.5

CERTIFICATIONS

I, David M. Velazquez, certify that:

1. I have reviewed this report on Form 10-K of Delmarva Power & Light Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 18, 2016	/s/ DAVID M. VELAZQUEZ
	David M. Velazquez President and Chief Executive Officer

EX-31.6

Exhibit 31.6

CERTIFICATIONS

I, Frederick J. Boyle, certify that:

1. I have reviewed this report on Form 10-K of Delmarva Power & Light Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 18, 2016	/s/ FRED BOYLE
	Frederick J. Boyle Senior Vice President and Chief Financial Officer

EX-31.7

Exhibit 31.7

CERTIFICATIONS

I, David M. Velazquez, certify that:

1. I have reviewed this report on Form 10-K of Atlantic City Electric Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 18, 2016	/s/ DAVID M. VELAZQUEZ
	David M. Velazquez President and Chief Executive Officer

EX-31.8

Exhibit 31.8

CERTIFICATIONS

I, Frederick J. Boyle, certify that:

1. I have reviewed this report on Form 10-K of Atlantic City Electric Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 18, 2016	/s/ FRED BOYLE
	Frederick J. Boyle Chief Financial Officer

EX-32.1

Exhibit 32.1

Certificate of Chief Executive Officer and Chief Financial Officer

of

Pepco Holdings, Inc.

(pursuant to 18 U.S.C. Section 1350)

I, Joseph M. Rigby, and I, Frederick J. Boyle, certify that, to the best of my knowledge, (i) the Report on Form 10-K of Pepco Holdings, Inc. for the year ended December 31, 2015 filed with the Securities and Exchange Commission on the date hereof fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Pepco Holdings, Inc.

February 18, 2016	/s/ JOSEPH M. RIGBY
	Joseph M. Rigby Chairman of the Board, President and Chief Executive Officer
February 18, 2016	/s/ FRED BOYLE
	Frederick J. Boyle Senior Vice President and Chief Financial Officer

A signed original of this written statement required by Section 906 has been provided to Pepco Holdings, Inc. and will be retained by Pepco Holdings, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

Certificate of Chief Executive Officer and Chief Financial Officer

of

Potomac Electric Power Company

(pursuant to 18 U.S.C. Section 1350)

I, David M. Velazquez, and I, Frederick J. Boyle, certify that, to the best of my knowledge, (i) the Report on Form 10-K of Potomac Electric Power Company for the year ended December 31, 2015 filed with the Securities and Exchange Commission on the date hereof fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Potomac Electric Power Company.

February 18, 2016	/s/ DAVID M. VELAZQUEZ
	David M. Velazquez President and Chief Executive Officer
February 18, 2016	/s/ FRED BOYLE
	Frederick J. Boyle Senior Vice President and Chief Financial Officer

A signed original of this written statement required by Section 906 has been provided to Potomac Electric Power Company and will be retained by Potomac Electric Power Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.3

Exhibit 32.3

Certificate of Chief Executive Officer and Chief Financial Officer

of

Delmarva Power & Light Company

(pursuant to 18 U.S.C. Section 1350)

I, David M. Velazquez, and I, Frederick J. Boyle, certify that, to the best of my knowledge, (i) the Report on Form 10-K of Delmarva Power & Light Company for the year ended December 31, 2015 filed with the Securities and Exchange Commission on the date hereof fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Delmarva Power & Light Company.

February 18, 2016	/s/ DAVID M. VELAZQUEZ
	David M. Velazquez President and Chief Executive Officer
February 18, 2016	/s/ FRED BOYLE
	Frederick J. Boyle Senior Vice President and Chief Financial Officer

A signed original of this written statement required by Section 906 has been provided to Delmarva Power & Light Company and will be retained by Delmarva Power & Light Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.4

Exhibit 32.4

Certificate of Chief Executive Officer and Chief Financial Officer

of

Atlantic City Electric Company

(pursuant to 18 U.S.C. Section 1350)

I, David M. Velazquez, and I, Frederick J. Boyle, certify that, to the best of my knowledge, (i) the Report on Form 10-K of Atlantic City Electric Company for the year ended December 31, 2015 filed with the Securities and Exchange Commission on the date hereof fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Atlantic City Electric Company.

February 18, 2016	/s/ DAVID M. VELAZQUEZ
	David M. Velazquez President and Chief Executive Officer
February 18, 2016	/s/ FRED BOYLE
	Frederick J. Boyle Chief Financial Officer

A signed original of this written statement required by Section 906 has been provided to Atlantic City Electric Company and will be retained by Atlantic City Electric Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-99

Exhibit 99

PEPCO HOLDINGS, INC.

AUDIT COMMITTEE

Policy on the Approval of Services

Provided By the Independent Auditor

I. Overview

Under the federal securities laws and the rules of the Securities and Exchange Commission (the “SEC”), the annual consolidated financial statements of Pepco Holdings, Inc. (the “Company”) and each of its subsidiaries that has a reporting obligation (a “Reporting Company”) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), must be audited by an “independent” public accountant. Likewise, the quarterly financial statements of the Company and each Reporting Company must be reviewed by an “independent” public accountant.

Under SEC regulations, a public accountant is not “independent” if it provides certain specified non-audit services to an audit client. In addition, a public accountant will not qualify as “independent” unless (i) before the accountant is engaged to provide audit or non-audit services, the engagement is approved by the public company’s audit committee or (ii) the engagement to provide audit or non-audit services is pursuant to pre-approved policies and procedures established by the audit committee.

Under the Audit Committee Charter, the Audit Committee of the Company has sole authority (i) to retain and terminate the Company’s independent auditors, (ii) to pre-approve all audit engagement fees and terms and (iii) to pre-approve all significant audit-related relationships with the independent auditor. This Policy sets forth the policies and procedures adopted by the Audit Committee with respect to the engagement of the Company’s independent auditor to provide audit and non-audit services to the Company and its subsidiaries (as defined by Rule 1-02 (x) of SEC Regulation S-X).

The Audit Committee also serves as the audit committee for each subsidiary of the Company that is a Reporting Company for the purpose of approving audit and non-audit services to be provided by the independent auditor(s) of such Reporting Companies. In this capacity, the Audit Committee has determined that this Policy also shall govern the engagement of the independent auditor for each such Reporting Company.

II. Statement of Principles

The Audit Committee recognizes the importance of maintaining the independence of its external auditor both in fact and appearance. In order to ensure that the independence of the Company’s external auditor is not, in the judgment of the Audit Committee, impaired by any other services that the external auditor may provide to the Company and its subsidiaries:

• The Audit Committee shall approve in advance all services — both audit and permitted non-audit services — provided to the Company or any of its subsidiaries by the Company’s independent auditor in accordance with the procedures set forth in this Policy.

• The Audit Committee shall not engage the Company’s independent auditor to provide to the Company or any of its subsidiaries any non-audit services that are unlawful under Section 10A of the Exchange Act or that would impair the independence of the Company’s independent auditor under the standards set forth in Rule 2-01 of SEC Regulation S-X (“Prohibited Non-Audit Services”).

III. Approval of Annual Audit Services

The annual audit services provided to the Company and its subsidiaries by the Company’s independent auditor shall consist of:

• The audit of the annual consolidated financial statements of the Company and each other Reporting Company and the other procedures required to be performed by the independent auditor to be able to form an opinion on the financial statements.

• Review of the quarterly consolidated financial statements of the Company and each Reporting Company.

• The attestation engagement for the independent auditor’s report on management’s statement on the effectiveness of the Company’s internal control over financial reports.

• Services associated with SEC registration statements, periodic reports and other documents filed with the SEC or issued in connection with securities offerings, including consents and comfort letters provided to underwriters, reviews of registration statements and prospectuses, and assistance in responding to SEC comment letters.

• All such audit services must be approved annually by the Audit Committee following a review by the Audit Committee of the proposed terms and scope of the engagement and the projected fees. Any subsequent change of a material nature in the terms, scope or fees associated with such annual audit services shall be approved in advance by the Audit Committee.

• Any additional audit services may be pre-approved annually at the Annual Meeting at which the annual audit services are approved. If not pre-approved, each additional annual audit service must be approved by the Audit Committee in advance on a case-by-case basis.

IV. Approval of Audit-Related Services

Audit-related services consist of assurance and related services that are reasonably related to the performance of the audit or review of the financial statements of the Company and each Reporting Company, other than the annual audit services described in Section III above. Audit-related services may include, but are not limited to:

• Employee benefit plan audits.

• Due diligence related to mergers and acquisitions.

• Accounting consultations and audits in connection with acquisitions.

• Internal control reviews.

• Attest services related to financial reporting that are not required by statute or regulation.

Audit-related services may be pre-approved annually at the meeting of the Audit Committee at which the annual audit services are approved. If not pre-approved, each audit-related service must be approved by the Audit Committee in advance on a case-by-case basis.

V. Approval of Tax Services

Tax services consist of professional services rendered by the independent auditor to the Company or any of its subsidiaries for tax compliance, tax advice and tax planning. Tax services may be pre-approved annually at the meeting of the Audit Committee at which the annual audit services are approved. If not pre-approved, each tax service must be approved by the Audit Committee in advance on a case-by-case basis.

VI. Approval of All Other Services

Any other services to be provided by the Company’s independent auditor, other than Prohibited Non-Audit Services, may be pre-approved annually at the meeting of the Audit Committee at which the annual audit services are approved. If not pre-approved, each such other service must be approved by the Audit Committee in advance on a case-by-case basis.

VII. Procedures

At the meeting of the Audit Committee to select the independent auditor for the Company and each of the Reporting Companies, the Chief Financial Officer shall submit to the Audit Committee a list of the additional audit services, audit-related services, tax services and other services, if any, that the Company and the Related Companies wish to have pre-approved for the ensuing year. The list shall be accompanied by:

• a written description (which may consist of or include a description furnished to the Company by the independent auditor) of the services to be provided in detail sufficient to enable the Audit Committee to make an informed decision with regard to each proposed service, and, to the extent determinable, an estimate provided by the independent auditor of the fees for each of the services; and

• confirmation of the independent auditor that (i) it would not be unlawful under Section 10A of the Exchange Act for the independent auditor to provide the listed non-audit services to the Company or any of its subsidiaries and (ii) none of the services, if provided by the independent auditor to the Company or any of its subsidiaries, would impair the independence of the auditor under the standards set forth in Rule 2-01 of SEC Regulation S-X.

If a type of non-audit service is pre-approved by the Audit Committee, and the Company or any of its subsidiaries subsequently engages the independent auditor to provide that service, the Company’s Chief Financial Officer shall report the engagement to the Audit Committee at its next regularly scheduled meeting.

VIII. Delegation

The Audit Committee hereby delegates to the Chairman of the Audit Committee the authority to approve, upon the receipt of the documentation referred to in Section VII above, on a case-by-case basis any non-audit service less than $1,000,000 of the types referred to in Sections IV, V and VI above (i.e. an audit-related, tax or other service) at any time other than at a meeting of the Audit Committee. The Chairman shall report any services so approved to the Audit Committee at its next regularly scheduled meeting. In no circumstances shall the responsibilities of the Audit Committee under this Policy be delegated to the management of the Company or any of its subsidiaries.

XML

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Feb. 05, 2016	Jun. 30, 2015
Document Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	FY
Trading Symbol	POM
Entity Registrant Name	PEPCO HOLDINGS INC
Entity Central Index Key	0001135971
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		254,340,724
Entity Public Float			$ 6,802.6
Potomac Electric Power Co [Member]
Document Information [Line Items]
Entity Registrant Name	POTOMAC ELECTRIC POWER CO
Entity Central Index Key	0000079732
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		100
Entity Public Float			0.0
Delmarva Power & Light Co/De [Member]
Document Information [Line Items]
Entity Registrant Name	DELMARVA POWER & LIGHT CO /DE/
Entity Central Index Key	0000027879
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		1,000
Entity Public Float			0.0
Atlantic City Electric Co [Member]
Document Information [Line Items]
Entity Registrant Name	ATLANTIC CITY ELECTRIC CO
Entity Central Index Key	0000008192
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		8,546,017
Entity Public Float			$ 0.0

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Consolidated Statements of Income (Loss) - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating Revenue	$ 5,023	$ 4,878	$ 4,666
Operating Expenses
Fuel and purchased energy	2,097	2,080	2,070
Other services cost of sales	175	207	146
Other operation and maintenance	1,016	924	851
Depreciation and amortization	651	549	473
Other taxes	427	413	428
Deferred electric service costs	30	20	26
Impairment losses		81	4
Gains on sales of land	(46)
Total Operating Expenses	4,350	4,274	3,998
Operating Income (Loss)	673	604	668
Other Income (Expenses)
Interest expense	(280)	(268)	(273)
Gain from equity investments			2
Other income	54	44	32
Total Other Income (Expenses)	(226)	(224)	(239)
Income from Continuing Operations Before Income Tax Expense	447	380	429
Income Tax Expense Related to Continuing Operations	129	138	319
Net Income (Loss) from Continuing Operations	318	242	110
Income (Loss) from Discontinued Operations, net of Income Taxes	9		(322)
Net Income (Loss)	$ 327	$ 242	$ (212)
Basic Share Information
Weighted average shares outstanding - Basic (millions)	253	251	246
Earnings per share of common stock from Continuing Operations - Basic	$ 1.25	$ 0.96	$ 0.45
Earnings (loss) per share of common stock from Discontinued Operations - Basic	0.04		(1.31)
Earnings (loss) per share - Basic	$ 1.29	$ 0.96	$ (0.86)
Diluted Share Information
Weighted average shares outstanding - Diluted (millions)	254	252	246
Earnings per share of common stock from Continuing Operations - Diluted	$ 1.25	$ 0.96	$ 0.45
Earnings (loss) per share of common stock from Discontinued Operations - Diluted	0.04		(1.31)
Earnings (loss) per share - Diluted	$ 1.29	$ 0.96	$ (0.86)
Potomac Electric Power Co [Member]
Operating Revenue
Total Operating Revenue	$ 2,189	$ 2,101	$ 2,026
Operating Revenue	2,189	2,101	2,026
Operating Expenses
Fuel and purchased energy	763	771	750
Other operation and maintenance	441	390	391
Depreciation and amortization	277	229	196
Other taxes	369	363	368
Gains on sales of land	(46)
Total Operating Expenses	1,804	1,753	1,705
Operating Income (Loss)	385	348	321
Other Income (Expenses)
Interest expense	(123)	(115)	(110)
Other income	23	30	18
Total Other Income (Expenses)	(100)	(85)	(92)
Income from Continuing Operations Before Income Tax Expense	285	263	229
Income Tax Expense Related to Continuing Operations	98	92	79
Net Income (Loss)	187	171	150
Delmarva Power & Light Co/De [Member]
Operating Revenue
Electric	1,153	1,099	1,053
Natural gas	165	194	191
Total Operating Revenue	1,318	1,293	1,244
Operating Revenue	1,318	1,293	1,244
Operating Expenses
Fuel and purchased energy	568	546	552
Gas purchased	79	104	109
Other operation and maintenance	306	269	251
Depreciation and amortization	153	125	107
Other taxes	47	42	40
Total Operating Expenses	1,153	1,086	1,059
Operating Income (Loss)	165	207	185
Other Income (Expenses)
Interest expense	(50)	(48)	(50)
Other income	10	10	10
Total Other Income (Expenses)	(40)	(38)	(40)
Income from Continuing Operations Before Income Tax Expense	125	169	145
Income Tax Expense Related to Continuing Operations	49	65	56
Net Income (Loss)	76	104	89
Atlantic City Electric Co [Member]
Operating Revenue
Total Operating Revenue	1,298	1,213	1,202
Operating Revenue	1,298	1,213	1,202
Operating Expenses
Fuel and purchased energy	685	653	660
Other operation and maintenance	272	246	230
Depreciation and amortization	176	157	136
Other taxes	5	2	14
Deferred electric service costs	30	20	26
Total Operating Expenses	1,168	1,078	1,066
Operating Income (Loss)	130	135	136
Other Income (Expenses)
Interest expense	(64)	(63)	(68)
Other income	3	1	1
Total Other Income (Expenses)	(61)	(62)	(67)
Income from Continuing Operations Before Income Tax Expense	69	73	69
Income Tax Expense Related to Continuing Operations	31	28	19
Net Income (Loss)	$ 38	$ 45	$ 50

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Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement of Comprehensive Income [Abstract]
Net Income (Loss)	$ 327	$ 242	$ (212)
Other Comprehensive Income (Loss) from Continuing Operations
Losses on treasury rate locks reclassified into income	1	1	1
Pension and other postretirement benefit plans	15	(20)	13
Other comprehensive income (loss), before income taxes	16	(19)	14
Income tax expense (benefit) related to other comprehensive income	6	(7)	6
Other comprehensive income (loss) from continuing operations, net of income taxes	10	(12)	8
Other Comprehensive Income from Discontinued Operations, Net of Income Taxes			6
Comprehensive Income (Loss)	$ 337	$ 230	$ (198)

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Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
CURRENT ASSETS
Cash and cash equivalents	$ 25	$ 14
Restricted cash equivalents	14	25
Accounts receivable, less allowance for uncollectible accounts	839	782
Inventories	141	141
Income taxes and related accrued interest receivable	111	9
Prepaid expenses and other	72	63
Total Current Assets	1,202	1,034
OTHER ASSETS
Goodwill	1,406	1,407
Regulatory assets	2,246	2,409
Deferred income tax assets, net	15	17
Income taxes and related accrued interest receivable	6	81
Restricted cash equivalents	18	14
Other	129	121
Total Other Assets	3,820	4,049
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment	16,218	15,465
Accumulated depreciation	(4,914)	(4,959)
Net Property, Plant and Equipment	11,304	10,506
TOTAL ASSETS	16,326	15,589
CURRENT LIABILITIES
Short-term debt	1,063	729
Current portion of long-term debt and project funding	341	431
Current portion of long-term debt	294	366
Accounts payable	175	174
Accrued liabilities	322	313
Capital lease obligations due within one year	11	10
Taxes accrued	51	41
Interest accrued	49	47
Liabilities and accrued interest related to uncertain tax positions	9	6
Other	287	305
Total Current Liabilities	2,308	2,056
DEFERRED CREDITS
Regulatory liabilities	308	343
Deferred income tax liabilities, net	3,393	3,242
Investment tax credits	15	16
Pension benefit obligation	466	396
Other postretirement benefit obligations	215	265
Other	202	195
Total Deferred Credits	4,599	4,457
OTHER LONG-TERM LIABILITIES
Long-term debt	4,656	4,397
Transition bonds issued by ACE Funding	124	170
Long-term project funding	4	8
Capital lease obligations	39	50
Total Other Long-Term Liabilities	$ 4,823	$ 4,625
COMMITMENTS AND CONTINGENCIES
PREFERRED STOCK
Series A preferred stock, $.01 par value, 18,000 shares authorized, 18,000 and 12,600 shares outstanding, respectively	$ 183	$ 129
EQUITY
Common stock	3	3
Premium on stock and other capital contributions	3,829	3,800
Accumulated other comprehensive loss	(36)	(46)
Retained earnings	617	565
Total Equity	4,413	4,322
TOTAL LIABILITIES AND EQUITY	16,326	15,589
Potomac Electric Power Co [Member]
CURRENT ASSETS
Cash and cash equivalents	5	6
Restricted cash equivalents	2	5
Accounts receivable, less allowance for uncollectible accounts	346	315
Inventories	67	62
Income taxes and related accrued interest receivable	170	94
Prepaid expenses and other	20	21
Total Current Assets	610	503
OTHER ASSETS
Regulatory assets	720	697
Prepaid pension expense	291	316
Investment in trust	27	34
Income taxes and related accrued interest receivable	3	30
Other	42	43
Total Other Assets	1,083	1,120
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment	8,091	7,764
Accumulated depreciation	(2,799)	(2,816)
Net Property, Plant and Equipment	5,292	4,948
TOTAL ASSETS	6,985	6,571
CURRENT LIABILITIES
Short-term debt	64	104
Current portion of long-term debt and project funding		12
Accounts payable	87	94
Accrued liabilities	101	91
Accounts payable due to associated companies	30	30
Capital lease obligations due within one year	11	10
Taxes accrued	37	32
Interest accrued	22	19
Liabilities and accrued interest related to uncertain tax positions	3
Customer deposits	46	44
Other	68	93
Total Current Liabilities	469	529
DEFERRED CREDITS
Regulatory liabilities	92	104
Deferred income tax liabilities, net	1,721	1,579
Investment tax credits	2	2
Other postretirement benefit obligations	49	57
Other	72	67
Total Deferred Credits	1,936	1,809
OTHER LONG-TERM LIABILITIES
Long-term debt	2,301	2,096
Capital lease obligations	39	50
Total Other Long-Term Liabilities	$ 2,340	$ 2,146
COMMITMENTS AND CONTINGENCIES
EQUITY
Premium on stock and other capital contributions	$ 1,122	$ 1,010
Retained earnings	1,118	1,077
Total Equity	2,240	2,087
TOTAL LIABILITIES AND EQUITY	6,985	6,571
Delmarva Power & Light Co/De [Member]
CURRENT ASSETS
Cash and cash equivalents	5	4
Restricted cash equivalents		5
Accounts receivable, less allowance for uncollectible accounts	203	193
Inventories	50	55
Income taxes and related accrued interest receivable	58	34
Prepaid expenses and other	10	12
Total Current Assets	326	303
OTHER ASSETS
Goodwill	8	8
Regulatory assets	308	356
Prepaid pension expense	205	220
Income taxes and related accrued interest receivable		4
Other	1	4
Total Other Assets	522	592
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment	4,209	3,946
Accumulated depreciation	(1,046)	(1,021)
Net Property, Plant and Equipment	3,163	2,925
TOTAL ASSETS	4,011	3,820
CURRENT LIABILITIES
Short-term debt	210	211
Current portion of long-term debt	100	100
Accounts payable	41	39
Accrued liabilities	76	74
Accounts payable due to associated companies	20	17
Taxes accrued	3	3
Interest accrued	7	7
Customer deposits	31	24
Other	39	41
Total Current Liabilities	527	516
DEFERRED CREDITS
Regulatory liabilities	189	225
Deferred income tax liabilities, net	941	878
Investment tax credits	4	4
Other postretirement benefit obligations	19	21
Other	33	35
Total Deferred Credits	1,186	1,163
OTHER LONG-TERM LIABILITIES
Long-term debt	$ 1,061	$ 963
COMMITMENTS AND CONTINGENCIES
EQUITY
Premium on stock and other capital contributions	$ 612	$ 537
Retained earnings	625	641
Total Equity	1,237	1,178
TOTAL LIABILITIES AND EQUITY	4,011	3,820
Atlantic City Electric Co [Member]
CURRENT ASSETS
Cash and cash equivalents	3	2
Restricted cash equivalents	12	10
Accounts receivable, less allowance for uncollectible accounts	211	167
Inventories	23	23
Income taxes and related accrued interest receivable	199	151
Prepaid expenses and other	1	3
Total Current Assets	449	356
OTHER ASSETS
Regulatory assets	322	427
Prepaid pension expense	83	96
Income taxes and related accrued interest receivable		34
Restricted cash equivalents	18	14
Other	4	5
Total Other Assets	427	576
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment	3,305	3,073
Accumulated depreciation	(764)	(760)
Net Property, Plant and Equipment	2,541	2,313
TOTAL ASSETS	3,417	3,245
CURRENT LIABILITIES
Short-term debt	5	127
Current portion of long-term debt and project funding	48	59
Current portion of long-term debt	2	15
Accounts payable	25	20
Accrued liabilities	106	103
Accounts payable due to associated companies	16	15
Taxes accrued	22	1
Interest accrued	13	13
Customer deposits	30	21
Other	21	22
Total Current Liabilities	286	381
DEFERRED CREDITS
Regulatory liabilities	27	14
Deferred income tax liabilities, net	888	855
Investment tax credits	4	5
Other postretirement benefit obligations	33	36
Other	18	16
Total Deferred Credits	970	926
OTHER LONG-TERM LIABILITIES
Long-term debt	1,030	882
Transition bonds issued by ACE Funding	124	170
Total Other Long-Term Liabilities	$ 1,154	$ 1,052
COMMITMENTS AND CONTINGENCIES
EQUITY
Common stock	$ 26	$ 26
Premium on stock and other capital contributions	746	651
Retained earnings	235	209
Total Equity	1,007	886
TOTAL LIABILITIES AND EQUITY	$ 3,417	$ 3,245

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Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Accounts receivable, allowance for uncollectible accounts	$ 56	$ 40
Series A preferred stock, par value	$ 0.01	$ 0.01
Series A preferred stock, shares authorized	18,000	18,000
Series A preferred stock, shares outstanding	18,000	12,600
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	400,000,000	400,000,000
Common stock, shares outstanding	254,289,261	252,728,684
Potomac Electric Power Co [Member]
Accounts receivable, allowance for uncollectible accounts	$ 17	$ 16
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	200,000,000	200,000,000
Common stock, shares outstanding	100	100
Delmarva Power & Light Co/De [Member]
Accounts receivable, allowance for uncollectible accounts	$ 17	$ 11
Common stock, par value	$ 2.25	$ 2.25
Common stock, shares authorized	1,000	1,000
Common stock, shares outstanding	1,000	1,000
Atlantic City Electric Co [Member]
Accounts receivable, allowance for uncollectible accounts	$ 17	$ 9
Common stock, par value	$ 3.00	$ 3.00
Common stock, shares authorized	25,000,000	25,000,000
Common stock, shares outstanding	8,546,017	8,546,017

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Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
OPERATING ACTIVITIES
Net Income (Loss)	$ 327	$ 242	$ (212)
(Income) loss from discontinued operations, net of income taxes	(9)		322
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	651	549	473
Deferred income taxes	122	302	458
Gains on sales of land	(46)
Losses on treasury rate locks reclassified into income	1	1	1
Impairment losses		81	4
Increase in fair value of preferred stock derivative	(15)
Other	(2)	(6)	(13)
Changes in:
Accounts receivable	(56)	48	(46)
Inventories		7	5
Prepaid expenses	8	(8)	17
Regulatory assets and liabilities, net	(146)	(216)	(121)
Accounts payable and accrued liabilities	(14)	(22)	1
Pension contributions			(120)
Pension benefit obligation, excluding contributions	76	48	65
Cash collateral related to derivative activities	2	(9)	31
Income tax-related prepayments, receivables and payables	32	(173)	(182)
Advanced payment made to taxing authority			(242)
Other assets and liabilities	8	10	9
Net current assets held for disposition or sale			47
Net Cash From (Used By) Operating Activities	939	854	497
INVESTING ACTIVITIES
Investment in property, plant and equipment	(1,230)	(1,223)	(1,310)
Department of Energy capital reimbursement awards received		4	22
Proceeds from sales of land	54
Changes in restricted cash equivalents	7	(12)	1
Net other investing activities	8	5	3
Proceeds from discontinued operations, early termination of finance leases held in trust			873
Net Cash Used By Investing Activities	(1,161)	(1,226)	(411)
FINANCING ACTIVITIES
Dividends paid on common stock	(275)	(272)	(270)
Common stock issued for the Direct Stock Purchase and Dividend Reinvestment Plan (DRP) and employee-related compensation	18	34	50
Issuances of common stock			324
Issuances of Series A preferred stock	54	126
Issuances of long-term debt	558	766	800
Reacquisitions of long-term debt	(420)	(334)	(558)
Issuances (repayments) of short-term debt, net	34	164	(200)
Borrowings under term loans	300		250
Repayment of term loan		(100)	(450)
Cost of issuances	(7)	(10)	(23)
Net other financing activities	(29)	(11)	(11)
Net Cash From (Used By) Financing Activities	233	363	(88)
Net Increase (Decrease) In Cash and Cash Equivalents	11	(9)	(2)
Cash and Cash Equivalents at Beginning of Year	14	23	25
CASH AND CASH EQUIVALENTS AT END OF YEAR	25	14	23
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for interest	268	257	260
Cash (received) paid for income taxes	(13)	(2)	228
Delmarva Power & Light Co/De [Member]
OPERATING ACTIVITIES
Net Income (Loss)	76	104	89
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	153	125	107
Deferred income taxes	74	111	65
Investment tax credit amortization	(1)	(1)	(1)
Changes in:
Accounts receivable	(9)	15	(7)
Inventories	5	(4)	2
Regulatory assets and liabilities, net	(38)	(66)	(42)
Accounts payable and accrued liabilities	10	(15)	(1)
Pension contributions	0	0	(10)
Pension benefit obligation, excluding contributions	15	8	14
Income tax-related prepayments, receivables and payables	(19)	(3)	(1)
Other assets and liabilities		(6)	(1)
Net Cash From (Used By) Operating Activities	266	268	214
INVESTING ACTIVITIES
Investment in property, plant and equipment	(352)	(352)	(357)
Net other investing activities	7	(6)	2
Net Cash Used By Investing Activities	(345)	(358)	(355)
FINANCING ACTIVITIES
Dividends paid on common stock	(92)	(100)	(30)
Capital contributions from Parent	75	130
Issuances of long-term debt	200	204	300
Reacquisitions of long-term debt	(100)	(100)	(250)
Issuances (repayments) of short-term debt, net	(1)	(41)	115
Cost of issuances	(2)	(2)	(3)
Net other financing activities		1	5
Net Cash From (Used By) Financing Activities	80	92	137
Net Increase (Decrease) In Cash and Cash Equivalents	1	2	(4)
Cash and Cash Equivalents at Beginning of Year	4	2	6
CASH AND CASH EQUIVALENTS AT END OF YEAR	5	4	2
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for interest	47	45	47
Cash (received) paid for income taxes	(5)	(43)	(8)
Atlantic City Electric Co [Member]
OPERATING ACTIVITIES
Net Income (Loss)	38	45	50
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	176	157	136
Deferred income taxes	30	37	53
Investment tax credit amortization			(1)
Changes in:
Accounts receivable	(44)	18	7
Inventories		5	2
Regulatory assets and liabilities, net	21	13	19
Accounts payable and accrued liabilities	12	(13)	(1)
Pension contributions	0	0	(30)
Income tax-related prepayments, receivables and payables	10	(16)	(6)
Other assets and liabilities	13	13	12
Net Cash From (Used By) Operating Activities	256	259	241
INVESTING ACTIVITIES
Investment in property, plant and equipment	(300)	(225)	(261)
Department of Energy capital reimbursement awards received		1	2
Net other investing activities	(6)		3
Net Cash Used By Investing Activities	(306)	(224)	(256)
FINANCING ACTIVITIES
Dividends paid on common stock	(12)	(26)	(60)
Capital contributions from Parent	95		75
Issuances of long-term debt	150	150	100
Reacquisitions of long-term debt	(58)	(48)	(108)
Issuances (repayments) of short-term debt, net	(122)	(11)	6
Repayment of term loan		(100)
Net other financing activities	(2)	(1)	(1)
Net Cash From (Used By) Financing Activities	51	(36)	12
Net Increase (Decrease) In Cash and Cash Equivalents	1	(1)	(3)
Cash and Cash Equivalents at Beginning of Year	2	3	6
CASH AND CASH EQUIVALENTS AT END OF YEAR	3	2	3
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for interest	63	61	67
Cash (received) paid for income taxes		(3)	(21)
Potomac Electric Power Co [Member]
OPERATING ACTIVITIES
Net Income (Loss)	187	171	150
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	277	229	196
Deferred income taxes	149	174	120
Gains on sales of land	(46)
Investment tax credit amortization			(1)
Other		(9)
Changes in:
Accounts receivable	(32)	27	(39)
Inventories	(5)	5	2
Prepaid expenses	2	(2)	(1)
Regulatory assets and liabilities, net	(129)	(163)	(99)
Accounts payable and accrued liabilities	(19)	(34)	26
Pension contributions	0	0	0
Pension benefit obligation, excluding contributions	24	16	21
Income tax-related prepayments, receivables and payables	(40)	(25)	(36)
Interest accrued	2		2
Other assets and liabilities	3	(3)	(11)
Net Cash From (Used By) Operating Activities	373	386	330
INVESTING ACTIVITIES
Investment in property, plant and equipment	(544)	(567)	(576)
Department of Energy capital reimbursement awards received		3	20
Proceeds from sales of land	54
Changes in restricted cash equivalents	3	(3)	(3)
Net other investing activities	10	7	(5)
Net Cash Used By Investing Activities	(477)	(560)	(564)
FINANCING ACTIVITIES
Dividends paid on common stock	(146)	(86)	(46)
Capital contributions from Parent	112	80	175
Issuances of long-term debt	208	412	400
Reacquisitions of long-term debt	(12)	(175)	(200)
Issuances (repayments) of short-term debt, net	(40)	(47)	(80)
Cost of issuances	(4)	(7)	(7)
Net other financing activities	(15)	(6)	(8)
Net Cash From (Used By) Financing Activities	103	171	234
Net Increase (Decrease) In Cash and Cash Equivalents	(1)	(3)
Cash and Cash Equivalents at Beginning of Year	6	9	9
CASH AND CASH EQUIVALENTS AT END OF YEAR	5	6	9
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for interest	116	111	102
Cash (received) paid for income taxes	$ (6)	$ (58)	$ (28)

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Consolidated Statements of Cash Flows (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Capitalized interest	$ 8	$ 8	$ 7
Delmarva Power & Light Co/De [Member]
Capitalized interest	1	1	2
Atlantic City Electric Co [Member]
Capitalized interest	1	1	1
Potomac Electric Power Co [Member]
Capitalized interest	$ 7	$ 5	$ 5

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Consolidated Statements of Equity - USD ($) $ in Millions	Total	Common Stock [Member]	Premium on Stock [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive (Loss) Income [Member]	Potomac Electric Power Co [Member]	Potomac Electric Power Co [Member] Common Stock [Member]	Potomac Electric Power Co [Member] Premium on Stock [Member]	Potomac Electric Power Co [Member] Retained Earnings [Member]	Delmarva Power & Light Co/De [Member]	Delmarva Power & Light Co/De [Member] Common Stock [Member]	Delmarva Power & Light Co/De [Member] Premium on Stock [Member]	Delmarva Power & Light Co/De [Member] Retained Earnings [Member]	Atlantic City Electric Co [Member]	Atlantic City Electric Co [Member] Common Stock [Member]	Atlantic City Electric Co [Member] Premium on Stock [Member]	Atlantic City Electric Co [Member] Retained Earnings [Member]
Balance at Dec. 31, 2012	$ 4,414	$ 2	$ 3,383	$ 1,077	$ (48)	$ 1,643		$ 755	$ 888	$ 985		$ 407	$ 578	$ 802	$ 26	$ 576	$ 200
Balance, Shares at Dec. 31, 2012		230,015,427					100				1,000				8,546,017
Net Income (Loss)	(212)			(212)		150			150	89			89	50			50
Other comprehensive income (loss)	14				14
Capital contribution from Parent						175		175						75		75
Dividends on common stock	(270)			(270)		(46)			(46)	(30)			(30)	(60)			(60)
Issuance of common stock:
Original issue shares, net	332	$ 1	331
Original issue shares, net, shares		18,734,128
DRP original issue shares	$ 30		30
DRP original issue shares, shares	2,000,000	1,575,343
Net activity related to stock-based awards	$ 7		7
Balance at Dec. 31, 2013	4,315	$ 3	3,751	595	(34)	1,922		930	992	1,044		407	637	867	$ 26	651	190
Balance, Shares at Dec. 31, 2013		250,324,898					100				1,000				8,546,017
Net Income (Loss)	242			242		171			171	104			104	45			45
Other comprehensive income (loss)	(12)				(12)
Capital contribution from Parent						80		80		130		130
Dividends on common stock	(272)			(272)		(86)			(86)	(100)			(100)	(26)			(26)
Issuance of common stock:
Original issue shares, net	14		14
Original issue shares, net, shares		1,310,276
DRP original issue shares	$ 28		28
DRP original issue shares, shares	1,000,000	1,122,575
Net activity related to stock-based awards	$ 7		7
Net activity related to stock-based awards, shares		(29,065)
Balance at Dec. 31, 2014	$ 4,322	$ 3	3,800	565	(46)	$ 2,087		1,010	1,077	$ 1,178		537	641	$ 886	$ 26	651	209
Balance, Shares at Dec. 31, 2014	252,728,684	252,728,684				100	100			1,000	1,000			8,546,017	8,546,017
Net Income (Loss)	$ 327			327		$ 187			187	$ 76			76	$ 38			38
Other comprehensive income (loss)	10				10
Capital contribution from Parent						112		112		75		75		95		95
Dividends on common stock	(275)			(275)		(146)			(146)	(92)			(92)	(12)			(12)
Issuance of common stock:
Original issue shares, net	15		15
Original issue shares, net, shares		1,157,203
DRP original issue shares	$ 11		11
DRP original issue shares, shares	1,000,000	397,939
Net activity related to stock-based awards	$ 3		3
Net activity related to stock-based awards, shares		5,435
Balance at Dec. 31, 2015	$ 4,413	$ 3	$ 3,829	$ 617	$ (36)	$ 2,240		$ 1,122	$ 1,118	$ 1,237		$ 612	$ 625	$ 1,007	$ 26	$ 746	$ 235
Balance, Shares at Dec. 31, 2015	254,289,261	254,289,261				100	100			1,000	1,000			8,546,017	8,546,017

XML

Consolidated Statements of Equity (Parenthetical) - $ / shares	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement of Stockholders' Equity [Abstract]
Dividends on common stock, per share	$ 0.27	$ 0.27	$ 0.27	$ 0.27	$ 0.27	$ 0.27	$ 0.27	$ 0.27	$ 1.08	$ 1.08	$ 1.08

XML

Organization

12 Months Ended

Dec. 31, 2015

Organization

(1) ORGANIZATION

Pepco Holdings, Inc. (PHI or Pepco Holdings), a Delaware corporation incorporated in 2001, is a holding company that, through the following regulated public utility subsidiaries, is engaged primarily in the transmission, distribution and default supply of electricity and, to a lesser extent, the distribution and supply of natural gas (Power Delivery):

• Potomac Electric Power Company (Pepco), which was incorporated in Washington, D.C. in 1896 and became a domestic Virginia corporation in 1949,

• Delmarva Power & Light Company (DPL), which was incorporated in Delaware in 1909 and became a domestic Virginia corporation in 1979, and

• Atlantic City Electric Company (ACE), which was incorporated in New Jersey in 1924.

Each of PHI, Pepco, DPL and ACE is also a reporting company under the Securities Exchange Act of 1934, as amended. Together, Pepco, DPL and ACE constitute the Power Delivery segment for financial reporting purposes.

Through Pepco Energy Services, Inc. and its subsidiaries (collectively, Pepco Energy Services), PHI provides energy savings performance contracting services, underground transmission and distribution construction and maintenance services, and steam and chilled water under long-term contracts.

PHI Service Company, a wholly owned subsidiary service company of PHI, provides a variety of support services, including legal, accounting, treasury, tax, purchasing and information technology services to PHI and its operating subsidiaries. These services are provided pursuant to service agreements among PHI, PHI Service Company and the participating operating subsidiaries. The expenses of PHI Service Company are charged to PHI and the participating operating subsidiaries in accordance with cost allocation methodologies set forth in the service agreements.

Agreement and Plan of Merger with Exelon Corporation

PHI entered into an Agreement and Plan of Merger, dated April 29, 2014, as amended and restated on July 18, 2014 (the Merger Agreement), with Exelon Corporation, a Pennsylvania corporation (Exelon), and Purple Acquisition Corp., a Delaware corporation and an indirect, wholly owned subsidiary of Exelon (Merger Sub), providing for the merger of Merger Sub with and into PHI (the Merger), with PHI surviving the Merger as an indirect, wholly owned subsidiary of Exelon. Pursuant to the Merger Agreement, at the effective time of the Merger, each outstanding share of common stock, par value $0.01 per share, of PHI (other than (i) shares owned by Exelon, Merger Sub or any other direct or indirect wholly owned subsidiary of Exelon and shares owned by PHI or any direct or indirect, wholly owned subsidiary of PHI, and in each case not held on behalf of third parties (but not including shares held by PHI in any rabbi trust or similar arrangement in respect of any compensation plan or arrangement) and (ii) shares that are owned by stockholders who have perfected and not withdrawn a demand for appraisal rights pursuant to Delaware law), will be canceled and converted into the right to receive $27.25 in cash, without interest.

In connection with entering into the Merger Agreement, as further described in Note (13), “Preferred Stock,” PHI entered into a Subscription Agreement with Exelon dated April 29, 2014 (the Subscription Agreement), pursuant to which PHI issued to Exelon 9,000 originally issued shares of non-voting, non-convertible and non-transferable Series A preferred stock, par value $0.01 per share (the Preferred Stock), for a purchase price of $90 million on April 30, 2014. Exelon also committed, pursuant to the Subscription Agreement, to purchase 1,800 originally issued shares of Preferred Stock for a purchase price of $18 million at the end of each 90-day period following the date of the Subscription Agreement until the Merger closes or is terminated, up to a maximum of 18,000 shares of Preferred Stock for a maximum aggregate consideration of $180 million. In accordance with the Subscription Agreement, on each of July 29, 2014, October 27, 2014, January 26, 2015, April 27, 2015 and July 24, 2015, an additional 1,800 shares of Preferred Stock were issued by PHI to Exelon for an aggregate purchase price of $90 million.

The Merger Agreement provides for certain termination rights for each of PHI and Exelon, and further provides that, upon termination of the Merger Agreement under certain specified circumstances, PHI will be required to pay Exelon a termination fee of $259 million or reimburse Exelon for its expenses up to $40 million (which reimbursement of expenses shall reduce on a dollar for dollar basis any termination fee subsequently payable by PHI), provided, however, that if the Merger Agreement is terminated in connection with an acquisition proposal made under certain circumstances by a person who made an acquisition proposal between April 1, 2014 and the date of the Merger Agreement, the termination fee will be $293 million plus reimbursement of Exelon for its expenses up to $40 million (not subject to offset). In addition, if the Merger Agreement is terminated under certain circumstances due to the failure to obtain required regulatory approvals with respect to the Merger or the breach by Exelon of its obligations in respect of obtaining such regulatory approvals (a Regulatory Termination), PHI will be able to redeem any issued and outstanding Preferred Stock at par value, and in that case, Exelon will be required to pay all documented out-of-pocket expenses incurred by PHI in connection with the Merger Agreement or the transactions contemplated thereby, up to $40 million. If the Merger Agreement is terminated, other than for a Regulatory Termination, PHI will be required to redeem the Preferred Stock at the purchase price of $10,000 per share, plus any unpaid accrued and accumulated dividends thereupon.

Consummation of the Merger is subject to the satisfaction or waiver of specified closing conditions, including (i) the approval of the Merger by the holders of a majority of the outstanding shares of common stock of PHI; (ii) the receipt of regulatory approvals required to consummate the Merger, including approvals from the Federal Energy Regulatory Commission (FERC), the Federal Communications Commission (FCC), the Delaware Public Service Commission (DPSC), the District of Columbia Public Service Commission (DCPSC), the Maryland Public Service Commission (MPSC), the New Jersey Board of Public Utilities (NJBPU) and the Virginia State Corporation Commission (VSCC); (iii) the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (the HSR Act); and (iv) other customary closing conditions, including (a) the accuracy of each party’s representations and warranties (subject to customary materiality qualifiers) and (b) each party’s compliance with its obligations and covenants contained in the Merger Agreement (including covenants that may limit, restrict or prohibit PHI and its subsidiaries from taking specified actions during the period between the date of the Merger Agreement and the closing of the Merger or the termination of the Merger Agreement). In addition, the obligations of Exelon and Merger Sub to consummate the Merger are subject to the required regulatory approvals not imposing terms, conditions, obligations or commitments, individually or in the aggregate, that constitute a burdensome condition (as defined in the Merger Agreement). For additional discussion, see Note (7), “Regulatory Matters – Merger Approval Proceedings.”

On September 23, 2014, the stockholders of PHI approved the Merger, on October 7, 2014, the VSCC approved the Merger, and on November 20, 2014, FERC approved the Merger. In addition, the transfer of control of certain communications licenses held by certain of PHI’s subsidiaries has been approved by the FCC. The NJBPU approved the Merger on February 11, 2015 and, on October 15, 2015, voted to extend the effectiveness of its approval until June 30, 2016. The DPSC approved the Merger on May 19, 2015.

The waiting period expired under the HSR Act on December 2, 2015, which allows for the closing of the Merger at any time on or before December 1, 2016.

On May 15, 2015, the MPSC approved the Merger, with conditions, including conditions that modify and supplement those originally proposed. On May 18, 2015, PHI and Exelon announced that they had committed to fulfill the modified, more stringent conditions and package of customer benefits imposed by the MPSC. In connection with these proceedings, the Maryland Office of People’s Counsel and several other parties to the Merger proceedings filed motions in the Circuit Court for Queen Anne’s County, Maryland, requesting a stay of the MPSC order. On August 7, 2015, the Circuit Court for Queen Anne’s County denied the motions for stay. On January 8, 2016, the Circuit Court affirmed the MPSC’s order in all respects. On January 20 and 22, 2016, respectively, the Maryland Office of People’s Counsel and environmental groups filed notices of appeal of the Circuit Court’s order to the Maryland Court of Special Appeals. Unless a motion to stay is filed and then granted by the court, the MPSC order will remain in effect during the appeals process.

On August 27, 2015, the DCPSC issued a written order denying the application seeking approval of the Merger. On September 28, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, filed an application for reconsideration with the DCPSC requesting reconsideration of the DCPSC order related to the Merger.

On October 6, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, entered into a Nonunanimous Full Settlement Agreement and Stipulation (the DC Settlement Agreement) with the District of Columbia Government, the Office of the People’s Counsel and other parties, which DC Settlement Agreement contains commitments from Exelon and PHI above those contained in their original merger application.

Also on October 6, 2015, PHI, Exelon and Merger Sub entered into a Letter Agreement (the Letter Agreement), setting forth the terms and conditions under which the parties will file with the DCPSC (a) a Motion of Joint Applicants to Reopen the Record in Formal Case No. 1119 to Allow for Consideration of the DC Settlement Agreement (the Motion to Reopen), or (b) if the Motion to Reopen is not granted, a new merger application, requesting approval of the Merger on the terms and commitments agreed to in the DC Settlement Agreement. Pursuant to the Letter Agreement, PHI and Exelon each agrees, among other things, that neither party will exercise the termination rights each may have under the Merger Agreement on or after October 29, 2015, unless: (i) the DCPSC does not, by November 20, 2015, set a procedural schedule which allows for a final order for approval of the Merger by March 4, 2016, (ii) the DCPSC sets a schedule for action which does not allow for a final order for approval of the Merger by March 4, 2016, (iii) the DCPSC fails to issue a final order approving the Merger and the DC Settlement Agreement as filed without condition or modification by March 4, 2016, (iv) the DCPSC issues a final order denying approval of the Merger or the DC Settlement Agreement or adds conditions or makes modifications to the DC Settlement Agreement, (v) the DC Settlement Agreement is terminated for any reason, or (vi) after March 4, 2016 a condition to closing of the Merger has not been satisfied or waived (other than those conditions that by their nature are to be satisfied at the closing). The Letter Agreement also provides that, subject to certain conditions, Exelon may, following receipt of all regulatory approvals consistent with the DC Settlement Agreement, delay closing of the Merger for up to 30 days to engage in capital markets transactions to raise additional funds required to consummate the Merger.

On October 6, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, filed with the DCPSC the Motion to Reopen requesting consideration of the DC Settlement Agreement and approval of the Merger on such terms and conditions set forth in the DC Settlement Agreement, without condition or modification, and to stay further proceedings on the application for reconsideration filed by the parties on September 28, 2015 and suspend the time period for reconsideration pending the DCPSC’s consideration of the DC Settlement Agreement.

On October 28, 2015, the DCPSC approved the Motion to Reopen and set a procedural schedule for its review of this matter. Upon completion of the public input and evidentiary hearings, the record was closed as of December 23, 2015. Although District of Columbia law does not impose any time limit on the DCPSC’s review of the Merger, the parties requested a decision by March 4, 2016.

Power Delivery

Each of Pepco, DPL and ACE is a regulated public utility in the jurisdictions that comprise its service territory. Each utility owns and operates a network of wires, substations and other equipment that is classified as transmission facilities, distribution facilities or common facilities (which are used for both transmission and distribution). Transmission facilities are high-voltage systems that carry wholesale electricity into, or across, the utility’s service territory. Distribution facilities are low-voltage systems that carry electricity to end-use customers in the utility’s service territory.

Each utility is responsible for the distribution of electricity, and in the case of DPL, the distribution and supply of natural gas, in its service territory, for which it is paid tariff rates established by the applicable local public service commissions. Each utility also supplies electricity at regulated rates to retail customers in its service territory who do not elect to purchase electricity from a competitive energy supplier. The regulatory term for this supply service is Standard Offer Service (SOS) in Delaware, the District of Columbia and Maryland, and Basic Generation Service in New Jersey. These supply service obligations are referred to generally as Default Electricity Supply.

Pepco Energy Services

Pepco Energy Services is engaged in the following businesses:

• Energy savings performance contracting: designing, constructing and operating energy efficiency projects and distributed generation equipment, including combined heat and power plants, principally for federal, state and local government customers;

• Underground transmission and distribution: providing underground transmission and distribution construction and maintenance services for electric utilities in North America; and

• Thermal: providing steam and chilled water under long-term contracts through systems owned and operated by Pepco Energy Services, primarily to hotels and casinos in Atlantic City, New Jersey.

During 2012, Pepco Energy Services deactivated its Buzzard Point and Benning Road oil-fired generation facilities. Pepco Energy Services completed demolition of the Benning Road generation facility in July 2015 and recognized the scrap metal salvage value of the facility as a reduction in its demolition expenses over the life of the project.

Corporate and Other

Corporate and Other includes the remaining operations of the former Other Non-Regulated segment, certain parent company transactions (including interest expense on parent company debt and incremental external merger-related costs) and inter-company eliminations.

Discontinued Operations

Cross-Border Energy Lease Investments

Through its subsidiary PCI, PHI held a portfolio of cross-border energy lease investments. During 2013, PHI completed the termination of its interest in its cross-border energy lease investments and, as a result, these investments have been accounted for as discontinued operations.

Pepco Energy Services

In December 2009, PHI announced the wind-down of the retail energy supply component of the Pepco Energy Services business which was comprised of the retail electric and natural gas supply businesses. Pepco Energy Services implemented the wind-down by not entering into any new retail electric or natural gas supply contracts while continuing to perform under its existing retail electric and natural gas supply contracts through their respective expiration dates. On March 21, 2013, Pepco Energy Services entered into an agreement whereby a third party assumed all the rights and obligations of the remaining retail natural gas supply customer contracts, and the associated supply obligations, inventory and derivative contracts. The transaction was completed on April 1, 2013. In addition, Pepco Energy Services completed the wind-down of its retail electric supply business in the second quarter of 2013 by terminating its remaining customer supply and wholesale purchase obligations beyond June 30, 2013.

The operations of Pepco Energy Services’ retail electric and natural gas supply businesses have been classified as discontinued operations and are no longer a part of the Pepco Energy Services segment for financial reporting purposes.

Potomac Electric Power Co [Member]

Organization

(1) ORGANIZATION

Potomac Electric Power Company (Pepco) is engaged in the transmission and distribution of electricity in the District of Columbia and major portions of Prince George’s County and Montgomery County in suburban Maryland. Pepco also provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its service territories who do not elect to purchase electricity from a competitive supplier. Default Electricity Supply is known as Standard Offer Service in both the District of Columbia and Maryland. Pepco is a wholly owned subsidiary of Pepco Holdings, Inc. (Pepco Holdings or PHI).

PHI entered into an Agreement and Plan of Merger, dated April 29, 2014, as amended and restated on July 18, 2014 (the Merger Agreement), with Exelon Corporation, a Pennsylvania corporation (Exelon), and Purple Acquisition Corp., a Delaware corporation and an indirect, wholly owned subsidiary of Exelon (Merger Sub), providing for the merger of Merger Sub with and into PHI (the Merger), with PHI surviving the Merger as an indirect, wholly owned subsidiary of Exelon. Pursuant to the Merger Agreement, at the effective time of the Merger, each outstanding share of common stock, par value $0.01 per share, of PHI (other than (i) shares owned by Exelon, Merger Sub or any other direct or indirect wholly owned subsidiary of Exelon and shares owned by PHI or any direct or indirect wholly owned subsidiary of PHI, and in each case not held on behalf of third parties (but not including shares held by PHI in any rabbi trust or similar arrangement in respect of any compensation plan or arrangement) and (ii) shares that are owned by stockholders who have perfected and not withdrawn a demand for appraisal rights pursuant to Delaware law), will be canceled and converted into the right to receive $27.25 in cash, without interest.

In connection with entering into the Merger Agreement, PHI entered into a Subscription Agreement, dated April 29, 2014 (the Subscription Agreement), with Exelon, pursuant to which on April 30, 2014, PHI issued to Exelon 9,000 originally issued shares of non-voting, non-convertible and non-transferable Series A preferred stock, par value $0.01 per share (the Preferred Stock), for a purchase price of $90 million. Exelon also committed pursuant to the Subscription Agreement to purchase 1,800 originally issued shares of Preferred Stock for a purchase price of $18 million at the end of each 90-day period following the date of the Subscription Agreement until the Merger closes or is terminated, up to a maximum of 18,000 shares of Preferred Stock for a maximum aggregate consideration of $180 million. In accordance with the Subscription Agreement, on each of July 29, 2014, October 27, 2014, January 26, 2015, April 27, 2015 and July 24, 2015, an additional 1,800 shares of Preferred Stock were issued by PHI to Exelon for an aggregate purchase price of $90 million. The holders of the Preferred Stock will be entitled to receive a cumulative, non-participating cash dividend of 0.1% per annum, payable quarterly, when, as and if declared by PHI’s board of directors. The proceeds from the issuance of the Preferred Stock are not subject to restrictions and are intended to serve as a prepayment of any applicable reverse termination fee payable from Exelon to PHI. The Preferred Stock will be redeemable on the terms and in the circumstances set forth in the Merger Agreement and the Subscription Agreement.

The Merger Agreement provides for certain termination rights for each of PHI and Exelon, and further provides that, upon termination of the Merger Agreement under certain specified circumstances, PHI will be required to pay Exelon a termination fee of $259 million or reimburse Exelon for its expenses up to $40 million (which reimbursement of expenses shall reduce on a dollar for dollar basis any termination fee subsequently payable by PHI), provided, however, that if the Merger Agreement is terminated in connection with an acquisition proposal made under certain circumstances by a person who made an acquisition proposal between April 1, 2014 and the date of the Merger Agreement, the termination fee will be $293 million plus reimbursement of Exelon for its expenses up to $40 million (not subject to offset). In addition, if the Merger Agreement is terminated under certain circumstances due to the failure to obtain required regulatory approvals with respect to the Merger or the breach by Exelon of its obligations in respect of obtaining such regulatory approvals (a Regulatory Termination), PHI will be able to redeem any issued and outstanding Preferred Stock at par value, and in that case, Exelon will be required to pay all documented out-of-pocket expenses incurred by PHI in connection with the Merger Agreement or the transactions contemplated thereby, up to $40 million. If the Merger Agreement is terminated, other than for a Regulatory Termination, PHI will be required to redeem the Preferred Stock at the purchase price of $10,000 per share, plus any unpaid accrued and accumulated dividends thereupon.

Consummation of the Merger is subject to the satisfaction or waiver of specified closing conditions, including (i) the approval of the Merger by the holders of a majority of the outstanding shares of common stock of PHI; (ii) the receipt of regulatory approvals required to consummate the Merger, including approvals from the Federal Energy Regulatory Commission (FERC), the Federal Communications Commission (FCC), the Delaware Public Service Commission (DPSC), the District of Columbia Public Service Commission (DCPSC), the Maryland Public Service Commission (MPSC), the New Jersey Board of Public Utilities (NJBPU) and the Virginia State Corporation Commission (VSCC); (iii) the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (the HSR Act); and (iv) other customary closing conditions, including (a) the accuracy of each party’s representations and warranties (subject to customary materiality qualifiers) and (b) each party’s compliance with its obligations and covenants contained in the Merger Agreement (including covenants that may limit, restrict or prohibit PHI and its subsidiaries from taking specified actions during the period between the date of the Merger Agreement and the closing of the Merger or the termination of the Merger Agreement). In addition, the obligations of Exelon and Merger Sub to consummate the Merger are subject to the required regulatory approvals not imposing terms, conditions, obligations or commitments, individually or in the aggregate, that constitute a burdensome condition (as defined in the Merger Agreement). For additional discussion, see Note (6), “Regulatory Matters – Merger Approval Proceedings.”

On September 23, 2014, the stockholders of PHI approved the Merger, on October 7, 2014, the VSCC approved the Merger, and on November 20, 2014, FERC approved the Merger. In addition, the transfer of control of certain communications licenses held by certain of PHI’s subsidiaries has been approved by the FCC. The NJBPU approved the Merger on February 11, 2015 and, on October 15, 2015, voted to extend the effectiveness of its approval until June 30, 2016. The DPSC approved the Merger on May 19, 2015.

The waiting period expired under the HSR Act on December 2, 2015, which allows for the closing of the Merger at any time on or before December 1, 2016.

On May 15, 2015, the MPSC approved the Merger, with conditions, including conditions that modify and supplement those originally proposed. On May 18, 2015, PHI and Exelon announced that they had committed to fulfill the modified, more stringent conditions and package of customer benefits imposed by the MPSC. In connection with these proceedings, the Maryland Office of People’s Counsel and several other parties to the Merger proceedings filed motions in the Circuit Court for Queen Anne’s County, Maryland, requesting a stay of the MPSC order. On August 7, 2015, the Circuit Court for Queen Anne’s County denied the motions for stay. On January 8, 2016, the Circuit Court affirmed the MPSC’s order in all respects. On January 20 and 22, 2016, respectively, the Maryland Office of People’s Counsel and environmental groups filed notices of appeal of the Circuit Court’s order to the Maryland Court of Special Appeals. Unless a motion to stay is filed and then granted by the court, the MPSC order will remain in effect during the appeals process.

On August 27, 2015, the DCPSC issued a written order denying the application seeking approval of the Merger. On September 28, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, filed an application for reconsideration with the DCPSC requesting reconsideration of the DCPSC order related to the Merger.

On October 6, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, entered into a Nonunanimous Full Settlement Agreement and Stipulation (the DC Settlement Agreement) with the District of Columbia Government, the Office of the People’s Counsel and other parties, which DC Settlement Agreement contains commitments from Exelon and PHI above those contained in their original merger application.

Also on October 6, 2015, PHI, Exelon and Merger Sub entered into a Letter Agreement (the Letter Agreement), setting forth the terms and conditions under which the parties will file with the DCPSC (a) a Motion of Joint Applicants to Reopen the Record in Formal Case No. 1119 to Allow for Consideration of the DC Settlement Agreement (the Motion to Reopen), or (b) if the Motion to Reopen is not granted, a new merger application, requesting approval of the Merger on the terms and commitments agreed to in the DC Settlement Agreement. Pursuant to the Letter Agreement, PHI and Exelon each agrees, among other things, that neither party will exercise the termination rights each may have under the Merger Agreement on or after October 29, 2015, unless: (i) the DCPSC does not, by November 20, 2015, set a procedural schedule which allows for a final order for approval of the Merger by March 4, 2016, (ii) the DCPSC sets a schedule for action which does not allow for a final order for approval of the Merger by March 4, 2016, (iii) the DCPSC fails to issue a final order approving the Merger and the DC Settlement Agreement as filed without condition or modification by March 4, 2016, (iv) the DCPSC issues a final order denying approval of the Merger or the DC Settlement Agreement or adds conditions or makes modifications to the DC Settlement Agreement, (v) the DC Settlement Agreement is terminated for any reason, or (vi) after March 4, 2016 a condition to closing of the Merger has not been satisfied or waived (other than those conditions that by their nature are to be satisfied at the closing). The Letter Agreement also provides that, subject to certain conditions, Exelon may, following receipt of all regulatory approvals consistent with the DC Settlement Agreement, delay closing of the Merger for up to 30 days to engage in capital markets transactions to raise additional funds required to consummate the Merger.

On October 6, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, filed with the DCPSC the Motion to Reopen requesting consideration of the DC Settlement Agreement and approval of the Merger on such terms and conditions set forth in the DC Settlement Agreement, without condition or modification, and to stay further proceedings on the application for reconsideration filed by the parties on September 28, 2015 and suspend the time period for reconsideration pending the DCPSC’s consideration of the DC Settlement Agreement.

On October 28, 2015, the DCPSC approved the Motion to Reopen and set a procedural schedule for its review of this matter. Upon completion of the public input and evidentiary hearings, the record was closed as of December 23, 2015. Although District of Columbia law does not impose any time limit on the DCPSC’s review of the Merger, the parties requested a decision by March 4, 2016.

Delmarva Power & Light Co/De [Member]

Organization

(1) ORGANIZATION

Delmarva Power & Light Company (DPL) is engaged in the transmission and distribution of electricity in portions of Delaware and Maryland and provides natural gas distribution service in northern Delaware. Additionally, DPL provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its service territories who do not elect to purchase electricity from a competitive supplier. Default Electricity Supply is known as Standard Offer Service in both Delaware and Maryland. DPL is a wholly owned subsidiary of Conectiv, LLC (Conectiv), which is wholly owned by Pepco Holdings, Inc. (Pepco Holdings or PHI).

PHI entered into an Agreement and Plan of Merger, dated April 29, 2014, as amended and restated on July 18, 2014 (the Merger Agreement), with Exelon Corporation, a Pennsylvania corporation (Exelon), and Purple Acquisition Corp., a Delaware corporation and an indirect, wholly owned subsidiary of Exelon (Merger Sub), providing for the merger of Merger Sub with and into PHI (the Merger), with PHI surviving the Merger as an indirect, wholly owned subsidiary of Exelon. Pursuant to the Merger Agreement, at the effective time of the Merger, each outstanding share of common stock, par value $0.01 per share, of PHI (other than (i) shares owned by Exelon, Merger Sub or any other direct or indirect wholly owned subsidiary of Exelon and shares owned by PHI or any direct or indirect wholly owned subsidiary of PHI, and in each case not held on behalf of third parties (but not including shares held by PHI in any rabbi trust or similar arrangement in respect of any compensation plan or arrangement) and (ii) shares that are owned by stockholders who have perfected and not withdrawn a demand for appraisal rights pursuant to Delaware law), will be canceled and converted into the right to receive $27.25 in cash, without interest.

In connection with entering into the Merger Agreement, PHI entered into a Subscription Agreement, dated April 29, 2014 (the Subscription Agreement), with Exelon, pursuant to which on April 30, 2014, PHI issued to Exelon 9,000 originally issued shares of non-voting, non-convertible and non-transferable Series A preferred stock, par value $0.01 per share (the Preferred Stock), for a purchase price of $90 million. Exelon also committed pursuant to the Subscription Agreement to purchase 1,800 originally issued shares of Preferred Stock for a purchase price of $18 million at the end of each 90-day period following the date of the Subscription Agreement until the Merger closes or is terminated, up to a maximum of 18,000 shares of Preferred Stock for a maximum aggregate consideration of $180 million. In accordance with the Subscription Agreement, on each of July 29, 2014, October 27, 2014, January 26, 2015, April 27, 2015 and July 24, 2015, an additional 1,800 shares of Preferred Stock were issued by PHI to Exelon for an aggregate purchase price of $90 million. The holders of the Preferred Stock will be entitled to receive a cumulative, non-participating cash dividend of 0.1% per annum, payable quarterly, when, as and if declared by PHI’s board of directors. The proceeds from the issuance of the Preferred Stock are not subject to restrictions and are intended to serve as a prepayment of any applicable reverse termination fee payable from Exelon to PHI. The Preferred Stock will be redeemable on the terms and in the circumstances set forth in the Merger Agreement and the Subscription Agreement.

The Merger Agreement provides for certain termination rights for each of PHI and Exelon, and further provides that, upon termination of the Merger Agreement under certain specified circumstances, PHI will be required to pay Exelon a termination fee of $259 million or reimburse Exelon for its expenses up to $40 million (which reimbursement of expenses shall reduce on a dollar for dollar basis any termination fee subsequently payable by PHI), provided, however, that if the Merger Agreement is terminated in connection with an acquisition proposal made under certain circumstances by a person who made an acquisition proposal between April 1, 2014 and the date of the Merger Agreement, the termination fee will be $293 million plus reimbursement of Exelon for its expenses up to $40 million (not subject to offset). In addition, if the Merger Agreement is terminated under certain circumstances due to the failure to obtain required regulatory approvals with respect to the Merger or the breach by Exelon of its obligations in respect of obtaining such regulatory approvals (a Regulatory Termination), PHI will be able to redeem any issued and outstanding Preferred Stock at par value, and in that case, Exelon will be required to pay all documented out-of-pocket expenses incurred by PHI in connection with the Merger Agreement or the transactions contemplated thereby, up to $40 million. If the Merger Agreement is terminated, other than for a Regulatory Termination, PHI will be required to redeem the Preferred Stock at the purchase price of $10,000 per share, plus any unpaid accrued and accumulated dividends thereupon.

Consummation of the Merger is subject to the satisfaction or waiver of specified closing conditions, including (i) the approval of the Merger by the holders of a majority of the outstanding shares of common stock of PHI; (ii) the receipt of regulatory approvals required to consummate the Merger, including approvals from the Federal Energy Regulatory Commission (FERC), the Federal Communications Commission (FCC), the Delaware Public Service Commission (DPSC), the District of Columbia Public Service Commission (DCPSC), the Maryland Public Service Commission (MPSC), the New Jersey Board of Public Utilities (NJBPU) and the Virginia State Corporation Commission (VSCC); (iii) the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (the HSR Act); and (iv) other customary closing conditions, including (a) the accuracy of each party’s representations and warranties (subject to customary materiality qualifiers) and (b) each party’s compliance with its obligations and covenants contained in the Merger Agreement (including covenants that may limit, restrict or prohibit PHI and its subsidiaries from taking specified actions during the period between the date of the Merger Agreement and the closing of the Merger or the termination of the Merger Agreement). In addition, the obligations of Exelon and Merger Sub to consummate the Merger are subject to the required regulatory approvals not imposing terms, conditions, obligations or commitments, individually or in the aggregate, that constitute a burdensome condition (as defined in the Merger Agreement). For additional discussion, see Note (7), “Regulatory Matters – Merger Approval Proceedings.”

On September 23, 2014, the stockholders of PHI approved the Merger, on October 7, 2014, the VSCC approved the Merger, and on November 20, 2014, FERC approved the Merger. In addition, the transfer of control of certain communications licenses held by certain of PHI’s subsidiaries has been approved by the FCC. The NJBPU approved the Merger on February 11, 2015 and, on October 15, 2015, voted to extend the effectiveness of its approval until June 30, 2016. The DPSC approved the Merger on May 19, 2015.

The waiting period under the HSR Act expired on December 2, 2015, which allows for the closing of the Merger at any time on or before December 1, 2016.

On May 15, 2015, the MPSC approved the Merger, with conditions, including conditions that modify and supplement those originally proposed. On May 18, 2015, PHI and Exelon announced that they had committed to fulfill the modified, more stringent conditions and package of customer benefits imposed by the MPSC. In connection with these proceedings, the Maryland Office of People’s Counsel and several other parties to the Merger proceedings filed motions in the Circuit Court for Queen Anne’s County, Maryland, requesting a stay of the MPSC order. On August 7, 2015, the Circuit Court for Queen Anne’s County denied the motions for stay. On January 8, 2016, the Circuit Court affirmed the MPSC’s order in all respects. On January 20 and 22, 2016, respectively, the Maryland Office of People’s Counsel and environmental groups filed notices of appeal of the Circuit Court’s order to the Maryland Court of Special Appeals. Unless a motion to stay is filed and then granted by the court, the MPSC order will remain in effect during the appeals process.

On August 27, 2015, the DCPSC issued a written order denying the application seeking approval of the Merger. On September 28, 2015, Exelon, PHI and Potomac Electric Power Company (Pepco), and certain of their respective affiliates, filed an application for reconsideration with the DCPSC requesting reconsideration of the DCPSC order related to the Merger.

On October 6, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, entered into a Nonunanimous Full Settlement Agreement and Stipulation (the DC Settlement Agreement) with the District of Columbia Government, the Office of the People’s Counsel and other parties, which DC Settlement Agreement contains commitments from Exelon and PHI above those contained in their original merger application.

Also on October 6, 2015, PHI, Exelon and Merger Sub entered into a Letter Agreement (the Letter Agreement), setting forth the terms and conditions under which the parties will file with the DCPSC (a) a Motion of Joint Applicants to Reopen the Record in Formal Case No. 1119 to Allow for Consideration of the DC Settlement Agreement (the Motion to Reopen), or (b) if the Motion to Reopen is not granted, a new merger application, requesting approval of the Merger on the terms and commitments agreed to in the DC Settlement Agreement. Pursuant to the Letter Agreement, PHI and Exelon each agrees, among other things, that neither party will exercise the termination rights each may have under the Merger Agreement on or after October 29, 2015, unless: (i) the DCPSC does not, by November 20, 2015, set a procedural schedule which allows for a final order for approval of the Merger by March 4, 2016, (ii) the DCPSC sets a schedule for action which does not allow for a final order for approval of the Merger by March 4, 2016, (iii) the DCPSC fails to issue a final order approving the Merger and the DC Settlement Agreement as filed without condition or modification by March 4, 2016, (iv) the DCPSC issues a final order denying approval of the Merger or the DC Settlement Agreement or adds conditions or makes modifications to the DC Settlement Agreement, (v) the DC Settlement Agreement is terminated for any reason, or (vi) after March 4, 2016 a condition to closing of the Merger has not been satisfied or waived (other than those conditions that by their nature are to be satisfied at the closing). The Letter Agreement also provides that, subject to certain conditions, Exelon may, following receipt of all regulatory approvals consistent with the DC Settlement Agreement, delay closing of the Merger for up to 30 days to engage in capital markets transactions to raise additional funds required to consummate the Merger.

On October 6, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, filed with the DCPSC the Motion to Reopen requesting consideration of the DC Settlement Agreement and approval of the Merger on such terms and conditions set forth in the DC Settlement Agreement, without condition or modification, and to stay further proceedings on the application for reconsideration filed by the parties on September 28, 2015 and suspend the time period for reconsideration pending the DCPSC’s consideration of the DC Settlement Agreement.

On October 28, 2015, the DCPSC approved the Motion to Reopen and set a procedural schedule for its review of this matter. Upon completion of the public input and evidentiary hearings, the record was closed as of December 23, 2015. Although District of Columbia law does not impose any time limit on the DCPSC’s review of the Merger, the parties requested a decision by March 4, 2016.

Atlantic City Electric Co [Member]

Organization

(1) ORGANIZATION

Atlantic City Electric Company (ACE) is engaged in the transmission and distribution of electricity in southern New Jersey. ACE also provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its service territory who do not elect to purchase electricity from a competitive energy supplier. Default Electricity Supply is known as Basic Generation Service in New Jersey. ACE is a wholly owned subsidiary of Conectiv, LLC (Conectiv), which is wholly owned by Pepco Holdings, Inc. (Pepco Holdings or PHI).

PHI entered into an Agreement and Plan of Merger, dated April 29, 2014, as amended and restated on July 18, 2014 (the Merger Agreement), with Exelon Corporation, a Pennsylvania corporation (Exelon), and Purple Acquisition Corp., a Delaware corporation and an indirect, wholly owned subsidiary of Exelon (Merger Sub), providing for the merger of Merger Sub with and into PHI (the Merger), with PHI surviving the Merger as an indirect, wholly owned subsidiary of Exelon. Pursuant to the Merger Agreement, at the effective time of the Merger, each outstanding share of common stock, par value $0.01 per share, of PHI (other than (i) shares owned by Exelon, Merger Sub or any other direct or indirect wholly owned subsidiary of Exelon and shares owned by PHI or any direct or indirect wholly owned subsidiary of PHI, and in each case not held on behalf of third parties (but not including shares held by PHI in any rabbi trust or similar arrangement in respect of any compensation plan or arrangement) and (ii) shares that are owned by stockholders who have perfected and not withdrawn a demand for appraisal rights pursuant to Delaware law), will be canceled and converted into the right to receive $27.25 in cash, without interest.

In connection with entering into the Merger Agreement, PHI entered into a Subscription Agreement, dated April 29, 2014 (the Subscription Agreement), with Exelon, pursuant to which on April 30, 2014, PHI issued to Exelon 9,000 originally issued shares of non-voting, non-convertible and non-transferable Series A preferred stock, par value $0.01 per share (the Preferred Stock), for a purchase price of $90 million. Exelon also committed pursuant to the Subscription Agreement to purchase 1,800 originally issued shares of Preferred Stock for a purchase price of $18 million at the end of each 90-day period following the date of the Subscription Agreement until the Merger closes or is terminated, up to a maximum of 18,000 shares of Preferred Stock for a maximum aggregate consideration of $180 million. In accordance with the Subscription Agreement, on each of July 29, 2014, October 27, 2014, January 26, 2015, April 27, 2015 and July 24, 2015, an additional 1,800 shares of Preferred Stock were issued by PHI to Exelon for an aggregate purchase price of $90 million. The holders of the Preferred Stock will be entitled to receive a cumulative, non-participating cash dividend of 0.1% per annum, payable quarterly, when, as and if declared by PHI’s board of directors. The proceeds from the issuance of the Preferred Stock are not subject to restrictions and are intended to serve as a prepayment of any applicable reverse termination fee payable from Exelon to PHI. The Preferred Stock will be redeemable on the terms and in the circumstances set forth in the Merger Agreement and the Subscription Agreement.

The Merger Agreement provides for certain termination rights for each of PHI and Exelon, and further provides that, upon termination of the Merger Agreement under certain specified circumstances, PHI will be required to pay Exelon a termination fee of $259 million or reimburse Exelon for its expenses up to $40 million (which reimbursement of expenses shall reduce on a dollar for dollar basis any termination fee subsequently payable by PHI), provided, however, that if the Merger Agreement is terminated in connection with an acquisition proposal made under certain circumstances by a person who made an acquisition proposal between April 1, 2014 and the date of the Merger Agreement, the termination fee will be $293 million plus reimbursement of Exelon for its expenses up to $40 million (not subject to offset). In addition, if the Merger Agreement is terminated under certain circumstances due to the failure to obtain required regulatory approvals with respect to the Merger or the breach by Exelon of its obligations in respect of obtaining such regulatory approvals (a Regulatory Termination), PHI will be able to redeem any issued and outstanding Preferred Stock at par value, and in that case, Exelon will be required to pay all documented out-of-pocket expenses incurred by PHI in connection with the Merger Agreement or the transactions contemplated thereby, up to $40 million. If the Merger Agreement is terminated, other than for a Regulatory Termination, PHI will be required to redeem the Preferred Stock at the purchase price of $10,000 per share, plus any unpaid accrued and accumulated dividends thereupon.

Consummation of the Merger is subject to the satisfaction or waiver of specified closing conditions, including (i) the approval of the Merger by the holders of a majority of the outstanding shares of common stock of PHI; (ii) the receipt of regulatory approvals required to consummate the Merger, including approvals from the Federal Energy Regulatory Commission (FERC), the Federal Communications Commission (FCC), the Delaware Public Service Commission (DPSC), the District of Columbia Public Service Commission (DCPSC), the Maryland Public Service Commission (MPSC), the New Jersey Board of Public Utilities (NJBPU) and the Virginia State Corporation Commission (VSCC); (iii) the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (the HSR Act); and (iv) other customary closing conditions, including (a) the accuracy of each party’s representations and warranties (subject to customary materiality qualifiers) and (b) each party’s compliance with its obligations and covenants contained in the Merger Agreement (including covenants that may limit, restrict or prohibit PHI and its subsidiaries from taking specified actions during the period between the date of the Merger Agreement and the closing of the Merger or the termination of the Merger Agreement). In addition, the obligations of Exelon and Merger Sub to consummate the Merger are subject to the required regulatory approvals not imposing terms, conditions, obligations or commitments, individually or in the aggregate, that constitute a burdensome condition (as defined in the Merger Agreement). For additional discussion, see Note (6), “Regulatory Matters – Merger Approval Proceedings.”

On September 23, 2014, the stockholders of PHI approved the Merger, on October 7, 2014, the VSCC approved the Merger, and on November 20, 2014, FERC approved the Merger. In addition, the transfer of control of certain communications licenses held by certain of PHI’s subsidiaries has been approved by the FCC. The NJBPU approved the Merger on February 11, 2015 and, on October 15, 2015, voted to extend the effectiveness of its approval until June 30, 2016. The DPSC approved the Merger on May 19, 2015.

The waiting period under the HSR Act expired on December 2, 2015, which allows for the closing of the Merger at any time on or before December 1, 2016.

On May 15, 2015, the MPSC approved the Merger, with conditions, including conditions that modify and supplement those originally proposed. On May 18, 2015, PHI and Exelon announced that they had committed to fulfill the modified, more stringent conditions and package of customer benefits imposed by the MPSC. In connection with these proceedings, the Maryland Office of People’s Counsel and several other parties to the Merger proceedings filed motions in the Circuit Court for Queen Anne’s County, Maryland, requesting a stay of the MPSC order. On August 7, 2015, the Circuit Court for Queen Anne’s County denied the motions for stay. On January 8, 2016, the Circuit Court affirmed the MPSC’s order in all respects. On January 20 and 22, 2016, respectively, the Maryland Office of People’s Counsel and environmental groups filed notices of appeal of the Circuit Court’s order to the Maryland Court of Special Appeals. Unless a motion to stay is filed and then granted by the court, the MPSC order will remain in effect during the appeals process.

On August 27, 2015, the DCPSC issued a written order denying the application seeking approval of the Merger. On September 28, 2015, Exelon, PHI and Potomac Electric Power Company (Pepco), and certain of their respective affiliates, filed an application for reconsideration with the DCPSC requesting reconsideration of the DCPSC order related to the Merger.

On October 6, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, entered into a Nonunanimous Full Settlement Agreement and Stipulation (the DC Settlement Agreement) with the District of Columbia Government, the Office of the People’s Counsel and other parties, which DC Settlement Agreement contains commitments from Exelon and PHI above those contained in their original merger application.

Also on October 6, 2015, PHI, Exelon and Merger Sub entered into a Letter Agreement (the Letter Agreement), setting forth the terms and conditions under which the parties will file with the DCPSC (a) a Motion of Joint Applicants to Reopen the Record in Formal Case No. 1119 to Allow for Consideration of the DC Settlement Agreement (the Motion to Reopen), or (b) if the Motion to Reopen is not granted, a new merger application, requesting approval of the Merger on the terms and commitments agreed to in the DC Settlement Agreement. Pursuant to the Letter Agreement, PHI and Exelon each agrees, among other things, that neither party will exercise the termination rights each may have under the Merger Agreement on or after October 29, 2015, unless: (i) the DCPSC does not, by November 20, 2015, set a procedural schedule which allows for a final order for approval of the Merger by March 4, 2016, (ii) the DCPSC sets a schedule for action which does not allow for a final order for approval of the Merger by March 4, 2016, (iii) the DCPSC fails to issue a final order approving the Merger and the DC Settlement Agreement as filed without condition or modification by March 4, 2016, (iv) the DCPSC issues a final order denying approval of the Merger or the DC Settlement Agreement or adds conditions or makes modifications to the DC Settlement Agreement, (v) the DC Settlement Agreement is terminated for any reason, or (vi) after March 4, 2016 a condition to closing of the Merger has not been satisfied or waived (other than those conditions that by their nature are to be satisfied at the closing). The Letter Agreement also provides that, subject to certain conditions, Exelon may, following receipt of all regulatory approvals consistent with the DC Settlement Agreement, delay closing of the Merger for up to 30 days to engage in capital markets transactions to raise additional funds required to consummate the Merger.

On October 6, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, filed with the DCPSC the Motion to Reopen requesting consideration of the DC Settlement Agreement and approval of the Merger on such terms and conditions set forth in the DC Settlement Agreement, without condition or modification, and to stay further proceedings on the application for reconsideration filed by the parties on September 28, 2015 and suspend the time period for reconsideration pending the DCPSC’s consideration of the DC Settlement Agreement.

On October 28, 2015, the DCPSC approved the Motion to Reopen and set a procedural schedule for its review of this matter. Upon completion of the public input and evidentiary hearings, the record was closed as of December 23, 2015. Although District of Columbia law does not impose any time limit on the DCPSC’s review of the Merger, the parties requested a decision by March 4, 2016.

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Significant Accounting Policies

12 Months Ended

Dec. 31, 2015

Significant Accounting Policies

(2) SIGNIFICANT ACCOUNTING POLICIES

Consolidation Policy

The accompanying consolidated financial statements include the accounts of Pepco Holdings and its wholly owned subsidiaries. All material intercompany balances and transactions between subsidiaries have been eliminated. Pepco Holdings uses the equity method to report investments, corporate joint ventures, partnerships, and affiliated companies in which it holds an interest and can exercise significant influence over the operations and policies of the entity. Certain transmission and other facilities currently held are consolidated in proportion to PHI’s percentage interest in the facility.

Consolidation of Variable Interest Entities

PHI assesses its contractual arrangements with variable interest entities (VIEs) to determine whether it is the primary beneficiary and thereby has to consolidate the entities in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 810. The guidance addresses conditions under which an entity should be consolidated based upon variable interests rather than voting interests. See Note (17), “Variable Interest Entities,” for additional information.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the consolidated financial statements and accompanying notes. Although Pepco Holdings believes that its estimates and assumptions are reasonable, they are based upon information available to management at the time the estimates are made. Actual results may differ significantly from these estimates.

Significant matters that involve the use of estimates include the assessment of contingencies, the calculation of future cash flows and fair value amounts for use in asset and goodwill impairment calculations, fair value calculations for derivative instruments, pension and other postretirement benefit assumptions, the assessment of the adequacy of the allowance for uncollectible accounts, the assessment of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of unbilled revenue, recognition of changes in network service transmission rates for prior service year costs, accrual of loss contingency liabilities for general litigation and auto and other liability claims, accrual of interest related to income taxes, the recognition of lease income and income tax benefits for investments in finance leases held in trust associated with PHI’s former cross-border energy lease investments (see Note (20), “Discontinued Operations – Cross-Border Energy Lease Investments”), and income tax provisions and reserves. Additionally, PHI is subject to legal, regulatory and other proceedings and claims that arise in the ordinary course of its business. PHI records an estimated liability for these proceedings and claims when it is probable that a loss has been incurred and the loss is reasonably estimable.

Revenue Recognition

Regulated Revenue

Power Delivery recognizes revenue upon distribution of electricity and natural gas to its customers, including unbilled revenue for services rendered but not yet billed. PHI’s unbilled revenue was $139 million and $172 million as of December 31, 2015 and 2014, respectively, and these amounts are included in Accounts receivable. PHI’s utility subsidiaries calculate unbilled revenue using an output-based methodology. This methodology is based on the supply of electricity or natural gas intended for distribution to customers. The unbilled revenue process requires management to make assumptions and judgments about input factors such as customer sales mix, temperature and estimated line losses (estimates of electricity and natural gas expected to be lost in the process of its transmission and distribution to customers). The assumptions and judgments are inherently uncertain and susceptible to change from period to period, and if the actual results differ from the projected results, the impact could be material.

Taxes related to the consumption of electricity and natural gas by the utility customers, such as fuel, energy, or other similar taxes, are components of the tariff rates charged by PHI’s utility subsidiaries and, as such, are billed to customers and recorded in Operating revenue. Accruals for the remittance of these taxes are recorded in Other taxes.

Pepco Energy Services Revenue

Revenue for Pepco Energy Services’ energy savings performance construction business and certain construction contracts in its underground transmission and distribution business is recognized using the percentage-of-completion method which recognizes revenue as work is completed and costs are incurred on its contracts. Under this method, Pepco Energy Services recognizes these contractual revenues based on the percentage of incurred costs relative to the estimated costs to complete a contract. Revenues from its operation and maintenance activities and measurement and verification activities in its energy savings business and certain construction contracts in its underground transmission and distribution business are recognized when earned.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in PHI’s gross revenues were $322 million, $321 million and $346 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Accounting for Derivatives

PHI and its subsidiaries may use derivative instruments primarily to manage risk associated with commodity prices and interest rates. Risk management policies are determined by PHI’s Corporate Risk Management Committee (CRMC). The CRMC monitors interest rate fluctuation, commodity price fluctuation and credit risk exposure, and sets risk management policies that establish limits on unhedged risk.

PHI accounts for its derivative activities in accordance with FASB guidance on derivatives and hedging. Derivatives are recorded on the consolidated balance sheets as Derivative assets or Derivative liabilities and measured at fair value.

Changes in the fair value of derivatives held by DPL that do not qualify for hedge accounting or are not designated as hedges are presented on the consolidated statements of income (loss) as Fuel and purchased energy expense or Operating revenue, respectively. Changes in the fair value of derivatives held by DPL are deferred as regulatory assets or liabilities under the accounting guidance for regulated operations.

The gain or loss on a derivative that qualifies as a cash flow hedge of an exposure to variable cash flows of a forecasted transaction is initially recorded in accumulated other comprehensive loss (AOCL) (a separate component of equity) to the extent that the hedge is effective and is subsequently reclassified into earnings, in the same category as the item being hedged, when the gain or loss from the forecasted transaction occurs. If it is probable that a forecasted transaction will not occur, the deferred gain or loss in AOCL is immediately reclassified to earnings. Gains or losses related to any ineffective portion of cash flow hedges are also recognized in earnings immediately.

Changes in the fair value of derivatives designated as fair value hedges, as well as changes in the fair value of the hedged asset, liability or firm commitment, are recorded in the consolidated statements of income (loss).

The impact of derivatives that are marked to market through current earnings, the ineffective portion of cash flow hedges, and the portion of fair value hedges that flows to current earnings are presented on a net basis in the consolidated statements of income (loss) as Operating revenue or as Fuel and purchased energy expense. When a hedging gain or loss is realized, it is presented on a net basis in the same line item as the underlying item being hedged. Unrealized derivative gains and losses are presented gross on the consolidated balance sheets except where contractual netting agreements are in place with individual counterparties.

The fair value of derivatives is determined using quoted exchange prices where available. For instruments that are not traded on an exchange, pricing services and external broker quotes may also be used to determine fair value. For some custom and complex instruments, internal models use market-based information when external broker quotes are not available. For certain long-dated instruments, broker or exchange data are extrapolated, or capacity prices are forecasted, for future periods where information is limited. Models are also used to estimate volumes for certain transactions.

PHI may enter into master netting arrangements to mitigate credit risk related to its derivatives. Under FASB guidance on offsetting of balance sheet accounts (ASC 210-20), amounts recognized for derivative assets and liabilities and the fair value amounts recognized for any related collateral positions executed with the same counterparty under such master netting agreements are offset.

See Note (14), “Derivative Instruments and Hedging Activities,” for more information about the types of derivatives employed by PHI, the components of any unrealized and realized gains and losses and Note (15), “Fair Value Disclosures,” for the methodologies used to value them.

Stock-Based Compensation

PHI recognizes compensation expense for stock-based awards, modifications or cancellations based on the grant-date fair value. Compensation expense is recognized over the requisite service period. A deferred tax asset and deferred tax benefit are also recognized concurrently with compensation expense for the tax effect of the deduction of stock options, restricted stock and restricted stock unit awards, which are deductible only upon exercise and/or vesting.

Historically, PHI’s compensation awards had included both time-based restricted stock awards that vest over a three-year service period and performance-based restricted stock and restricted stock units that were earned based on performance over a three-year period. Beginning in 2011, stock-based compensation awards have been granted primarily in the form of restricted stock units. Since May 2012, the Board of Directors have been granted an annual time-based restricted stock unit award that vests over one year as part of their compensation. The compensation expense associated with these awards is calculated based on the estimated fair value of the awards at the grant date and is recognized over the service or performance period.

PHI estimates the fair value of performance-based restricted stock unit awards using the Monte Carlo valuation model. These awards include performance conditions based upon PHI’s total stockholder return (TSR) versus a select group of peer companies over a three-year period. The effect of market conditions is considered in determining the awards’ fair value. This model values the specific features of employee share-based awards, including market-based performance conditions.

PHI’s current policy is to issue new shares to satisfy vested awards of restricted stock units.

Income Taxes

PHI and the majority of its subsidiaries file a consolidated federal income tax return. Federal income taxes are allocated among PHI and the subsidiaries included in its consolidated group pursuant to a written tax sharing agreement, which was approved by the Securities and Exchange Commission (SEC) in 2002 in connection with the establishment of PHI as a public utility holding company. Under this tax sharing agreement, PHI’s consolidated federal income tax liability is allocated based upon PHI’s and its subsidiaries’ separate taxable income or loss amounts.

The consolidated financial statements include current and deferred income taxes. Current income taxes represent the amount of tax expected to be reported on PHI’s and its subsidiaries’ federal and state income tax returns. Deferred income tax assets and liabilities represent the tax effects of temporary differences between the financial statement basis and tax basis of existing assets and liabilities, and they are measured using presently enacted tax rates. See Note (11), “Income Taxes,” for a listing of primary deferred tax assets and liabilities. The portions of Pepco’s, DPL’s and ACE’s deferred tax liabilities applicable to their utility operations that have not been recovered from utility customers represent income taxes recoverable in the future and are included in Regulatory Assets on the consolidated balance sheets. See Note (7), “Regulatory Matters – Regulatory Assets and Regulatory Liabilities,” for additional information.

PHI recognizes interest on underpayments and overpayments of income taxes, interest on uncertain tax positions and tax-related penalties in income tax expense. Deferred income tax expense generally represents the net change during the reporting period in the net deferred tax liability and deferred recoverable income taxes.

Investment tax credits are amortized to income over the useful lives of the related property.

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand, cash invested in money market funds and commercial paper held with original maturities of three months or less.

Restricted Cash Equivalents

The Restricted cash equivalents included in Current assets and the Restricted cash equivalents included in Other assets consist of (i) cash held as collateral that is restricted from use for general corporate purposes and (ii) cash equivalents that are specifically segregated based on management’s intent to use such cash equivalents for a particular purpose. The classification as current or non-current conforms to the classification of the related liabilities.

Accounts Receivable and Allowance for Uncollectible Accounts

PHI’s Accounts receivable balances primarily consist of customer accounts receivable arising from the sale of goods and services to customers within PHI’s service territories, other accounts receivable, and accrued unbilled revenue. Accrued unbilled revenue represents revenue earned in the current period but not billed to the customer until a future date (usually within one month after the receivable is recorded).

PHI maintains an allowance for uncollectible accounts and changes in the allowance are recorded as an adjustment to Other operation and maintenance expense in the consolidated statements of income (loss). PHI determines the amount of the allowance based on specific identification of material amounts at risk by customer and maintains a reserve based on its historical collection experience. The adequacy of this allowance is assessed on a quarterly basis by evaluating all known factors, such as the aging of the receivables, historical collection experience, the economic and competitive environment and changes in the creditworthiness of its customers. Accounts receivable are written off in the period in which the receivable is deemed uncollectible and collection efforts have been exhausted. Recoveries of Accounts receivable previously written off are recorded when received. Although PHI believes its allowance is adequate, it cannot anticipate with any certainty the changes in the financial condition of its customers. As a result, PHI records adjustments to the allowance for uncollectible accounts in the period in which the new information that requires an adjustment to the reserve becomes known.

Inventories

PHI utilizes the weighted average cost method of accounting for inventory items. Under this method, an average price is determined for the quantity of units acquired at each price level and is applied to the ending quantity to calculate the total ending inventory balance. Materials and supplies are recorded in Inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed.

The cost of natural gas, including transportation costs, is included in Inventory when purchased and charged to Fuel and Purchased Energy expense when used.

Goodwill

Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired at the acquisition date. PHI tests its goodwill for impairment annually as of November 1 and whenever an event occurs or circumstances change in the interim that would more likely than not (that is, a greater than 50% chance) reduce the estimated fair value of a reporting unit below the carrying amount of its net assets. Factors that may result in an interim impairment test include, but are not limited to: a change in the identified reporting units; an adverse change in business conditions; a protracted decline in PHI’s stock price causing market capitalization to fall significantly below book value; an adverse regulatory action; or an impairment of long-lived assets in the reporting unit. PHI performed its most recent annual impairment test as of November 1, 2015, and its goodwill was not impaired as described in Note (6), “Goodwill.”

Regulatory Assets and Regulatory Liabilities

The operations of Pepco are regulated by the DCPSC and the MPSC. The operations of DPL are regulated by the DPSC and the MPSC. DPL’s interstate transportation and wholesale sale of natural gas are regulated by FERC. The operations of ACE are regulated by the NJBPU. The transmission of electricity by Pepco, DPL and ACE is regulated by FERC.

The FASB guidance on regulated operations (ASC 980) applies to Power Delivery. It allows regulated entities, in appropriate circumstances, to defer the income statement impact of certain costs that are expected to be recovered in future rates through the establishment of regulatory assets and defer certain revenues that are expected to be refunded to customers through the establishment of regulatory liabilities. Management’s assessment of the probability of recovery of regulatory assets requires judgment and interpretation of laws, regulatory commission orders and other factors. If management subsequently determines, based on changes in facts or circumstances, that a regulatory asset is not probable of recovery, then the regulatory asset would be eliminated through a charge to earnings.

Effective June 2007, the MPSC approved a bill stabilization adjustment (BSA) mechanism for retail customers of Pepco and DPL. Effective November 2009, the DCPSC approved a BSA for Pepco’s retail customers. For customers to whom the BSA applies, Pepco and DPL recognize distribution revenue based on an approved distribution charge per customer. From a revenue recognition standpoint, the BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during that period. Pursuant to this mechanism, Pepco and DPL recognize either (i) a positive adjustment equal to the amount by which revenue from Maryland and the District of Columbia retail distribution sales falls short of the revenue that Pepco and DPL are entitled to earn based on the approved distribution charge per customer, or (ii) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that Pepco and DPL are entitled to earn based on the approved distribution charge per customer (a Revenue Decoupling Adjustment). A net positive Revenue Decoupling Adjustment is recorded as a regulatory asset and a net negative Revenue Decoupling Adjustment is recorded as a regulatory liability.

Leasing Activities

Pepco Holdings’ lease transactions include plant, office space, equipment, software, vehicles and elements of power purchase agreements (PPAs). In accordance with FASB guidance on leases (ASC 840), these leases are classified as either leveraged leases, operating leases or capital leases.

Leveraged Leases

Income from investments in leveraged lease transactions, in which PHI was an equity participant, was accounted for using the financing method. In accordance with the financing method, investments in leased property were recorded as a receivable from the lessee to be recovered through the collection of future rentals. Income was recognized over the life of the lease at a constant rate of return on the positive net investment. Each quarter, PHI reviewed the carrying value of each lease, which included a review of the underlying financial assumptions, the timing and collectibility of cash flows, and the credit quality of the lessee. Changes to the underlying assumptions, if any, were accounted for in accordance with FASB guidance on leases and reflected in the carrying value of the lease effective for the quarter within which they occurred.

Operating Leases

An operating lease in which PHI or a subsidiary is the lessee generally results in a level income statement charge over the term of the lease, reflecting the rental payments required by the lease agreement. If rental payments are not made on a straight-line basis, PHI’s policy is to recognize rent expense on a straight-line basis over the lease term unless another systematic and rational allocation basis is more representative of the time pattern in which the leased property is physically employed.

Capital Leases

For ratemaking purposes, capital leases in which PHI or a subsidiary is the lessee are treated as operating leases; therefore, in accordance with FASB guidance on regulated operations (ASC 980), the amortization of the leased asset is based on the recovery of rental payments through customer rates. Investments in equipment under capital leases are stated at cost, less accumulated depreciation. Depreciation is recorded on a straight-line basis over the equipment’s estimated useful life.

Arrangements Containing a Lease

PPAs are deemed to contain a lease if the arrangement conveys the right to control the use of property, plant or equipment. If so, PHI determines the appropriate lease accounting classification.

Property, Plant and Equipment

Property, plant and equipment is recorded at original cost, including labor, materials, asset retirement costs and other direct and indirect costs including capitalized interest. The carrying value of Property, plant and equipment is evaluated for impairment whenever circumstances indicate the carrying value of those assets may not be recoverable. Upon retirement, the cost of regulated property, net of salvage, is charged to Accumulated depreciation. For non-regulated property, the cost and accumulated depreciation of the property, plant and equipment retired or otherwise disposed of are removed from the related accounts and included in the determination of any gain or loss on disposition.

The annual provision for depreciation on electric and natural gas property, plant and equipment is computed on a straight-line basis using composite rates by classes of depreciable property. Non-operating and other property is generally depreciated on a straight-line basis over the useful lives of the assets. The table below provides system-wide composite annual depreciation rates for the years ended December 31, 2015, 2014 and 2013.

	Transmission and Distribution									Generation
	2015			2014			2013			2015			2014			2013
Pepco		2.3	%		2.3	%		2.2	%		—			—			—
DPL		2.6	%		2.6	%		2.6	%		—			—			—
ACE		2.6	%		2.6	%		2.8	%		—			—			—
Pepco Energy Services		—			—			—			0.6	%		1.2	%		0.4	%

In 2010, subsidiaries of PHI received awards from the U.S. Department of Energy (DOE) under the American Recovery and Reinvestment Act of 2009. Pepco was awarded $149 million from DOE to fund a portion of the costs incurred for the implementation of an advanced metering infrastructure (AMI) system (a system that collects, measures and analyzes energy usage data from advanced digital meters known as smart meters), direct load control, distribution automation and communications infrastructure in its Maryland and District of Columbia service territories. ACE was awarded $19 million from DOE to fund a portion of the costs incurred for the implementation of direct load control, distribution automation and communications infrastructure in its New Jersey service territory. PHI elected to recognize the award proceeds as a reduction in the carrying value of the assets acquired rather than grant income over the service period.

Long-Lived Asset Impairment Evaluation

PHI evaluates long-lived assets to be held and used, such as generating property and equipment, and real estate, for impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. Examples of such events or changes include a significant decrease in the market price of a long-lived asset or a significant adverse change in the manner in which an asset is being used or its physical condition. A long-lived asset to be held and used is written down to its estimated fair value if the expected future undiscounted cash flow from the asset is less than its carrying value.

For long-lived assets held for sale, an impairment loss is recognized to the extent that the asset’s carrying value exceeds its estimated fair value including costs to sell.

Capitalized Interest and Allowance for Funds Used During Construction

In accordance with FASB guidance on regulated operations (ASC 980), PHI’s utility subsidiaries may capitalize the capital costs of financing the construction of plant and equipment as allowance for funds used during construction (AFUDC). This results in the debt portion of AFUDC being recorded as a reduction of Interest expense and the equity portion of AFUDC being recorded as an increase to Other income in the accompanying consolidated statements of income (loss).

Pepco Holdings recorded AFUDC for borrowed funds of $8 million, $7 million and $7 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Pepco Holdings recorded amounts for the equity component of AFUDC of $14 million, $13 million and $11 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Amortization of Debt Issuance and Reacquisition Costs

Pepco Holdings defers and amortizes debt issuance costs and long-term debt premiums and discounts over the lives of the respective debt issuances. When PHI utility subsidiaries refinance existing debt or redeem existing debt, any unamortized premiums, discounts and debt issuance costs, as well as debt redemption costs, are classified as regulatory assets and are amortized over the life of the original or new issue.

Asset Removal Costs

In accordance with FASB guidance on regulated operations (ASC 980), asset removal costs are recorded by PHI utility subsidiaries as Regulatory liabilities. At December 31, 2015 and 2014, $211 million and $250 million, respectively, of asset removal costs are included in Regulatory liabilities in the accompanying consolidated balance sheets.

Pension and Postretirement Benefit Plans

PHI sponsors a non-contributory, defined benefit pension plan that covers substantially all employees of Pepco, DPL, ACE and certain employees of other PHI subsidiaries (the PHI Retirement Plan). PHI also provides supplemental retirement benefits to certain eligible executives and key employees through nonqualified retirement plans and provides certain postretirement health care and life insurance benefits for eligible retired employees. Most employees hired after January 1, 2005 will not have retiree health care coverage.

Net periodic benefit cost is included in Other operation and maintenance expense, net of the portion of the net periodic benefit cost capitalized as part of the cost of labor for internal construction projects. After intercompany allocations, the three utility subsidiaries are responsible for substantially all of the total PHI net periodic benefit cost.

PHI accounts for the PHI Retirement Plan, the nonqualified retirement plans, and the retirement health care and life insurance benefit plans in accordance with FASB guidance on retirement benefits (ASC 715).

See Note (9), “Pension and Other Postretirement Benefits,” for additional information.

Reclassifications

Certain prior period amounts have been reclassified in order to conform to the current period presentation.

Potomac Electric Power Co [Member]

Significant Accounting Policies

(2) SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the financial statements and accompanying notes. Although Pepco believes that its estimates and assumptions are reasonable, they are based upon information available to management at the time the estimates are made. Actual results may differ significantly from these estimates.

Significant matters that involve the use of estimates include the assessment of contingencies, the calculation of future cash flows and fair value amounts for use in asset impairment calculations, pension and other postretirement benefits assumptions, the assessment of the adequacy of the allowance for uncollectible accounts, the assessment of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of unbilled revenue, recognition of changes in network service transmission rates for prior service year costs, accrual of loss contingency liabilities for general litigation and auto and other liability claims and income tax provisions and reserves. Additionally, Pepco is subject to legal, regulatory, and other proceedings and claims that arise in the ordinary course of its business. Pepco records an estimated liability for these proceedings and claims when it is probable that a loss has been incurred and the loss is reasonably estimable.

Revenue Recognition

Pepco recognizes revenue upon distribution of electricity to its customers, including unbilled revenue for services rendered, but not yet billed. Pepco’s unbilled revenue was $76 million and $77 million as of December 31, 2015 and 2014, respectively, and these amounts are included in Accounts receivable. Pepco calculates unbilled revenue using an output-based methodology. This methodology is based on the supply of electricity intended for distribution to customers. The unbilled revenue process requires management to make assumptions and judgments about input factors such as customer sales mix, temperature, and estimated line losses (estimates of electricity expected to be lost in the process of its transmission and distribution to customers). The assumptions and judgments are inherently uncertain and susceptible to change from period to period, and if actual results differ from projected results, the impact could be material.

Taxes related to the consumption of electricity by Pepco’s customers, such as fuel, energy, or other similar taxes, are components of Pepco’s tariffs and, as such, are billed to customers and recorded in Operating revenue. Accruals for the remittance of these taxes by Pepco are recorded in Other taxes.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in Pepco’s gross revenues were $304 million, $304 million and $318 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Long-Lived Assets Impairment Evaluation

Pepco evaluates certain long-lived assets to be held and used (for example, equipment and real estate) for impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. Examples of such events or changes include a significant decrease in the market price of a long-lived asset or a significant adverse change in the manner in which an asset is being used or its physical condition. A long-lived asset to be held and used is written down to its estimated fair value if the expected future undiscounted cash flow from the asset is less than its carrying value.

For long-lived assets that can be classified as assets to be disposed of by sale, an impairment loss is recognized to the extent that the asset’s carrying value exceeds its estimated fair value including costs to sell.

Income Taxes

Pepco, as a direct subsidiary of Pepco Holdings, is included in the consolidated federal income tax return of PHI. Federal income taxes are allocated to Pepco based upon the taxable income or loss amounts, determined on a separate return basis.

The financial statements include current and deferred income taxes. Current income taxes represent the amount of tax expected to be reported on Pepco’s state income tax returns and the amount of federal income tax allocated from Pepco Holdings.

Deferred income tax assets and liabilities represent the tax effects of temporary differences between the financial statement basis and tax basis of existing assets and liabilities and they are measured using presently enacted tax rates. The portion of Pepco’s deferred tax liability applicable to its utility operations that has not been recovered from utility customers represents income taxes recoverable in the future and is included in Regulatory assets on the balance sheets. See Note (6), “Regulatory Matters,” for additional information.

Deferred income tax expense generally represents the net change during the reporting period in the net deferred tax liability and deferred recoverable income taxes.

Pepco recognizes interest on underpayments and overpayments of income taxes, interest on uncertain tax positions, and tax-related penalties in income tax expense.

Investment tax credits are being amortized to income over the useful lives of the related property.

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand, cash invested in money market funds and commercial paper held with original maturities of three months or less. Additionally, deposits in PHI’s money pool, which Pepco and certain other PHI subsidiaries use to manage short-term cash management requirements, are considered cash equivalents. Deposits in the money pool are guaranteed by PHI. PHI deposits funds in the money pool to the extent that the pool has insufficient funds to meet the needs of its participants, which may require PHI to borrow funds for deposit from external sources.

Restricted Cash Equivalents

The Restricted cash equivalents included in Current assets consist of (i) cash held as collateral that is restricted from use for general corporate purposes and (ii) cash equivalents that are specifically segregated based on management’s intent to use such cash equivalents for a particular purpose. The classification as current conforms to the classification of the related liabilities.

Accounts Receivable and Allowance for Uncollectible Accounts

Pepco’s Accounts receivable balance primarily consists of customer accounts receivable arising from the sale of goods and services to customers within its service territory, other accounts receivable, and accrued unbilled revenue. Accrued unbilled revenue represents revenue earned in the current period but not billed to the customer until a future date (usually within one month after the receivable is recorded).

Pepco maintains an allowance for uncollectible accounts and changes in the allowance are recorded as an adjustment to Other operation and maintenance expense in the statements of income. Pepco determines the amount of the allowance based on specific identification of material amounts at risk by customer and maintains a reserve based on its historical collection experience. The adequacy of this allowance is assessed on a quarterly basis by evaluating all known factors such as the aging of the receivables, historical collection experience, the economic and competitive environment and changes in the creditworthiness of its customers. Accounts receivable are written off in the period in which the receivable is deemed uncollectible and collection efforts have been exhausted. Recoveries of Accounts receivable previously written off are recorded when received. Although Pepco believes its allowance is adequate, it cannot anticipate with any certainty the changes in the financial condition of its customers. As a result, Pepco records adjustments to the allowance for uncollectible accounts in the period in which the new information that requires an adjustment to the reserve becomes known.

Inventories

Included in Inventories are transmission and distribution materials and supplies. Pepco utilizes the weighted average cost method of accounting for inventory items. Under this method, an average price is determined for the quantity of units acquired at each price level and is applied to the ending quantity to calculate the total ending inventory balance. Materials and supplies are recorded in Inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed.

Regulatory Assets and Regulatory Liabilities

Pepco is regulated by the MPSC and the DCPSC. The transmission of electricity by Pepco is regulated by FERC.

Based on the regulatory framework in which it has operated, Pepco has historically applied, and in connection with its transmission and distribution business continues to apply, the Financial Accounting Standards Board (FASB) guidance on regulated operations (Accounting Standards Codification (ASC) 980). The guidance allows regulated entities, in appropriate circumstances, to defer the income statement impact of certain costs that are expected to be recovered in future rates through the establishment of regulatory assets and defer certain revenues that are expected to be refunded to customers through the establishment of regulatory liabilities. Management’s assessment of the probability of recovery of regulatory assets requires judgment and interpretation of laws, regulatory commission orders and other factors. If management subsequently determines, based on changes in facts or circumstances, that a regulatory asset is not probable of recovery, the regulatory asset would be eliminated through a charge to earnings.

Effective June 2007, the MPSC approved a bill stabilization adjustment (BSA) mechanism for retail customers. Effective November 2009, the DCPSC approved a BSA for retail customers. For customers to whom the BSA applies, Pepco recognizes distribution revenue based on an approved distribution charge per customer. From a revenue recognition standpoint, the BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during that period. Pursuant to this mechanism, Pepco recognizes either (i) a positive adjustment equal to the amount by which revenue from Maryland and the District of Columbia retail distribution sales falls short of the revenue that Pepco is entitled to earn based on the approved distribution charge per customer, or (ii) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that Pepco is entitled to earn based on the approved distribution charge per customer (a Revenue Decoupling Adjustment). A net positive Revenue Decoupling Adjustment is recorded as a regulatory asset and a net negative Revenue Decoupling Adjustment is recorded as a regulatory liability.

Investment in Trust

Represents assets held in a trust for the benefit of participants in the Pepco Owned Life Insurance plan.

Property, Plant and Equipment

Property, plant and equipment is recorded at original cost, including labor, materials, asset retirement costs and other direct and indirect costs including capitalized interest. The carrying value of Property, plant and equipment is evaluated for impairment whenever circumstances indicate that the carrying value of those assets may not be recoverable. Upon retirement, the cost of regulated property, net of salvage, is charged to Accumulated depreciation. For additional information regarding the treatment of asset removal obligations, see the “Asset Removal Costs” section included in this Note.

The annual provision for depreciation on electric property, plant and equipment is computed on a straight-line basis using composite rates by classes of depreciable property. Non-operating and other property is generally depreciated on a straight-line basis over the useful lives of the assets. The system-wide composite annual depreciation rates for the years ended December 31, 2015, 2014 and 2013 for Pepco’s property were approximately 2.3%, 2.3% and 2.2%, respectively.

Capitalized Interest and Allowance for Funds Used During Construction

In accordance with FASB guidance on regulated operations (ASC 980), utilities may capitalize the capital costs of financing the construction of plant and equipment as allowance for funds used during construction (AFUDC). This results in the debt portion of AFUDC being recorded as a reduction of Interest expense and the equity portion of AFUDC being recorded as an increase to Other income in the accompanying statements of income.

Pepco recorded AFUDC for borrowed funds of $6 million, $5 million and $5 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Pepco recorded amounts for the equity component of AFUDC of $12 million, $10 million and $9 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Leasing Activities

Pepco’s lease transactions include office space, equipment, software and vehicles. In accordance with FASB guidance on leases (ASC 840), these leases are classified as either operating leases or capital leases.

Operating Leases

An operating lease in which Pepco is the lessee generally results in a level income statement charge over the term of the lease, reflecting the rental payments required by the lease agreement. If rental payments are not made on a straight-line basis, Pepco’s policy is to recognize rent expense on a straight-line basis over the lease term unless another systematic and rational allocation basis is more representative of the time pattern in which the leased property is physically employed.

Capital Leases

For ratemaking purposes, capital leases in which Pepco is the lessee are treated as operating leases; therefore, in accordance with FASB guidance on regulated operations (ASC 980), the amortization of the leased asset is based on the recovery of rental payments through customer rates. Investments in equipment under capital leases are stated at cost, less accumulated depreciation. Depreciation is recorded on a straight-line basis over the equipment’s estimated useful life.

Amortization of Debt Issuance and Reacquisition Costs

Pepco defers and amortizes debt issuance costs and long-term debt premiums and discounts over the lives of the respective debt issuances. When refinancing or redeeming existing debt, any unamortized premiums, discounts and debt issuance costs, as well as debt redemption costs, are classified as regulatory assets and are amortized generally over the life of the new issue.

Asset Removal Costs

In accordance with FASB guidance on regulated operations (ASC 980), asset removal costs are recorded as regulatory liabilities. At December 31, 2015 and 2014, $58 million and $84 million, respectively, of asset removal costs are included in Regulatory liabilities in the accompanying balance sheets.

Pension and Postretirement Benefit Plans

Pepco Holdings sponsors a non-contributory, defined benefit pension plan that covers substantially all employees of Pepco and certain employees of other Pepco Holdings subsidiaries (the PHI Retirement Plan). Pepco Holdings also provides supplemental retirement benefits to certain eligible executives and key employees through nonqualified retirement plans and provides certain postretirement health care and life insurance benefits for eligible retired employees.

The PHI Retirement Plan is accounted for in accordance with FASB guidance on retirement benefits (ASC 715).

Dividend Restrictions

All of Pepco’s shares of outstanding common stock are held by PHI, its parent company. In addition to its future financial performance, the ability of Pepco to pay dividends to its parent company is subject to limits imposed by: (i) state corporate laws, which impose limitations on the funds that can be used to pay dividends, and (ii) the prior rights of holders of future preferred stock, if any, and existing and future mortgage bonds and other long-term debt issued by Pepco and any other restrictions imposed in connection with the incurrence of liabilities. Pepco has no shares of preferred stock outstanding. Pepco had approximately $1,118 million and $1,077 million of retained earnings available for payment of common stock dividends at December 31, 2015 and 2014, respectively. These amounts represent the total retained earnings balances at those dates.

Reclassifications

Certain prior period amounts have been reclassified in order to conform to the current period presentation.

Delmarva Power & Light Co/De [Member]

Significant Accounting Policies

(2) SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the financial statements and accompanying notes. Although DPL believes that its estimates and assumptions are reasonable, they are based upon information available to management at the time the estimates are made. Actual results may differ significantly from these estimates.

Significant matters that involve the use of estimates include the assessment of contingencies, the calculation of future cash flows and fair value amounts for use in asset and goodwill impairment calculations, fair value calculations for derivative instruments, pension and other postretirement benefits assumptions, the assessment of the adequacy of the allowance for uncollectible accounts, the assessment of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of unbilled revenue, recognition of changes in network service transmission rates for prior service year costs, accrual of loss contingency liabilities for general litigation and auto and other liability claims, and income tax provisions and reserves. Additionally, DPL is subject to legal, regulatory, and other proceedings and claims that arise in the ordinary course of its business. DPL records an estimated liability for these proceedings and claims when it is probable that a loss has been incurred and the loss is reasonably estimable.

Revenue Recognition

DPL recognizes revenue upon distribution of electricity and natural gas to its customers, including unbilled revenue for services rendered, but not yet billed. DPL’s unbilled revenue was $37 million and $63 million as of December 31, 2015 and 2014, respectively, and these amounts are included in Accounts receivable. DPL calculates unbilled revenue using an output-based methodology. This methodology is based on the supply of electricity or natural gas intended for distribution to customers. The unbilled revenue process requires management to make assumptions and judgments about input factors such as customer sales mix, temperature, and estimated line losses (estimates of electricity and natural gas expected to be lost in the process of its transmission and distribution to customers). The assumptions and judgments are inherently uncertain and susceptible to change from period to period, and if the actual results differ from the projected results, the impact could be material. Revenue from non-regulated electricity and natural gas sales is included in Electric revenue and Natural gas revenue, respectively.

Taxes related to the consumption of electricity and natural gas by DPL’s customers, such as fuel, energy, or other similar taxes, are components of DPL’s tariffs and, as such, are billed to customers and recorded in Operating revenue. Accruals for the remittance of these taxes by DPL are recorded in Other taxes.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in DPL’s gross revenues were $18 million, $16 million and $17 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Accounting for Derivatives

DPL uses derivative instruments primarily to reduce natural gas commodity price volatility and to limit its customers’ exposure to natural gas price fluctuations under a hedging program approved by the DPSC. Derivatives are recorded in the balance sheets as Derivative assets or Derivative liabilities and measured at fair value. DPL enters physical natural gas contracts as part of the hedging program that qualify as normal purchases or normal sales, which are not required to be recorded in the financial statements until settled. DPL’s capacity contracts are not classified as derivatives. Changes in the fair value of derivatives that are not designated as cash flow hedges are reflected in income.

All premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all gains and losses related to hedging activities, are fully recoverable through the fuel adjustment clause approved by the DPSC, and are deferred under Financial Accounting Standards Board (FASB) guidance on regulated operations (Accounting Standards Codification (ASC) 980) until recovered.

Long-Lived Assets Impairment Evaluation

DPL evaluates certain long-lived assets to be held and used (for example, equipment and real estate) for impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. Examples of such events or changes include a significant decrease in the market price of a long-lived asset or a significant adverse change in the manner in which an asset is being used or its physical condition. A long-lived asset to be held and used is written down to its estimated fair value if the expected future undiscounted cash flow from the asset is less than its carrying value.

For long-lived assets that can be classified as assets to be disposed of by sale, an impairment loss is recognized to the extent that the assets’ carrying value exceeds its estimated fair value including costs to sell.

Income Taxes

DPL, as an indirect subsidiary of Pepco Holdings, is included in the consolidated federal income tax return of PHI. Federal income taxes are allocated to DPL based upon the taxable income or loss amounts, determined on a separate return basis.

The accompanying financial statements include current and deferred income taxes. Current income taxes represent the amount of tax expected to be reported on DPL’s state income tax returns and the amount of federal income tax allocated from Pepco Holdings.

Deferred income tax assets and liabilities represent the tax effects of temporary differences between the financial statement basis and tax basis of existing assets and liabilities, and they are measured using presently enacted tax rates. The portion of DPL’s deferred tax liability applicable to its utility operations that has not been recovered from utility customers represents income taxes recoverable in the future and is included in Regulatory assets on the accompanying balance sheets. See Note (7), “Regulatory Matters,” for additional information.

Deferred income tax expense generally represents the net change during the reporting period in the net deferred tax liability and deferred recoverable income taxes.

DPL recognizes interest on underpayments and overpayments of income taxes, interest on uncertain tax positions, and tax-related penalties in income tax expense.

Investment tax credits are being amortized to income over the useful lives of the related property.

Consolidation of Variable Interest Entities

DPL assesses its contractual arrangements with variable interest entities (VIEs) to determine whether it is the primary beneficiary and thereby has to consolidate the entities in accordance with FASB ASC 810. The guidance addresses conditions under which an entity should be consolidated based upon variable interests rather than voting interests. See Note (17), “Variable Interest Entities,” for additional information.

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand, cash invested in money market funds and commercial paper held with original maturities of three months or less. Additionally, deposits in PHI’s money pool, which DPL and certain other PHI subsidiaries use to manage short-term cash management requirements, are considered cash equivalents. Deposits in the money pool are guaranteed by PHI. PHI deposits funds in the money pool to the extent that the pool has insufficient funds to meet the needs of its participants, which may require PHI to borrow funds for deposit from external sources.

Accounts Receivable and Allowance for Uncollectible Accounts

DPL’s Accounts receivable balance primarily consists of customer accounts receivable arising from the sale of goods and services to customers within its service territory, other accounts receivable, and accrued unbilled revenue. Accrued unbilled revenue represents revenue earned in the current period but not billed to the customer until a future date (usually within one month after the receivable is recorded).

DPL maintains an allowance for uncollectible accounts and changes in the allowance are recorded as an adjustment to Other operation and maintenance expense in the accompanying statements of income. DPL determines the amount of the allowance based on specific identification of material amounts at risk by customer and maintains a reserve based on its historical collection experience. The adequacy of this allowance is assessed on a quarterly basis by evaluating all known factors such as the aging of the receivables, historical collection experience, the economic and competitive environment and changes in the creditworthiness of its customers. Accounts receivable are written off in the period in which the receivable is deemed uncollectible and collection efforts have been exhausted. Recoveries of Accounts receivable previously written off are recorded when received. Although DPL believes its allowance is adequate, it cannot anticipate with any certainty the changes in the financial condition of its customers. As a result, DPL records adjustments to the allowance for uncollectible accounts in the period in which the new information that requires an adjustment to the reserve becomes known.

Inventories

Included in Inventories are transmission and distribution materials and supplies and natural gas. DPL utilizes the weighted average cost method of accounting for inventory items. Under this method, an average price is determined for the quantity of units acquired at each price level and is applied to the ending quantity to calculate the total ending inventory balance. Materials and supplies are recorded in Inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed.

The cost of natural gas, including transportation costs, is included in Inventory when purchased and charged to Gas purchased expense when used.

Goodwill

Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired at the acquisition date. DPL tests its goodwill for impairment annually as of November 1 and whenever an event occurs or circumstances change in the interim that would more likely than not (that is, a greater than 50% chance) reduce the estimated fair value of DPL below the carrying amount of its net assets. Factors that may result in an interim impairment test include, but are not limited to: a change in the identified reporting unit, an adverse change in business conditions, an adverse regulatory action, or an impairment of DPL’s long-lived assets. DPL performed its most recent annual impairment test as of November 1, 2015, and its goodwill was not impaired as described in Note (6), “Goodwill.”

Regulatory Assets and Regulatory Liabilities

Certain aspects of DPL’s business are subject to regulation by the DPSC and the MPSC. The transmission of electricity by DPL is regulated by FERC. DPL’s interstate transportation and wholesale sale of natural gas are regulated by FERC.

Based on the regulatory framework in which it has operated, DPL has historically applied, and in connection with its transmission and distribution business continues to apply, FASB guidance on regulated operations (ASC 980). The guidance allows regulated entities, in appropriate circumstances, to defer the income statement impact of certain costs that are expected to be recovered in future rates through the establishment of regulatory assets and defer certain revenues that are expected to be refunded to customers through the establishment of regulatory liabilities. Management’s assessment of the probability of recovery of regulatory assets requires judgment and interpretation of laws, regulatory commission orders and other factors. If management subsequently determines, based on changes in facts or circumstances, that a regulatory asset is not probable of recovery, the regulatory asset would be eliminated through a charge to earnings.

Effective June 2007, the MPSC approved a bill stabilization adjustment (BSA) mechanism for retail customers. For customers to whom the BSA applies, DPL recognizes distribution revenue based on an approved distribution charge per customer. From a revenue recognition standpoint, the BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during that period. Pursuant to this mechanism, DPL recognizes either (i) a positive adjustment equal to the amount by which revenue from Maryland retail distribution sales falls short of the revenue that DPL is entitled to earn based on the approved distribution charge per customer, or (ii) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that DPL is entitled to earn based on the approved distribution charge per customer (a Revenue Decoupling Adjustment). A net positive Revenue Decoupling Adjustment is recorded as a regulatory asset and a net negative Revenue Decoupling Adjustment is recorded as a regulatory liability.

Property, Plant and Equipment

Property, plant and equipment is recorded at original cost, including labor, materials, asset retirement costs and other direct and indirect costs including capitalized interest. The carrying value of Property, plant and equipment is evaluated for impairment whenever circumstances indicate that the carrying value of those assets may not be recoverable. Upon retirement, the cost of regulated property, net of salvage, is charged to Accumulated depreciation. For additional information regarding the treatment of asset retirement obligations, see the “Asset Removal Costs” section included in this Note.

The annual provision for depreciation on electric and natural gas property, plant and equipment is computed on a straight-line basis using composite rates by classes of depreciable property. Non-operating and other property is generally depreciated on a straight-line basis over the useful lives of the assets. The system-wide composite annual depreciation rate for each of the years ended December 31, 2015, 2014 and 2013 for DPL’s property was approximately 2.6%.

Capitalized Interest and Allowance for Funds Used During Construction

In accordance with FASB guidance on regulated operations (ASC 980), utilities may capitalize the capital costs of financing the construction of plant and equipment as allowance for funds used during construction (AFUDC). This results in the debt portion of AFUDC being recorded as a reduction of Interest expense and the equity portion of AFUDC being recorded as an increase to Other income in the accompanying statements of income.

DPL recorded AFUDC for borrowed funds of $1 million, $1 million and $2 million for the years ended December 31, 2015, 2014 and 2013, respectively.

DPL recorded amounts for the equity component of AFUDC of $1 million, $2 million and $2 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Leasing Activities

DPL’s lease transactions include plant, office space, equipment, software, vehicles and elements of power purchase agreements (PPAs). In accordance with FASB guidance on leases (ASC 840), these leases are classified as operating leases.

Operating Leases

An operating lease in which DPL is the lessee generally results in a level income statement charge over the term of the lease, reflecting the rental payments required by the lease agreement. If rental payments are not made on a straight-line basis, DPL’s policy is to recognize rent expense on a straight-line basis over the lease term unless another systematic and rational allocation basis is more representative of the time pattern in which the leased property is physically employed.

Arrangements Containing a Lease

PPAs are deemed to contain a lease if the arrangement conveys the right to control the use of property, plant or equipment. If so, DPL determines the appropriate lease accounting classification.

Amortization of Debt Issuance and Reacquisition Costs

DPL defers and amortizes debt issuance costs and long-term debt premiums and discounts over the lives of the respective debt issuances. When refinancing or redeeming existing debt, any unamortized premiums, discounts and debt issuance costs, as well as debt redemption costs, are classified as regulatory assets and are amortized generally over the life of the original issue.

Asset Removal Costs

In accordance with FASB guidance on regulated operations (ASC 980), asset removal costs are recorded as regulatory liabilities. At December 31, 2015 and 2014, $153 million and $166 million, respectively, of asset removal costs are included in Regulatory liabilities in the accompanying balance sheets.

Pension and Postretirement Benefit Plans

Pepco Holdings sponsors a non-contributory, defined benefit pension plan that covers substantially all employees of DPL and certain employees of other Pepco Holdings subsidiaries (the PHI Retirement Plan). Pepco Holdings also provides supplemental retirement benefits to certain eligible executives and key employees through nonqualified retirement plans and provides certain postretirement health care and life insurance benefits for eligible retired employees.

The PHI Retirement Plan is accounted for in accordance with FASB guidance on retirement benefits (ASC 715).

Dividend Restrictions

All of DPL’s shares of outstanding common stock are held by Conectiv, its parent company. In addition to its future financial performance, the ability of DPL to pay dividends to its parent company is subject to limits imposed by: (i) state corporate laws, which impose limitations on the funds that can be used to pay dividends, and (ii) the prior rights of holders of future preferred stock, if any, and existing and future mortgage bonds and other long-term debt issued by DPL and any other restrictions imposed in connection with the incurrence of liabilities. DPL has no shares of preferred stock outstanding. DPL had approximately $625 million and $641 million of retained earnings available for payment of common stock dividends at December 31, 2015 and 2014, respectively. These amounts represent the total retained earnings balances at those dates.

Reclassifications

Certain prior period amounts have been reclassified in order to conform to the current period presentation.

Atlantic City Electric Co [Member]

Significant Accounting Policies

(2) SIGNIFICANT ACCOUNTING POLICIES

Consolidation Policy

The accompanying consolidated financial statements include the accounts of ACE and its wholly owned subsidiary Atlantic City Electric Transition Funding, LLC (ACE Funding). All intercompany balances and transactions between subsidiaries have been eliminated. ACE uses the equity method to report investments, corporate joint ventures, partnerships, and affiliated companies where it holds an interest and can exercise significant influence over the operations and policies of the entity. Certain transmission and other facilities currently held are consolidated in proportion to ACE’s percentage interest in the facility.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the consolidated financial statements and accompanying notes. Although ACE believes that its estimates and assumptions are reasonable, they are based upon information available to management at the time the estimates are made. Actual results may differ significantly from these estimates.

Significant matters that involve the use of estimates include the assessment of contingencies, the calculation of future cash flows and fair value amounts for use in asset impairment calculations, fair value calculations for derivative instruments, pension and other postretirement benefits assumptions, the assessment of the adequacy of the allowance for uncollectible accounts, the assessment of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of unbilled revenue, recognition of changes in network service transmission rates for prior service year costs, accrual of loss contingency liabilities for general litigation and auto and other liability claims, and income tax provisions and reserves. Additionally, ACE is subject to legal, regulatory, and other proceedings and claims that arise in the ordinary course of its business. ACE records an estimated liability for these proceedings and claims when it is probable that a loss has been incurred and the loss is reasonably estimable.

Revenue Recognition

ACE recognizes revenue upon distribution of electricity to its customers, including unbilled revenue for electricity delivered but not yet billed. ACE’s unbilled revenue was $26 million and $32 million as of December 31, 2015 and 2014, respectively, and these amounts are included in Accounts receivable. ACE calculates unbilled revenue using an output-based methodology. This methodology is based on the supply of electricity intended for distribution to customers. The unbilled revenue process requires management to make assumptions and judgments about input factors such as customer sales mix, temperature, and estimated line losses (estimates of electricity expected to be lost in the process of its transmission and distribution to customers). The assumptions and judgments are inherently uncertain and susceptible to change from period to period, and if the actual results differ from the projected results, the impact could be material.

Taxes related to the consumption of electricity by ACE’s customers are a component of ACE’s tariffs and, as such, are billed to customers and recorded in Operating revenue. Accruals for the remittance of these taxes by ACE are recorded in Other taxes.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in ACE’s gross revenues were zero, $1 million and $11 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Long-Lived Asset Impairment Evaluation

ACE evaluates certain long-lived assets to be held and used (for example, equipment and real estate) for impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. Examples of such events or changes include a significant decrease in the market price of a long-lived asset or a significant adverse change in the manner in which an asset is being used or its physical condition. A long-lived asset to be held and used is written down to its estimated fair value if the expected future undiscounted cash flow from the asset is less than its carrying value.

For long-lived assets that can be classified as assets to be disposed of by sale, an impairment loss is recognized to the extent that the asset’s carrying value exceeds its estimated fair value including costs to sell.

Income Taxes

ACE, as an indirect subsidiary of Pepco Holdings, is included in the consolidated federal income tax return of PHI. Federal income taxes are allocated to ACE based upon the taxable income or loss amounts, determined on a separate return basis.

The consolidated financial statements include current and deferred income taxes. Current income taxes represent the amount of tax expected to be reported on ACE’s state income tax returns and the amount of federal income tax allocated from Pepco Holdings.

Deferred income tax assets and liabilities represent the tax effects of temporary differences between the financial statement basis and tax basis of existing assets and liabilities, and they are measured using presently enacted tax rates. The portion of ACE’s deferred tax liability applicable to its utility operations that has not been recovered from utility customers represents income taxes recoverable in the future and is included in Regulatory assets on the consolidated balance sheets. See Note (6), “Regulatory Matters,” for additional information.

Deferred income tax expense generally represents the net change during the reporting period in the net deferred tax liability and deferred recoverable income taxes.

ACE recognizes interest on underpayments and overpayments of income taxes, interest on uncertain tax positions, and tax-related penalties in income tax expense.

Investment tax credits are being amortized to income over the useful lives of the related property.

Consolidation of Variable Interest Entities

ACE assesses its contractual arrangements with variable interest entities (VIEs) to determine whether it is the primary beneficiary and thereby has to consolidate the entities in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 810. The guidance addresses conditions under which an entity should be consolidated based upon variable interests rather than voting interests. See Note (16), “Variable Interest Entities,” for additional information.

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand, cash invested in money market funds and commercial paper held with original maturities of three months or less. Additionally, deposits in PHI’s money pool, which ACE and certain other PHI subsidiaries use to manage short-term cash management requirements, are considered cash equivalents. Deposits in the money pool are guaranteed by PHI. PHI deposits funds in the money pool to the extent that the pool has insufficient funds to meet the needs of its participants, which may require PHI to borrow funds for deposit from external sources.

Restricted Cash Equivalents

The Restricted cash equivalents included in Current assets and the Restricted cash equivalents included in Other assets consist of (i) cash held as collateral that is restricted from use for general corporate purposes and (ii) cash equivalents that are specifically segregated based on management’s intent to use such cash equivalents for a particular purpose. The classification as current or non-current conforms to the classification of the related liabilities.

Accounts Receivable and Allowance for Uncollectible Accounts

ACE’s Accounts receivable balance primarily consists of customer accounts receivable arising from the sale of goods and services to customers within its service territories, other accounts receivable, and accrued unbilled revenue. Accrued unbilled revenue represents revenue earned in the current period but not billed to the customer until a future date (usually within one month after the receivable is recorded).

ACE maintains an allowance for uncollectible accounts and changes in the allowance are recorded as an adjustment to Other operation and maintenance expense in the consolidated statements of income. ACE determines the amount of the allowance based on specific identification of material amounts at risk by customer and maintains a reserve based on its historical collection experience. The adequacy of this allowance is assessed on a quarterly basis by evaluating all known factors such as the aging of the receivables, historical collection experience, the economic and competitive environment and changes in the creditworthiness of its customers. Accounts receivable are written off in the period in which the receivable is deemed uncollectible and collection efforts have been exhausted. Recoveries of Accounts receivable previously written off are recorded when received. Although ACE believes its allowance is adequate, it cannot anticipate with any certainty the changes in the financial condition of its customers. As a result, ACE records adjustments to the allowance for uncollectible accounts in the period in which the new information that requires an adjustment to the reserve becomes known.

Inventories

Included in inventories are transmission and distribution materials and supplies. ACE utilizes the weighted average cost method of accounting for inventory items. Under this method, an average price is determined for the quantity of units acquired at each price level and is applied to the ending quantity to calculate the total ending inventory balance. Materials and supplies are recorded in Inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed.

Regulatory Assets and Regulatory Liabilities

Certain aspects of ACE’s business are subject to regulation by the NJBPU. The transmission of electricity by ACE is regulated by FERC.

Based on the regulatory framework in which it has operated, ACE has historically applied, and in connection with its transmission and distribution business continues to apply, FASB guidance on regulated operations (ASC 980). The guidance allows regulated entities, in appropriate circumstances, to defer the income statement impact of certain costs that are expected to be recovered in future rates through the establishment of regulatory assets and defer certain revenues that are expected to be refunded to customers through the establishment of regulatory liabilities. Management’s assessment of the probability of recovery of regulatory assets requires judgment and interpretation of laws, regulatory commission orders and other factors. If management subsequently determines, based on changes in facts or circumstances, that a regulatory asset is not probable of recovery, the regulatory asset would be eliminated through a charge to earnings.

Property, Plant and Equipment

Property, plant and equipment is recorded at original cost, including labor, materials, asset retirement costs and other direct and indirect costs, including capitalized interest. The carrying value of Property, plant and equipment is evaluated for impairment whenever circumstances indicate that the carrying value of those assets may not be recoverable. Upon retirement, the cost of regulated property, net of salvage, is charged to accumulated depreciation.

The annual provision for depreciation on electric property, plant and equipment is computed on a straight-line basis using composite rates by classes of depreciable property. Non-operating and other property is generally depreciated on a straight-line basis over the useful lives of the assets. The system-wide composite annual depreciation rates for the years ended December 31, 2015, 2014 and 2013 for ACE’s property were approximately 2.6%, 2.6% and 2.8%, respectively.

Capitalized Interest and Allowance for Funds Used During Construction

In accordance with FASB guidance on regulated operations (ASC 980), utilities may capitalize the capital costs of financing the construction of plant and equipment as allowance for funds used during construction (AFUDC). This results in the debt portion of AFUDC being recorded as a reduction of Interest expense and the equity portion of AFUDC being recorded as an increase to Other income in the accompanying consolidated statements of income.

ACE recorded AFUDC for borrowed funds of $1 million, $1 million and less than $1 million for the years ended December 31, 2015, 2014 and 2013, respectively.

ACE recorded amounts for the equity component of AFUDC of $1 million, $1 million and less than $1 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Leasing Activities

ACE’s lease transactions include plant, office space, equipment, software, vehicles and elements of power purchase agreements (PPAs). In accordance with FASB guidance on leases (ASC 840), these leases are classified as operating leases.

Operating Leases

An operating lease in which ACE is the lessee generally results in a level income statement charge over the term of the lease, reflecting the rental payments required by the lease agreement. If rental payments are not made on a straight-line basis, ACE’s policy is to recognize rent expense on a straight-line basis over the lease term unless another systematic and rational allocation basis is more representative of the time pattern in which the leased property is physically employed.

Arrangements Containing a Lease

PPAs are deemed to contain a lease if the arrangement conveys the right to control the use of property, plant or equipment. If so, ACE determines the appropriate lease accounting classification.

Amortization of Debt Issuance and Reacquisition Costs

ACE defers and amortizes debt issuance costs and long-term debt premiums and discounts over the lives of the respective debt issuances. When refinancing or redeeming existing debt, any unamortized premiums, discounts and debt issuance costs, as well as debt redemption costs, are classified as regulatory assets and are amortized generally over the life of the original issue.

Pension and Postretirement Benefit Plans

Pepco Holdings sponsors a non-contributory, defined benefit pension plan that covers substantially all employees of ACE and certain employees of other Pepco Holdings subsidiaries (the PHI Retirement Plan). Pepco Holdings also provides supplemental retirement benefits to certain eligible executives and key employees through nonqualified retirement plans and provides certain postretirement health care and life insurance benefits for eligible retired employees.

The PHI Retirement Plan is accounted for in accordance with FASB guidance on retirement benefits (ASC 715).

Dividend Restrictions

All of ACE’s shares of outstanding common stock are held by Conectiv, its parent company. In addition to its future financial performance, the ability of ACE to pay dividends to its parent company is subject to limits imposed by: (i) state corporate laws, which impose limitations on the funds that can be used to pay dividends and the regulatory requirement that ACE obtain the prior approval of the NJBPU before dividends can be paid if its equity as a percent of its total capitalization, excluding securitization debt, falls below 30%; (ii) the prior rights of holders of future preferred stock, if any, and existing and future mortgage bonds and other long-term debt issued by ACE and any other restrictions imposed in connection with the incurrence of liabilities; and (iii) certain provisions of ACE’s charter that impose restrictions on payment of common stock dividends for the benefit of preferred stockholders. Currently, the restriction in the ACE charter does not limit its ability to pay common stock dividends. ACE had approximately $235 million and $209 million of retained earnings available for payment of common stock dividends at December 31, 2015 and 2014, respectively. These amounts represent the total retained earnings balances at those dates.

Reclassifications

Certain prior period amounts have been reclassified in order to conform to the current period presentation.

XML

Newly Adopted Accounting Standards

12 Months Ended

Dec. 31, 2015

Newly Adopted Accounting Standards

(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Discontinued Operations (ASC 205)

In April 2014, the FASB issued new guidance on the reporting of discontinued operations that is effective for dispositions that occur after January 1, 2015. In order for dispositions to be presented as discontinued operations, the dispositions must represent a strategic shift that will have a major effect on an entity’s operations and financial results. Adoption of this guidance during the first quarter of 2015 did not have an impact on PHI’s consolidated financial statements.

Business Combinations (ASC 805)

In November 2014, the FASB issued new recognition and disclosure requirements related to pushdown accounting. The new recognition requirements grant an acquired entity (or its subsidiaries) the option to elect whether and when a new accounting and reporting basis (pushdown accounting) will be applied when an acquirer obtains control of the acquired entity. This election may be made by the acquired entity (or its subsidiaries) for future change-in-control events or for its most recent change-in-control event, and the acquired entity will be required to determine whether pushdown accounting will be applied in the reporting period in which the change-in-control event occurs or in a subsequent reporting period.

The new required disclosures include information that enables financial statement users to evaluate the effects of pushdown accounting. Disclosures are required to be made in the period in which pushdown accounting is applied and are expected to include both qualitative and quantitative information.

The new recognition and disclosure requirements became effective on a prospective basis on November 18, 2014. PHI currently anticipates it may be affected by the new guidance if its Merger with Exelon is consummated.

Fair Value Measurement (ASC 820)

In May 2015, the FASB issued new disclosure requirements for investment fair values. Under the new requirements, investment fair values based on net asset value (NAV) per share will continue to be disclosed, however, a level will not be assigned to those investment fair values. The new requirements are effective for PHI beginning January 1, 2016, and are required to be implemented on a retrospective basis for all periods presented; however, early adoption is permitted. PHI has elected to early adopt the new guidance and implement the change in accounting principle in the fourth quarter of 2015. The impact of this guidance effected the presentation of certain investments that use NAV per share as a practical expedient in Note (9), “Pension and Other Postretirement Benefits” and had no impact to Note (15), “Fair Value Disclosure,” as the financial instruments measured at fair value on a recurring basis and other financial instruments are not based on NAV.

Presentation of Debt Issuance Costs (ASC 835)

In April 2015, the FASB issued new guidance for the presentation of debt issuance costs on the balance sheet. Debt issuance costs are currently required to be presented on the balance sheet as assets. However, under the new requirements, these debt issuance costs will be offset against the debt to which the costs relate. The new requirements are effective for PHI beginning January 1, 2016, and are required to be implemented on a retrospective basis for all periods presented; however, early adoption is permitted. PHI has elected to early adopt the new guidance in the fourth quarter of 2015. The table below illustrates the effects of the retrospective application on reported balances in PHI’s consolidated balance sheet as of December 31, 2014.

	December 31, 2014 As Filed		Reclassification ASC 835			December 31, 2014 As Adjusted
	(millions of dollars)
Other (within other assets)	$	166	$	(45	)	$	121
Long-term debt		4,441		(44	)		4,397
Transition bonds issued by ACE Funding		171		(1	)		170

Balance Sheet Classification of Deferred Taxes (ASC 740)

In November 2015, the FASB issued new requirements for the balance sheet classification of deferred taxes. Entities are currently required to present a current and noncurrent deferred tax balance on the balance sheet. Under the new requirements, deferred taxes will only be presented as noncurrent. The new requirements are effective for PHI beginning January 1, 2017, and may be implemented on either a prospective or retrospective basis; however, early adoption is permitted. PHI has elected to early adopt the new guidance on a retrospective basis in the fourth quarter of 2015. The table below illustrates the effects of the retrospective application on reported balances in PHI’s consolidated balance sheet as of December 31, 2014.

	December 31, 2014 As Filed		Reclassification ASC 740			December 31, 2014 As Adjusted
	(millions of dollars)
Deferred income taxes, net (within current assets)	$	50	$	(50	)	$	—
Deferred income taxes, net (within other assets)		—		17			17
Other (within current liabilities)		314		(9	)		305
Deferred income tax liabilities, net		3,266		(24	)		3,242

Potomac Electric Power Co [Member]

Newly Adopted Accounting Standards

(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Business Combinations (ASC 805)

In November 2014, the FASB issued new recognition and disclosure requirements related to pushdown accounting. The new recognition requirements grant an acquired entity (or its subsidiaries) the option to elect whether and when a new accounting and reporting basis (pushdown accounting) will be applied when an acquirer obtains control of the acquired entity. This election may be made by the acquired entity (or its subsidiaries) for future change-in-control events or for its most recent change-in-control event, and the acquired entity will be required to determine whether pushdown accounting will be applied in the reporting period in which the change-in-control event occurs or in a subsequent reporting period.

The new required disclosures include information that enables financial statement users to evaluate the effects of pushdown accounting. Disclosures are required to be made in the period in which pushdown accounting is applied and are expected to include both qualitative and quantitative information.

The new recognition and disclosure requirements became effective on a prospective basis on November 18, 2014.

Presentation of Debt Issuance Costs (ASC 835)

In April 2015, the FASB issued new guidance for the presentation of debt issuance costs on the balance sheet. Debt issuance costs are currently required to be presented on the balance sheet as assets. However, under the new requirements, these debt issuance costs will be offset against the debt to which the costs relate. The new requirements are effective for Pepco beginning January 1, 2016, and are required to be implemented on a retrospective basis for all periods presented; however, early adoption is permitted. Pepco has elected to early adopt the new guidance in the fourth quarter of 2015. The table below illustrates the effects of the retrospective application on reported balances in Pepco’s balance sheet as of December 31, 2014.

	December 31, 2014 As Filed		Reclassification ASC 835			December 31, 2014 As Adjusted
	(millions of dollars)
Other (within other assets)	$	71	$	(28	)	$	43
Long-term debt		2,124		(28	)		2,096

Balance Sheet Classification of Deferred Taxes (ASC 740)

In November 2015, the FASB issued new requirements for the balance sheet classification of deferred taxes. Entities are currently required to present a current and noncurrent deferred tax balance on the balance sheet. Under the new requirements, deferred taxes will only be presented as noncurrent. The new requirements are be effective for PHI beginning January 1, 2017, and may be implemented on either a prospective or retrospective basis; however, early adoption is permitted. PHI has elected to early adopt the new guidance on a retrospective basis in the fourth quarter of 2015. The table below illustrates the effects of the retrospective application on reported balances in Pepco’s balance sheet as of December 31, 2014.

	December 31, 2014 As Filed		Reclassification ASC 740			December 31, 2014 As Adjusted
	(millions of dollars)
Deferred income taxes, net (within current assets)	$	14	$	(14	)	$	—
Other (within current liabilities)		102		(9	)		93
Deferred income tax liabilities, net		1,584		(5	)		1,579

Delmarva Power & Light Co/De [Member]

Newly Adopted Accounting Standards

(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Business Combinations (ASC 805)

In November 2014, the FASB issued new recognition and disclosure requirements related to pushdown accounting. The new recognition requirements grant an acquired entity (or its subsidiaries) the option to elect whether and when a new accounting and reporting basis (pushdown accounting) will be applied when an acquirer obtains control of the acquired entity. This election may be made by the acquired entity (or its subsidiaries) for future change-in-control events or for its most recent change-in-control event, and the acquired entity will be required to determine whether pushdown accounting will be applied in the reporting period in which the change-in-control event occurs or in a subsequent reporting period.

The new required disclosures include information that enables financial statement users to evaluate the effects of pushdown accounting. Disclosures are required to be made in the period in which pushdown accounting is applied and are expected to include both qualitative and quantitative information.

The new recognition and disclosure requirements became effective on a prospective basis on November 18, 2014.

Presentation of Debt Issuance Costs (ASC 835)

In April 2015, the FASB issued new guidance for the presentation of debt issuance costs on the balance sheet. Debt issuance costs are currently required to be presented on the balance sheet as assets. However, under the new requirements, these debt issuance costs will be offset against the debt to which the costs relate. The new requirements are effective for DPL beginning January 1, 2016, and are required to be implemented on a retrospective basis for all periods presented; however, early adoption is permitted. DPL has elected to early adopt the new guidance in the fourth quarter of 2015. The table below illustrates the effects of the retrospective application on reported balances in DPL’s balance sheet as of December 31, 2014.

	December 31, 2014 As Filed		Reclassification ASC 835			December 31, 2014 As Adjusted
	(millions of dollars)
Other (within other assets)	$	12	$	(8	)	$	4
Long-term debt		971		(8	)		963

Balance Sheet Classification of Deferred Taxes (ASC 740)

In November 2015, the FASB issued new requirements for the balance sheet classification of deferred taxes. Entities are currently required to present a current and noncurrent deferred tax balance on the balance sheet. Under the new requirements, deferred taxes will only be presented as noncurrent. The new requirements are effective for PHI beginning January 1, 2017, and may be implemented on either a prospective or retrospective basis; however, early adoption is permitted. PHI has elected to early adopt the new guidance on a retrospective basis in the fourth quarter of 2015. The table below illustrates the effects of the retrospective application on reported balances in DPL’s balance sheet as of December 31, 2014.

	December 31, 2014 As Filed		Reclassification ASC 740			December 31, 2014 As Adjusted
	(millions of dollars)
Deferred income taxes, net (within current assets)	$	16	$	(16	)	$	—
Other (within current liabilities)		42		(1	)		41
Deferred income tax liabilities, net		893		(15	)		878

Atlantic City Electric Co [Member]

Newly Adopted Accounting Standards

(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Business Combinations (ASC 805)

In November 2014, the FASB issued new recognition and disclosure requirements related to pushdown accounting. The new recognition requirements grant an acquired entity (or its subsidiaries) the option to elect whether and when a new accounting and reporting basis (pushdown accounting) will be applied when an acquirer obtains control of the acquired entity. This election may be made by the acquired entity (or its subsidiaries) for future change-in-control events or for its most recent change-in-control event, and the acquired entity will be required to determine whether pushdown accounting will be applied in the reporting period in which the change-in-control event occurs or in a subsequent reporting period.

The new required disclosures include information that enables financial statement users to evaluate the effects of pushdown accounting. Disclosures are required to be made in the period in which pushdown accounting is applied and are expected to include both qualitative and quantitative information.

The new recognition and disclosure requirements became effective on a prospective basis on November 18, 2014.

Presentation of Debt Issuance Costs (ASC 835)

In April 2015, the FASB issued new guidance for the presentation of debt issuance costs on the balance sheet. Debt issuance costs are currently required to be presented on the balance sheet as assets. However, under the new requirements, these debt issuance costs will be offset against the debt to which the costs relate. The new requirements are effective for ACE beginning January 1, 2016, and are required to be implemented on a retrospective basis for all periods presented; however, early adoption is permitted. ACE has elected to early adopt the new guidance in the fourth quarter of 2015. The table below illustrates the effects of the retrospective application on reported balances in ACE’s consolidated balance sheet as of December 31, 2014.

	December 31, 2014 As Filed		Reclassification ASC 835			December 31, 2014 As Adjusted
	(millions of dollars)
Other (within other assets)	$	12	$	(7	)	$	5
Long-term debt		888		(6	)		882
Transition bonds issued by ACE Funding		171		(1	)		170

Balance Sheet Classification of Deferred Taxes (ASC 740)

In November 2015, the FASB issued new requirements for the balance sheet classification of deferred taxes. Entities are currently required to present a current and noncurrent deferred tax balance on the balance sheet. Under the new requirements, deferred taxes will only be presented as noncurrent. The new requirements are effective for PHI beginning January 1, 2017, and may be implemented on either a prospective or retrospective basis; however, early adoption is permitted. PHI has elected to early adopt the new guidance on a retrospective basis in the fourth quarter of 2015. The table below illustrates the effects of the retrospective application on reported balances in ACE’s consolidated balance sheet as of December 31, 2014.

	December 31, 2014 As Filed		Reclassification ASC 740			December 31, 2014 As Adjusted
	(millions of dollars)
Prepaid expenses and other	$	13	$	(10	)	$	3
Deferred income tax liabilities, net		865		(10	)		855

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Recently Issued Accounting Standards, Not Yet Adopted

12 Months Ended

Dec. 31, 2015

Recently Issued Accounting Standards, Not Yet Adopted

(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Revenue from Contracts with Customers (ASC 606)

In May 2014, the FASB issued new recognition and disclosure requirements for revenue from contracts with customers, which supersedes the existing revenue recognition guidance. The new recognition requirements focus on when the customer obtains control of the goods or services, rather than the current risks and rewards model of recognition. The core principle of the new standard is that an entity will recognize revenue when it transfers goods or services to its customers in an amount that reflects the consideration an entity expects to be entitled to for those goods or services. The new disclosure requirements will include information intended to communicate the nature, amount, timing and any uncertainty of revenue and cash flows from applicable contracts, including any significant judgments and changes in judgments and assets recognized from the costs to obtain or fulfill a contract. Entities will generally be required to make more estimates and use more judgment under the new standard.

The new requirements will be effective for PHI beginning January 1, 2018, and may be implemented either retrospectively for all periods presented, or as a cumulative-effect adjustment as of January 1, 2018. Early adoption is permitted, but not before January 1, 2017. PHI is currently evaluating the potential impact of this new guidance on its consolidated financial statements and which implementation approach to select.

Business Combination (ASC 805)

In September 2015, the FASB issued new guidance on adjustments to provisional amounts recognized in a business combination, which are currently recognized on a retrospective basis. Under the new requirements, adjustments will be recognized in the reporting period in which the adjustments are determined. The effects of changes in depreciation, amortization, or other income arising from changes to the provisional amounts, if any, are included in earnings of the reporting period in which the adjustments to the provisional amounts are determined. An entity is also required to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The new requirements will be effective for PHI beginning January 1, 2016, and are required to be implemented on a prospective basis. Early adoption is permitted. PHI currently anticipates it may be affected by the new guidance if its Merger with Exelon is consummated.

Potomac Electric Power Co [Member]

Recently Issued Accounting Standards, Not Yet Adopted

(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Revenue from Contracts with Customers (ASC 606)

In May 2014, the FASB issued new recognition and disclosure requirements for revenue from contracts with customers, which supersedes the existing revenue recognition guidance. The new recognition requirements focus on when the customer obtains control of the goods or services, rather than the current risks and rewards model of recognition. The core principle of the new standard is that an entity will recognize revenue when it transfers goods or services to its customers in an amount that reflects the consideration an entity expects to be entitled to for those goods or services. The new disclosure requirements will include information intended to communicate the nature, amount, timing and any uncertainty of revenue and cash flows from applicable contracts, including any significant judgments and changes in judgments and assets recognized from the costs to obtain or fulfill a contract. Entities will generally be required to make more estimates and use more judgment under the new standard.

The new requirements will be effective for Pepco beginning January 1, 2018, and may be implemented either retrospectively for all periods presented, or as a cumulative-effect adjustment as of January 1, 2018. Early adoption is permitted, but not before January 1, 2017. Pepco is currently evaluating the potential impact of this new guidance on its financial statements and which implementation approach to select.

Business Combination (ASC 805)

In September 2015, the FASB issued new guidance on adjustments to provisional amounts recognized in a business combination, which are currently recognized on a retrospective basis. Under the new requirements, adjustments will be recognized in the reporting period in which the adjustments are determined. The effects of changes in depreciation, amortization, or other income arising from changes to the provisional amounts, if any, are included in earnings of the reporting period in which the adjustments to the provisional amounts are determined. An entity is also required to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The new requirements will be effective for Pepco beginning January 1, 2016, and are required to be implemented on a prospective basis. Early adoption is permitted. Pepco currently anticipates it may be affected by the new guidance if its Merger with Exelon is consummated.

Delmarva Power & Light Co/De [Member]

Recently Issued Accounting Standards, Not Yet Adopted

(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Revenue from Contracts with Customers (ASC 606)

In May 2014, the FASB issued new recognition and disclosure requirements for revenue from contracts with customers, which supersedes the existing revenue recognition guidance. The new recognition requirements focus on when the customer obtains control of the goods or services, rather than the current risks and rewards model of recognition. The core principle of the new standard is that an entity will recognize revenue when it transfers goods or services to its customers in an amount that reflects the consideration an entity expects to be entitled to for those goods or services. The new disclosure requirements will include information intended to communicate the nature, amount, timing and any uncertainty of revenue and cash flows from applicable contracts, including any significant judgments and changes in judgments and assets recognized from the costs to obtain or fulfill a contract. Entities will generally be required to make more estimates and use more judgment under the new standard.

The new requirements will be effective for DPL beginning January 1, 2018, and may be implemented either retrospectively for all periods presented, or as a cumulative-effect adjustment as of January 1, 2018. Early adoption is permitted, but not before January 1, 2017. DPL is currently evaluating the potential impact of this new guidance on its financial statements and which implementation approach to select.

Business Combination (ASC 805)

In September 2015, the FASB issued new guidance on adjustments to provisional amounts recognized in a business combination, which are currently recognized on a retrospective basis. Under the new requirements, adjustments will be recognized in the reporting period in which the adjustments are determined. The effects of changes in depreciation, amortization, or other income arising from changes to the provisional amounts, if any, are included in earnings of the reporting period in which the adjustments to the provisional amounts are determined. An entity is also required to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The new requirements will be effective for DPL beginning January 1, 2016, and are required to be implemented on a prospective basis. Early adoption is permitted. DPL currently anticipates it may be affected by the new guidance if its Merger with Exelon is consummated.

Atlantic City Electric Co [Member]

Recently Issued Accounting Standards, Not Yet Adopted

(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Revenue from Contracts with Customers (ASC 606)

In May 2014, the FASB issued new recognition and disclosure requirements for revenue from contracts with customers, which supersedes the existing revenue recognition guidance. The new recognition requirements focus on when the customer obtains control of the goods or services, rather than the current risks and rewards model of recognition. The core principle of the new standard is that an entity will recognize revenue when it transfers goods or services to its customers in an amount that reflects the consideration an entity expects to be entitled to for those goods or services. The new disclosure requirements will include information intended to communicate the nature, amount, timing and any uncertainty of revenue and cash flows from applicable contracts, including any significant judgments and changes in judgments and assets recognized from the costs to obtain or fulfill a contract. Entities will generally be required to make more estimates and use more judgment under the new standard.

The new requirements will be effective for ACE beginning January 1, 2018, and may be implemented either retrospectively for all periods presented, or as a cumulative-effect adjustment as of January 1, 2018. Early adoption is permitted, but not before January 1, 2017. ACE is currently evaluating the potential impact of this new guidance on its consolidated financial statements and which implementation approach to select.

Business Combination (ASC 805)

In September 2015, the FASB issued new guidance on adjustments to provisional amounts recognized in a business combination, which are currently recognized on a retrospective basis. Under the new requirements, adjustments will be recognized in the reporting period in which the adjustments are determined. The effects of changes in depreciation, amortization, or other income arising from changes to the provisional amounts, if any, are included in earnings of the reporting period in which the adjustments to the provisional amounts are determined. An entity is also required to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The new requirements will be effective for ACE beginning January 1, 2016, and are required to be implemented on a prospective basis. Early adoption is permitted. ACE currently anticipates it may be affected by the new guidance if its Merger with Exelon is consummated.

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Segment Information

12 Months Ended

Dec. 31, 2015

Segment Information

(5) SEGMENT INFORMATION

Pepco Holdings’ management has identified its operating segments at December 31, 2015 as Power Delivery and Pepco Energy Services. In the tables below, the Corporate and Other column is included to reconcile the segment data with consolidated data and includes unallocated Pepco Holdings’ (parent company) capital costs, such as financing costs. During 2013, PHI completed the termination of its interests in its cross-border energy lease investments that had been maintained by PHI through its wholly- owned subsidiary, PCI. As a result, the cross-border energy lease investments, which comprised substantially all of the operations of the former Other Non-Regulated segment, have been accounted for as discontinued operations. The remaining operations of the former Other Non-Regulated segment, which no longer meet the definition of a separate segment for financial reporting purposes, have been included in Corporate and Other. Segment financial information for continuing operations at and for the years ended December 31, 2015, 2014 and 2013, is as follows:

	Year Ended December 31, 2015
	Power Delivery			Pepco Energy Services			Corporate and Other (a)			PHI Consolidated
	(millions of dollars)
Operating Revenue	$	4,805		$	223		$	(5	)	$	5,023
Operating Expenses (b)		4,124	(c)		224			2			4,350
Operating Income (Loss)		681			(1	)		(7	)		673
Interest Expense		238			—			42			280
Other Income		36			1			17	(d)		54
Income Tax Expense (Benefit) (e)		177			(4	)		(44	)		129
Net Income from Continuing Operations		302			4			12			318
Total Assets		14,413			221			1,692			16,326
Construction Expenditures	$	1,196		$	3		$	31		$	1,230

(a) Total Assets in this column includes Pepco Holdings’ goodwill balance of $1.4 billion, all of which is allocated to Power Delivery for purposes of assessing impairment. Total assets also include capital expenditures related to certain hardware and software expenditures which primarily benefit Power Delivery. These expenditures are recorded as incurred in Corporate and Other and are allocated to Power Delivery once the assets are placed in service. Corporate and Other includes intercompany amounts of $(5) million for Operating Revenue, $(4) million for Operating Expenses and $(5) million for Interest Expense.

(b) Includes depreciation and amortization expense of $651 million, consisting of $606 million for Power Delivery, $4 million for Pepco Energy Services and $41 million for Corporate and Other.

(c) Includes $46 million ($27 million after-tax) related to gains on sales of land at Pepco.

(d) Includes $15 million ($10 million after-tax) increase in fair value of preferred stock derivative.

(e) Includes tax benefit of $3 million for Power Delivery, $1 million for Pepco Energy Services and $43 million for Corporate and Other associated with the Global Tax Settlement.

	Year Ended December 31, 2014
	Power Delivery		Pepco Energy Services			Corporate and Other (a)			PHI Consolidated
	(millions of dollars)
Operating Revenue	$	4,607	$	278		$	(7	)	$	4,878
Operating Expenses (b)		3,916		354	(c)		4			4,274
Operating Income (Loss)		691		(76	)		(11	)		604
Interest Expense		226		1			41			268
Other Income		40		2			2			44
Income Tax Expense (Benefit)		185		(36	)		(11	)		138
Net Income (Loss) from Continuing Operations		320		(39	)		(39	)		242
Total Assets		13,636		249			1,704			15,589
Construction Expenditures	$	1,144	$	3		$	76		$	1,223

(a) Total Assets in this column includes Pepco Holdings’ goodwill balance of $1.4 billion, all of which is allocated to Power Delivery for purposes of assessing impairment. Total assets also include capital expenditures related to certain hardware and software expenditures which primarily benefit Power Delivery. These expenditures are recorded as incurred in Corporate and Other and are allocated to Power Delivery once the assets are placed in service. Corporate and Other includes intercompany amounts of $(7) million for Operating Revenue, $(7) million for Operating Expenses and $(4) million for Interest Expense.

(b) Includes depreciation and amortization expense of $549 million, consisting of $511 million for Power Delivery, $7 million for Pepco Energy Services and $31 million for Corporate and Other.

(c) Includes impairment losses of $81 million ($48 million after-tax) associated with Pepco Energy Services’ combined heat and power thermal generating facilities and operations in Atlantic City.

	Year Ended December 31, 2013
	Power Delivery		Pepco Energy Services			Corporate and Other (a)			PHI Consolidated
	(millions of dollars)
Operating Revenue	$	4,472	$	203		$	(9	)	$	4,666
Operating Expenses (b)		3,828		201	(c)		(31	)		3,998
Operating Income		644		2			22			668
Interest Expense		228		1			44			273
Other Income		28		3			3			34
Income Tax Expense (d)		155		1			163	(e)		319
Net Income (Loss) from Continuing Operations		289		3			(182	)		110
Total Assets		12,868		337			1,573			14,778
Construction Expenditures	$	1,194	$	4		$	112		$	1,310

(a) Total Assets in this column includes Pepco Holdings’ goodwill balance of $1.4 billion, all of which is allocated to Power Delivery for purposes of assessing impairment. Total assets also include capital expenditures related to certain hardware and software expenditures which primarily benefit Power Delivery. These expenditures are recorded as incurred in Corporate and Other and are allocated to Power Delivery once the assets are placed in service. Corporate and Other includes intercompany amounts of $(10) million for Operating Revenue, $(9) million for Operating Expenses and $(5) million for Interest Expense.

(b) Includes depreciation and amortization expense of $473 million, consisting of $439 million for Power Delivery, $6 million for Pepco Energy Services and $28 million for Corporate and Other.

(c) Includes impairment losses of $4 million ($3 million after-tax) associated with Pepco Energy Services’ landfill gas-fired electric generation facility.

(d) Includes after-tax interest associated with uncertain and effectively settled tax positions allocated to each member of the consolidated group, including a $12 million interest benefit for Power Delivery and interest expense of $66 million for Corporate and Other.

(e) Includes non-cash charges of $101 million representing the establishment of valuation allowances against certain deferred tax assets of PCI included in Corporate and Other.

Potomac Electric Power Co [Member]

Segment Information

(5) SEGMENT INFORMATION

Pepco operates its business as one regulated utility segment, which includes all of its services as described above.

Delmarva Power & Light Co/De [Member]

Segment Information

(5) SEGMENT INFORMATION

DPL operates its business as one regulated utility segment, which includes all of its services as described above.

Atlantic City Electric Co [Member]

Segment Information

(5) SEGMENT INFORMATION

ACE operates its business as one regulated utility segment, which includes all of its services as described above.

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Goodwill

12 Months Ended

Dec. 31, 2015

Goodwill

(6) GOODWILL

Substantially all of PHI’s goodwill balance as of December 31, 2015 and 2014 was generated by Pepco’s acquisition of Conectiv (now Conectiv, LLC, to be referred to herein as Conectiv) in 2002 and is allocated entirely to the Power Delivery reporting unit based on the aggregation of its regulated public utility company components for purposes of assessing impairment under FASB guidance on goodwill and other intangibles (ASC 350).

PHI performs an annual impairment assessment as of November 1 each year, or more frequently if indicators of potential impairment exist, to determine whether it is more likely than not that the fair value of a reporting unit to which goodwill relates is less than its carrying value. In evaluating goodwill for impairment, PHI first assesses qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. For reporting units in which PHI concludes that it is more likely than not that the fair value is more than its carrying value, goodwill is not considered impaired and PHI is not required to perform the two-step goodwill impairment test. Qualitative factors considered in this assessment include industry and market considerations, including the price per share of PHI common stock, overall financial performance, lack of significant changes in any key inputs to the prior year impairment test, including the discount rate and forecasted cash flows, and other relevant events and factors affecting the reporting unit.

For reporting units in which PHI concludes that it is more likely than not that the fair value is less than its carrying value, PHI performs the first step of the goodwill impairment test, which compares the fair value of the reporting unit to its carrying value. If the fair value of the reporting unit exceeds the carrying value of the net assets assigned to that unit, goodwill is not considered impaired and PHI is not required to perform additional testing. If the carrying value of the net assets assigned to the reporting unit exceeds the fair value of the reporting unit, then PHI must perform the second step of the goodwill impairment test to determine the implied fair value of the reporting unit’s goodwill. If PHI determines during this second step that the carrying value of a reporting unit’s goodwill exceeds its implied fair value, PHI records an impairment loss equal to the difference.

For the annual impairment assessment in 2015, PHI qualitatively determined for its Power Delivery reporting unit that it was more likely than not that fair value exceeded carrying value. As a result, PHI did not perform the two-step goodwill impairment test on the Power Delivery reporting unit.

As of December 31, 2015 and 2014, PHI’s goodwill balance was $1,406 million and $1,407 million, respectively, which is net of accumulated impairment losses of $12 million and $18 million, respectively.

Delmarva Power & Light Co/De [Member]

Goodwill

(6) GOODWILL

All of DPL’s goodwill was generated by its acquisition of Conowingo Power Company in 1995.

DPL performs an annual impairment assessment as of November 1 of each year, or more frequently if indicators of potential impairment exist, to determine whether it is more likely than not that the fair value of the DPL reporting unit to which goodwill relates is less than its carrying value. In evaluating goodwill for impairment, DPL first assesses qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If DPL concludes that it is more likely than not that the fair value is more than its carrying value, goodwill is not considered impaired and DPL is not required to perform the two-step goodwill impairment test. Qualitative factors considered in this assessment include industry and market considerations, overall financial performance, changes in any key inputs to the prior year impairment test, including the discount rate, and other relevant events and factors affecting the reporting unit.

If DPL concludes that it is more likely than not that the fair value is less than its carrying value, DPL performs the first step of the goodwill impairment test, which compares DPL’s fair value to its carrying value. If DPL’s fair value exceeds the carrying value of DPL’s net assets, goodwill is not considered impaired and DPL is not required to perform additional testing. If the carrying value of DPL’s net assets exceeds DPL’s fair value, then DPL must perform the second step of the goodwill impairment test to determine the implied fair value of DPL’s goodwill. If DPL determines during this second step that the carrying value of DPL’s goodwill exceeds its implied fair value, DPL records an impairment loss equal to the difference.

For the annual impairment assessment in 2015, DPL qualitatively determined that it was more likely than not that fair value exceeded carrying value. As a result, DPL did not perform the two-step goodwill impairment test on that reporting unit.

As of December 31, 2015 and 2014, DPL’s goodwill balance was $8 million. There are no accumulated impairment losses.

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Regulatory Matters

12 Months Ended

Dec. 31, 2015

Regulatory Matters

(7) REGULATORY MATTERS

Regulatory Assets and Regulatory Liabilities

The components of Pepco Holdings’ regulatory asset and liability balances at December 31, 2015 and 2014 are as follows:

	2015		2014
	(millions of dollars)
Regulatory Assets
Pension and other postretirement benefit costs	$	910	$	946
Demand-side management costs		403		329
Smart Grid costs		266		261
Recoverable income taxes		224		274
Securitized stranded costs		202		278
Incremental storm restoration costs		43		51
Deferred debt extinguishment costs		36		42
Deferred energy supply costs		32		73
Recoverable workers’ compensation and long-term disability costs		31		30
MAPP abandonment costs		7		33
Deferred losses on gas derivatives		2		4
Other		90		88
Total Regulatory Assets	$	2,246	$	2,409
Regulatory Liabilities
Asset removal costs	$	211	$	250
Reserves for FERC ROE transmission challenges		32		4
Federal and state tax benefits, related to securitized stranded costs		13		8
Deferred income taxes due to customers		12		44
Deferred energy supply costs		11		3
Other		29		34
Total Regulatory Liabilities	$	308	$	343

A description for each category of regulatory assets and regulatory liabilities follows:

Pension and OPEB Costs: Represents unrecognized net actuarial losses and prior service cost (credit) for Pepco Holdings’ defined benefit pension and other postretirement benefit (OPEB) plans that are expected to be recovered by Pepco, DPL and ACE in rates. The utilities have historically included these items as a part of its cost of service in its customer rates. This regulatory asset is adjusted at least annually when the funded status of Pepco Holdings’ defined benefit pension and OPEB plans are re-measured. See Note (9), “Pension and Other Postretirement Benefits,” for more information about the components of the unrecognized pension and OPEB costs. PHI does not earn a return on these regulatory assets.

Demand-Side Management Costs: Represents recoverable costs associated with customer direct load control and energy efficiency and conservation programs in all jurisdictions that are being recovered from customers. These programs are designed to reduce customers’ energy consumption. PHI earns a return on these regulatory assets.

Smart Grid Costs: Represents AMI costs associated with the installation of smart meters and the early retirement of legacy meters throughout Pepco’s and DPL’s service territories that are recoverable from customers. AMI has not been approved by the NJBPU for ACE in New Jersey. PHI generally is deferring carrying charges on these regulatory assets.

Recoverable Income Taxes: Represents amounts recoverable from Power Delivery’s customers for tax benefits applicable to utility operations of Pepco, DPL and ACE previously recognized in income tax expense before the companies were ordered to record the tax benefits as deferred income taxes. As the temporary differences between the financial statement basis and tax basis of assets reverse, the deferred recoverable balances are reversed.

Securitized Stranded Costs: Certain contract termination payments under a contract between ACE and an unaffiliated non-utility generator (NUG) and costs associated with the regulated operations of ACE’s electricity generation business are no longer recoverable through customer rates (collectively referred to as “stranded costs”). The stranded costs are amortized over the life of Transition Bonds issued by Atlantic City Electric Transition Funding LLC (ACE Funding) (Transition Bonds) to securitize the recoverability of these stranded costs. These bonds mature between 2016 and 2023. A customer surcharge is collected by ACE to fund principal and interest payments on the Transition Bonds. PHI earns a return on these regulatory assets.

Incremental Storm Restoration Costs: Represents total incremental storm restoration costs incurred for repair work due to major storm events in 2015, 2012 and 2011, including the June 2015 storm (for DPL and ACE), Hurricane Sandy, the June 2012 derecho, Hurricane Irene and the 2011 severe winter storm (for Pepco), that are recoverable from customers in the Maryland and New Jersey jurisdictions. Pepco’s and DPL’s costs related to Hurricane Sandy, the June 2012 derecho, Hurricane Irene and Pepco’s costs related to the 2011 severe winter storm are being amortized and recovered from customers, each over a five-year period. ACE’s costs related to Hurricane Sandy, the June 2012 derecho and Hurricane Irene are being amortized and recovered from customers, each over a three-year period. PHI does not earn a return on these regulatory assets.

Deferred Debt Extinguishment Costs: Represents deferred costs of debt extinguishment of Pepco, DPL and ACE that are amortized to interest expense and recovered from customers. PHI generally earns a return on these regulatory assets.

Deferred Energy Supply Costs: The regulatory asset represents primarily deferred costs associated with a net under-recovery of Default Electricity Supply costs incurred by Pepco, DPL and ACE that are being or are expected to be recovered from customers. PHI generally earns a return on these regulatory assets. The regulatory liability represents primarily deferred costs associated with a net over-recovery of Default Electricity Supply costs incurred that will be refunded by Pepco, DPL and ACE to customers.

Recoverable Workers’ Compensation and Long-Term Disability Costs: Represents accrued workers’ compensation and long-term disability costs for Pepco, which are recoverable from customers when actual claims are paid to employees. PHI does not earn a return on these regulatory assets.

MAPP Abandonment Costs: Represents abandonment costs incurred in connection with the Mid-Atlantic Power Pathway (MAPP) transmission line construction project which was terminated by PJM Interconnection, LLC (PJM) on August 24, 2012. These regulatory assets are being amortized and recovered in transmission rates through May 2016. PHI generally does not earn a return on these regulatory assets.

Deferred Losses on Gas Derivatives: Represents losses associated with hedges of natural gas purchases that are recoverable from customers through the Gas Cost Rate (GCR) approved by the DPSC. PHI does not earn a return on these regulatory assets.

Other: Represents miscellaneous regulatory assets that generally are being amortized over 1 to 20 years.

Asset Removal Costs: The depreciation rates for Pepco and DPL include a component for removal costs, as approved by the relevant federal and state regulatory commissions. Accordingly, Pepco and DPL have recorded regulatory liabilities for their estimate of the difference between incurred removal costs and the amount of removal costs recovered through depreciation rates.

Reserves for FERC ROE Transmission Challenges: Represents reserves established under a settlement agreement filed with FERC for the resolution of certain challenges filed by a group of complainants of the base return on equity (ROE) currently authorized by FERC for the transmission service that PHI’s utilities provide.

Federal and State Tax Benefits, Related to Securitized Stranded Costs: Securitized stranded costs include a portion attributable to the future tax benefit expected to be realized when the higher tax basis of the generating facilities divested by ACE is deducted for New Jersey state income tax purposes, as well as the future benefit to be realized through the reversal of federal excess deferred taxes. To account for the possibility that these tax benefits may be given to ACE’s customers through lower rates in the future, ACE established a regulatory liability. The regulatory liability related to federal excess deferred taxes will remain until such time as the Internal Revenue Service (IRS) issues its final regulations with respect to normalization of these federal excess deferred taxes.

Deferred Income Taxes Due to Customers: Represents the portions of deferred income tax assets applicable to utility operations of Pepco and DPL that have not been reflected in current customer rates for which future payment to customers is probable. As the temporary differences between the financial statement basis and tax basis of assets reverse, deferred recoverable income taxes are amortized.

Other: Represents miscellaneous regulatory liabilities.

Rate Proceedings

As further described in Note (1), “Organization,” on April 29, 2014, PHI entered into the Merger Agreement with Exelon and Merger Sub. Subject to certain exceptions, prior to the Merger or the termination of the Merger Agreement, PHI and its subsidiaries may not, without the consent of Exelon, initiate, file or pursue any rate cases, other than pursuing the conclusion of certain proceedings, as described below. To date, PHI has not requested such consent from Exelon and has not filed any new distribution base rate cases since entering into the Merger Agreement.

Bill Stabilization Adjustment

Each of PHI’s utility subsidiaries proposed in each of its respective jurisdictions the adoption of a mechanism to decouple retail distribution revenue from the amount of power delivered to retail customers. A decoupling mechanism, the BSA, was approved and implemented for Pepco and DPL electric service in Maryland and for Pepco electric service in the District of Columbia. None of the other jurisdictions have to date adopted decoupling proposals.

Delaware

Electric Distribution Base Rates

In March 2013, DPL submitted an application with the DPSC to increase its electric distribution base rates. The application sought approval of an annual rate increase of approximately $42 million (adjusted by DPL to approximately $39 million on September 20, 2013), based on a requested ROE of 10.25%. The requested rate increase sought to recover expenses associated with DPL’s ongoing investments in reliability enhancement improvements and efforts to maintain safe and reliable service. In August 2014, the DPSC issued a final order in this proceeding providing for an annual increase in DPL’s electric distribution base rates of approximately $15.1 million, based on an ROE of 9.70%. The new rates became effective on May 1, 2014.

In September 2014, DPL filed an appeal with the Delaware Superior Court of the DPSC’s August 2014 order in this proceeding, seeking the court’s review of the DPSC’s decision relating to the recovery of costs associated with one component of employee compensation, certain retirement benefits and credit facility expenses. The Division of the Public Advocate filed a cross-appeal in September 2014, pertaining to the treatment of a prepaid pension expense and other postretirement benefit obligations in base rates. Under the settlement agreement related to the Merger described below in “Merger Approval Proceedings – Delaware,” the parties agreed to suspend the appeal and, if the Merger is completed, to the withdrawal of the appeal and the cross-appeal with prejudice.

Forward Looking Rate Plan

In October 2013, DPL filed a multi-year rate plan, referred to as the Forward Looking Rate Plan (FLRP). As proposed, the FLRP would provide for annual electric distribution base rate increases over a four-year period in the aggregate amount of approximately $56 million. The FLRP as proposed provides the opportunity to achieve estimated earned ROEs of 7.41% and 8.80% in years one and two, respectively, and 9.75% in both years three and four of the plan.

In addition, DPL proposed that as part of the FLRP, in order to provide a higher minimum required standard of reliability for DPL’s customers than that to which DPL is currently subject, the standards by which DPL’s reliability is measured would be made more stringent in each year of the FLRP. DPL has also offered to refund an aggregate of $500,000 to customers in each year of the FLRP that it fails to meet the proposed stricter minimum reliability standards.

In October 2013, the DPSC opened a docket for the purpose of reviewing the details of the FLRP, but stated that it would not address the FLRP until the electric distribution base rate case discussed above was concluded. Although the rate case has been concluded, a schedule for the FLRP docket has not yet been established.

Under the Merger Agreement, DPL is permitted to pursue this matter; however, under the settlement agreement related to the Merger described below in “Merger Approval Proceedings – Delaware,” DPL agreed to withdraw the FLRP if the Merger is completed, without prejudice to the right to make future filings with the DPSC proposing alternative regulatory methodologies that could include, but are not limited to, a multi-year rate plan.

Gas Cost Rates

DPL makes an annual GCR filing with the DPSC for the purpose of allowing DPL to recover natural gas procurement costs through customer rates. In August 2015, DPL made its 2015 GCR filing. The rates proposed in the 2015 GCR filing would result in a GCR decrease of approximately 26%, primarily reflecting lower natural gas prices. On September 22, 2015, the DPSC issued an order allowing DPL to place the new rates into effect on November 1, 2015, subject to refund and pending final DPSC approval.

Under the Merger Agreement, DPL is permitted to continue to file its required annual GCR cases in Delaware.

Maryland

Pepco Electric Distribution Base Rates

2011 Base Rate Proceeding

In December 2011, Pepco submitted an application with the MPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $68.4 million (subsequently adjusted by Pepco to approximately $66.2 million), based on a requested ROE of 10.75%. In July 2012, the MPSC issued an order approving an annual rate increase of approximately $18.1 million, based on an ROE of 9.31%. Among other things, the order also authorized Pepco to recover the actual cost of AMI meters installed during the 2011 test year, stating that cost recovery for AMI deployment will be allowed in future rate cases in which Pepco demonstrates that the system is cost effective. The new rates became effective on July 20, 2012. The Maryland Office of People’s Counsel has sought rehearing on the portion of the order allowing Pepco to recover the costs of AMI meters installed during the test year; that motion remains pending.

2012 Base Rate Proceeding – Phase I

In November 2012, Pepco submitted an application with the MPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $60.8 million, based on a requested ROE of 10.25%. In July 2013, the MPSC issued an order in this proceeding approving an annual rate increase of approximately $27.9 million, based on an ROE of 9.36%. The order excludes the cost of AMI meters from Pepco’s rate base until such time as Pepco demonstrates the cost effectiveness of the AMI system; as a result, costs for AMI meters incurred with respect to the 2012 test year and beyond will be treated as other incremental AMI costs incurred in conjunction with the deployment of the AMI system that are deferred and on which a carrying charge is deferred, but only until such cost effectiveness has been demonstrated and such costs are included in rates. However, MPSC’s July 2012 order issued in connection with Pepco’s 2011 base rate proceeding, which allowed Pepco to recover the costs of meters installed during the 2011 test year for that case, remains in effect.

The July 2013 order also approved a Grid Resiliency Charge, which went into effect on January 1, 2014, for recovery of costs totaling approximately $24.0 million associated with Pepco’s proposed plan to accelerate investments related to certain priority feeders, provided that, before implementing the surcharge, Pepco (i) provides additional information to the MPSC related to performance objectives, milestones and costs, and (ii) makes annual filings with the MPSC thereafter concerning this project, which will permit the MPSC to establish the applicable Grid Resiliency Charge rider for each following year. These conditions have been met. The MPSC rejected certain other cost recovery mechanisms, including Pepco’s proposed reliability performance-based mechanism. The new rates were effective on July 12, 2013.

In July 2013, Pepco filed a notice of appeal of the July 2013 order in the Circuit Court for Baltimore City. Other parties also filed notices of appeal, which were consolidated with Pepco’s appeal. In its appeal, Pepco asserted that the MPSC erred in failing to grant Pepco an adequate ROE, denying a number of other cost recovery mechanisms and limiting Pepco’s test year data to no more than four months of forecasted data in future rate cases. The other parties primarily asserted that the MPSC erred or acted arbitrarily and capriciously in allowing the recovery of certain costs by Pepco, in approving the Grid Resiliency Charge, and in refusing to reduce Pepco’s rate base by known and measurable accumulated depreciation. In November 2014, the Circuit Court issued an order reversing the MPSC’s decision on Pepco’s ROE and directing the MPSC to make more specific findings regarding the impact of improved service reliability and the BSA in calculating Pepco’s ROE. On all other issues that were the subject of an appeal, the Circuit Court affirmed the MPSC’s July 2013 order.

Other parties to this proceeding filed notices of appeal of the Circuit Court’s decision to the Maryland Court of Special Appeals. On December 15, 2015, the Court of Special Appeals issued its decision in this matter (i) affirming the Circuit Court’s decision upholding the MPSC’s decision to approve the use of the Grid Resiliency Charge for Pepco, and (ii) reversing the Circuit Court on the ROE issue, finding that the MPSC’s original ROE of 9.36% was within the zone of reasonableness. Because none of the parties to the proceeding, including Pepco, appealed this Court of Special Appeals decision, the MPSC decision is now final.

2013 Base Rate Proceeding – Phase I

In December 2013, Pepco submitted an application with the MPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $43.3 million (adjusted by Pepco to approximately $37.4 million on April 15, 2014), based on a requested ROE of 10.25%. The requested rate increase sought to recover expenses associated with Pepco’s ongoing investments in reliability enhancement improvements and efforts to maintain safe and reliable service. In July 2014, the MPSC issued an order approving an annual rate increase of approximately $8.75 million, based on an ROE of 9.62%. The new rates became effective on July 4, 2014. In July 2014, Pepco filed a petition for rehearing seeking reconsideration of the recovery of certain expenses, which the MPSC denied by its order issued in November 2014 (described below). In December 2014, Pepco filed a petition for judicial review of this MPSC order with the Circuit Court for Baltimore City. On August 7, 2015, the Circuit Court for Baltimore City affirmed the MPSC’s decision and denied Pepco’s appeal. Pepco has elected not to appeal the decision of the Circuit Court.

2012 and 2013 Base Rate Proceedings – Phase II

In August 2014, the MPSC issued an order establishing a Phase II proceeding in the 2012 base rate case described above (the 2012 Phase II proceeding) to address the tax implications of Pepco’s net operating loss carryforward (NOLC), which had impacted certain of Pepco’s rate adjustments in the 2012 base rate proceeding. Pepco filed a motion to dismiss the 2012 Phase II proceeding, asserting that the MPSC no longer has jurisdiction over the 2012 base rate case due to appeals having been filed by numerous parties. In September 2014, the MPSC issued an order staying the 2012 Phase II proceeding until further notice. In a similar Phase II proceeding in the 2013 base rate case described above, the MPSC issued an order in November 2014 upholding Pepco’s treatment of the NOLC. Although Pepco believes the November 2014 MPSC order should be dispositive of the issues raised in the 2012 Phase II proceeding, the 2012 Phase II proceeding has remained open pending the resolution of all appeals of the 2012 base rate proceeding. Now that the MPSC decision in that proceeding is final, the MPSC will have authority to act on Phase II.

New Jersey

Update and Reconciliation of Certain Under-Recovered Balances

In March 2015, ACE submitted its 2015 annual petition with the NJBPU seeking to reconcile and update (i) charges related to the recovery of above-market costs associated with ACE’s long-term power purchase contracts with the NUGs, and (ii) costs related to surcharges for the New Jersey Societal Benefit Program (a statewide public interest program that is intended to benefit low income customers and address other public policy goals) and for ACE’s uncollected accounts. As filed, the net impact of the proposed changes would have been an annual rate increase of approximately $52.0 million (revised to an increase of approximately $33.9 million on April 17, 2015, based upon updates for actual data through March 31, 2015). On May 19, 2015, the NJBPU approved a stipulation of settlement entered into by the parties providing for a provisional overall annual rate increase of $33.9 million effective June 1, 2015. On September 11, 2015, the NJBPU approved a stipulation of settlement in this proceeding, which made final the provisional rates that were placed into effect as of June 1, 2015, with an adjustment that decreased the rate applicable to the residential class by $1.3 million. This rate increase of approximately $32.6 million will have no effect on ACE’s operating income, since these revenues provide for recovery of deferred costs under an approved deferral mechanism.

On February 1, 2016, ACE submitted its 2016 annual petition with the NJBPU seeking to reconcile and update the same categories of charges and costs described in (i) and (ii) in the above paragraph. The net impact of adjusting the charges as proposed is an overall annual rate increase of approximately $8.8 million, including New Jersey Sales and Use Tax. The matter is pending at the NJBPU and will be updated for January through March 2016 actual data. ACE has requested that the NJBPU place the new rates into effect by June 1, 2016.

Service Extension Contributions Refund Order

In July 2013, in compliance with a 2012 Superior Court of New Jersey Appellate Division (Appellate Division) court decision, the NJBPU released an order requiring utilities to issue refunds to persons or entities that paid non-refundable contributions for utility service extensions to certain areas described as “Areas Not Designated for Growth.” The order is limited to eligible contributions paid between March 20, 2005 and December 20, 2009. ACE is processing the refund requests that meet the eligibility criteria established in the order as they are received. Although ACE estimates that it received approximately $11 million of contributions between March 20, 2005 and December 20, 2009, it is currently unable to reasonably estimate the amount that it may be required to refund using the eligibility criteria established by the order. Since the July 2013 order was released, ACE has paid less than $1 million in refund claims, the validity of each of which is investigated by ACE prior to making any such refunds. In September 2014, the NJBPU commenced a rulemaking proceeding to further implement the directives of the Appellate Division decision. In November 2015, the NJBPU adopted new regulations that remove provisions distinguishing between growth areas and not-for-growth areas and provide formulae for allocating extension costs. At this time, ACE does not expect the amount it is ultimately required to refund will have a material effect on its consolidated financial condition, results of operations or cash flows, as the amount refunded will generally increase the value of ACE’s property, plant and equipment and may ultimately be recovered through depreciation expense and cost of service in future electric distribution base rate cases.

Generic Consolidated Tax Adjustment Proceeding

In January 2013, the NJBPU initiated a generic proceeding to examine whether a consolidated tax adjustment (CTA) should continue to be used, and if so, how it should be calculated in determining a utility’s cost of service. Under the NJBPU’s current policy, when a New Jersey utility is included in a consolidated group income tax return, an allocated amount of any reduction in the consolidated group’s taxes as a result of losses by affiliates is used to reduce the utility’s rate base, upon which the utility earns a return. This policy has negatively impacted ACE’s electric distribution base rate case outcomes and ACE’s position is that the CTA should be eliminated. In an order issued in October 2014, the NJBPU determined that it is appropriate for affected consolidated groups to continue to include a CTA in New Jersey base rate filings, but that the CTA calculation will be modified to limit the look-back period for the calculation to five years, exclude transmission assets from the calculation, and allocate 25 percent of the final CTA amount as a reduction to the distribution revenue requirement. ACE anticipates that this revised methodology will significantly reduce the negative effects of the CTA in future base rate cases. In November 2014, the New Jersey Division of Rate Counsel filed an appeal of the NJBPU’s CTA order in the Appellate Division. No stay of the October 2014 CTA order was requested in connection with the appeal. As such, barring an adverse finding by the Appellate Division, the order is in effect. The appeal remains pending.

FERC Transmission ROE Challenges

In February 2013, the public service commissions and public advocates of the District of Columbia, Maryland, Delaware and New Jersey, as well as the Delaware Municipal Electric Corporation, Inc., filed a joint complaint at FERC against Pepco, DPL and ACE, as well as Baltimore Gas and Electric Company (BGE). The complainants challenged the base ROE and certain protocols regarding the formula rate process associated with the transmission service that the utilities provide. The complainants support an ROE within a zone of reasonableness of 6.78% and 10.33%, and have argued for a base ROE of 8.7%. The base ROE currently authorized by FERC for PHI’s utilities is (i) 11.3% for facilities placed into service after January 1, 2006, and (ii) 10.8% for facilities placed into service prior to 2006. The 10.8% base ROE for facilities placed into service prior to 2006 receives a 50-basis-point incentive adder for being a member of a regional transmission organization. In August 2014, FERC issued an order setting the matters in this proceeding for hearing, but holding the hearing in abeyance pending settlement discussions. The order also (i) directed that the evidence and analysis presented concerning ROE be guided by the new ROE methodology adopted by FERC in another proceeding (discussed below), and (ii) set a 15-month refund period that commenced on February 27, 2013, should a refund result from this proceeding. After settlement discussions among the parties in this matter reached an impasse, the settlement judge, in November 2014, issued an order terminating the settlement discussions and referring the matter to a presiding administrative law judge.

In June 2014, FERC issued an order in a proceeding in which the PHI utilities were not involved, in which it adopted a new ROE methodology for electric utilities. This new methodology replaces the existing one-step discounted cash flow analysis (which incorporates only short-term growth rates) traditionally used to derive ROE for electric utilities with the two-step discounted cash flow analysis (which incorporates both short-term and long-term measures of growth) used for natural gas and oil pipelines. As a result of the August 2014 FERC order discussed in the preceding paragraph, Pepco, DPL and ACE applied an estimated ROE based on the two-step methodology announced by FERC for the 15-month period over which each of their transmission revenues would be subject to refund as a result of the challenge, and recorded estimated reserves for the entire 15-month refund period in the second quarter of 2014.

On December 8, 2014, the parties that filed the February 2013 complaint filed a second complaint against Pepco, DPL, ACE, as well as BGE, regarding the base transmission ROE, seeking a reduction from 10.8% to 8.8%. By order issued on February 9, 2015, FERC established a hearing on the second complaint and established a second 15-month refund period that commenced on December 8, 2014. Consistent with the prior challenge, Pepco, DPL and ACE applied an estimated ROE based on the two-step methodology described above, and in the fourth quarter of 2014 and in the first, second and third quarters of 2015 established reserves for the estimated refund based on the effective date of the second refund period of December 8, 2014. On February 20, 2015, the chief judge issued an order consolidating the two complaint proceedings and established an initial decision issuance deadline of February 29, 2016. On March 2, 2015, the presiding administrative law judge issued an order establishing a procedural schedule for the consolidated proceedings that provided for the hearing to commence on October 20, 2015.

Also during the third quarter of 2015, PHI further evaluated the reserves established for each of the two refund periods and, based on an updated assessment of market conditions, developments in other cases before FERC, litigation risk and other factors, increased its reserves to reflect management’s best estimate of the refund that is expected to result from these consolidated proceedings. A settlement entered into by the parties regarding the protocols (but not the ROE) raised in the February 2013 complaint was submitted to FERC on July 31, 2015 and was approved by FERC in November 2015.

On November 6, 2015, the parties filed a settlement agreement with FERC regarding the ROE. This settlement agreement provides for (i) a base ROE of 10.0%, effective March 8, 2016, to which a 50-basis-point incentive adder will be applied for being a member of a regional transmission organization, and (ii) customer refunds in the amount of approximately $9.5 million, $11.9 million, and $14.2 million for ACE, DPL and Pepco, respectively, covering the two 15-month refund periods described above. In addition, under this settlement agreement, no party may file to change the base ROE or any incentives prior to June 1, 2018. The parties have requested that FERC approve this settlement agreement by March 16, 2016, in order to incorporate the new ROE and applicable refunds into each utility’s 2016 transmission formula rate update. As of December 31, 2015, PHI’s reserves for both of the refund periods totaled $32 million as required under the settlement agreement.

MPSC New Generation Contract Requirement

In April 2012, the MPSC issued an order that requires Maryland electric distribution companies (EDCs) Pepco, DPL and BGE (collectively, the Contract EDCs) to negotiate and enter into a contract with the winning bidder of a competitive bidding process to build one new power plant in the range of 650 to 700 megawatts (MWs) beginning in 2015, in amounts proportional to their relative SOS loads. Under the terms of the order, the winning bidder was to construct a 661 MW natural gas-fired combined cycle generation plant in Waldorf, Maryland, with an originally expected commercial operation date of June 1, 2015 (which is now deferred pending the outcome of the proceedings discussed below), and each of the Contract EDCs was to recover its costs associated with the contract through surcharges on its respective SOS customers.

In response to a complaint filed by a group of generating companies in the PJM region, in September 2013, the U.S. District Court for the District of Maryland (the Federal District Court) issued a ruling that the MPSC’s April 2012 order violated the Supremacy Clause of the U.S. Constitution by attempting to regulate wholesale prices. In contrast, in October 2013, in response to appeals filed by the Contract EDCs and other parties, the Maryland Circuit Court for Baltimore City (the Maryland Circuit Court) upheld the MPSC’s orders requiring the Contract EDCs to enter into the contracts.

In October 2013, the Federal District Court issued an order ruling that the contracts are illegal and unenforceable. The Contract EDCs, the Maryland Office of People’s Counsel and one generating company have appealed the Maryland Circuit Court’s decision to the Maryland Court of Special Appeals. In addition, in November 2013 both the winning bidder and the MPSC appealed the Federal District Court decision to the U.S. Court of Appeals for the Fourth Circuit, which affirmed the decision. In November 2014, the winning bidder and the MPSC each petitioned the U.S. Supreme Court to consider hearing an appeal of the Fourth Circuit decision and, on October 19, 2015, the U.S. Supreme Court agreed to review that decision.

Assuming the contracts, as currently written, become effective following the satisfaction of all relevant conditions, including the completion of the proceedings discussed above, PHI continues to believe that Pepco and DPL may be required to record their proportional share of the contracts as derivative instruments at fair value and record related regulatory assets of approximately the same amount because Pepco and DPL would be entitled to recover any payments under the contracts from SOS customers. PHI, Pepco and DPL have concluded that any accounting for these contracts would not be required until all legal proceedings related to these contracts and the actions of the MPSC in the related proceeding have been resolved.

ACE Standard Offer Capacity Agreements

In April 2011, ACE entered into three Standard Offer Capacity Agreements (SOCAs) by order of the NJBPU, each with a different generation company. ACE entered into the SOCAs under protest, as did the other EDCs in New Jersey, arguing that the EDCs were denied due process and that the SOCAs violated certain of the requirements of the New Jersey law under which the SOCAs were established (the NJ SOCA Law). In October 2013, in light of the decision of the U.S. District Court for the District of New Jersey described below, the state appeals of the NJBPU implementation orders filed by the EDCs and generators were dismissed without prejudice, subject to the parties exercising their appellate rights in the Federal courts.

In February 2011, ACE joined other plaintiffs in an action filed in the U.S. District Court for the District of New Jersey challenging the NJ SOCA Law on the grounds that it violates the Commerce Clause and the Supremacy Clause of the U.S. Constitution. In October 2013, the Federal district court ruled that the NJ SOCA Law is preempted by the Federal Power Act (FPA) and violates the Supremacy Clause, and is therefore null and void. In October 2013, the Federal district court issued an order ruling that the SOCAs are void, invalid and unenforceable, which order was affirmed by the U.S. Court of Appeals for the Third Circuit in September 2014. In November 2014 and December 2014, respectively, one of the generation companies and the NJBPU petitioned the U.S. Supreme Court to consider hearing an appeal of the Third Circuit decision. Although the U.S. Supreme Court agreed to review the Fourth Circuit decision discussed above under “MPSC New Generation Contract Requirement,” it has not yet agreed to review the Third Circuit decision and the petitions for such review remain pending.

ACE terminated one of the three SOCAs effective July 1, 2013 due to the occurrence of an event of default on the part of the generation company counterparty. ACE terminated the remaining two SOCAs effective November 19, 2013, in response to the October 2013 Federal district court decision.

In response to the October 2013 Federal district court order, ACE, in the fourth quarter of 2013, derecognized both the derivative assets (liabilities) for the estimated fair value of the SOCAs and the related regulatory liabilities (assets) that it had established with respect to the SOCAs.

District of Columbia Power Line Undergrounding Initiative

In May 2014, the Council of the District of Columbia enacted the Electric Company Infrastructure Improvement Financing Act of 2014 (the Improvement Financing Act), which provides enabling legislation for the District of Columbia Power Line Undergrounding (DC PLUG) initiative. This $1 billion initiative seeks to selectively place underground some of the District of Columbia’s most outage-prone power lines, which lines and surrounding conduit would be owned and maintained by Pepco.

The Improvement Financing Act provides that: (i) Pepco is to fund approximately $500 million of the estimated cost to complete the DC PLUG initiative, recovering those costs through a surcharge on the electric bills of Pepco District of Columbia customers; (ii) $375 million of the DC PLUG initiative cost is to be financed by the District of Columbia’s issuance of securitized bonds, which bonds will be repaid through a surcharge on the electric bills of Pepco District of Columbia customers that Pepco will collect on behalf of and remit to the District of Columbia; and (iii) the remaining costs up to $125 million are to be covered by the existing capital projects program of the District of Columbia Department of Transportation (DDOT). Pepco will not earn a return on or a return of the cost of the assets funded with the proceeds of the securitized bonds or assets that are constructed by DDOT under its capital projects program, but ownership and responsibility for the operation and maintenance of such assets will be transferred to Pepco for a nominal amount.

In June 2014, Pepco and DDOT filed a Triennial Plan related to the construction of selected underground feeders in the District of Columbia and recovery of Pepco’s investment through a volumetric surcharge (the Triennial Plan), all in accordance with the Improvement Financing Act. In August 2014, Pepco filed an application for the issuance of a financing order to provide for the issuance of the District’s bonds and a volumetric surcharge for the District of Columbia to recover the costs associated with the bond issuance (the DDOT surcharge).

In November 2014, the DCPSC issued an order approving the Triennial Plan, including Pepco’s volumetric surcharge, and issued the financing order, including approval of the DDOT surcharge. Together these orders permit (i) Pepco and DDOT to commence proposed construction under the Triennial Plan; (ii) the District of Columbia to issue the necessary bonds to fund the District of Columbia’s portion of the DC PLUG initiative; and (iii) the establishment of the customer surcharges contemplated by the Improvement Financing Act. In December 2014, a party to the proceeding sought reconsideration from the DCPSC of both decisions. Final decisions denying both requests for reconsideration were issued by the DCPSC on January 22, 2015 and February 2, 2015, respectively.

In March 2015, a party to the DCPSC proceedings filed with the District of Columbia Court of Appeals a petition for review of the order approving the Triennial Plan and the issuance of the financing order. On January 14, 2016, the District of Columbia Court of Appeals affirmed the orders of the DCPSC. On January 27, 2016, the original petitioning party sought rehearing of the District of Columbia Court of Appeals decision. A determination whether the Court of Appeals will rehear the case is still pending.

Separately, in June 2015, an agency of the federal government served by Pepco asserted that the DDOT surcharge constitutes a tax on end users from which the federal government is immune. PHI is currently evaluating the assertion and the resolution of this matter will likely delay implementation of the DC PLUG initiative.

Merger Approval Proceedings

Delaware

On June 18, 2014, Exelon, PHI and DPL, and certain of their respective affiliates, filed an application with the DPSC seeking approval of the Merger. Delaware law requires the DPSC to approve the Merger when it determines that the transaction is in accordance with law, for a proper purpose, and is consistent with the public interest. The DPSC must further find that the successor will continue to provide safe and reliable service, will not terminate or impair existing collective bargaining agreements and will engage in good faith bargaining with organized labor. On February 13, 2015, Exelon, DPL, the DPSC staff, the Division of the Public Advocate and certain other parties filed a settlement agreement with the DPSC, which was amended in April 2015. The DPSC approved the amended settlement agreement at its meeting held on May 19, 2015, memorializing this decision by written order issued on June 2, 2015. The specific grounds for the DPSC’s approval of the Merger, as well as the specific conditions, will be included in an order to be issued by the DPSC after the Merger closes.

District of Columbia

On June 18, 2014, Exelon, PHI and Pepco, and certain of their respective affiliates, filed an application with the DCPSC seeking approval of the Merger. To approve the Merger, the DCPSC must find that the Merger is in the public interest. In an order issued August 22, 2014, the DCPSC stated that to make the determination of whether the transaction is in the public interest, it will analyze the transaction in the context of seven factors to determine whether the transaction balances the interests of shareholders and investors with ratepayers and the community, whether the benefits to shareholders do or do not come at the expense of the ratepayers, and whether the transaction produces a direct and tangible benefit to ratepayers. The seven factors identified by the DCPSC are the effects of the transaction on: (i) ratepayers, shareholders, the financial health of the utility standing alone and as merged, and the local economy; (ii) utility management and administrative operations; (iii) the public safety and the safety and reliability of services; (iv) risks associated with all of the affiliated non-jurisdictional business operations, including nuclear operations, of the applicants; (v) the DCPSC’s ability to regulate the utility effectively following the Merger; (vi) competition in the local retail and wholesale markets that impacts the District and District ratepayers; and (vii) conservation of natural resources and preservation of environmental quality. District of Columbia law does not impose any time limit on the DCPSC’s review of the Merger. The DCPSC held evidentiary hearings in March and April of 2015 and the record was closed on May 27, 2015.

On August 27, 2015, the DCPSC issued a written order denying the application seeking approval of the Merger. On September 28, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, filed an application for reconsideration before the DCPSC. Following the DCPSC’s decision on reconsideration, Exelon and Pepco Holdings have the option of filing further appeals with the DC Court of Appeals.

On October 6, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, entered into the DC Settlement Agreement with the District of Columbia Government, the Office of the People’s Counsel and other parties. Also on October 6, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates filed with the DCPSC the Motion to Reopen requesting consideration of the DC Settlement Agreement and approval of the Merger on such terms and conditions set forth in the DC Settlement Agreement, without condition or modification, and to stay further proceedings on the application for reconsideration filed by the parties on September 28, 2015, and suspend the time period for reconsideration pending the DCPSC’s consideration of the DC Settlement Agreement.

On October 28, 2015, the DCPSC approved the Motion to Reopen and set a procedural schedule for its review of this matter. Upon completion of the public input and evidentiary hearings, the record was closed as of December 23, 2015. Although District of Columbia law does not impose any time limit on the DCPSC’s review of the Merger, the parties requested a decision by March 4, 2016.

Maryland

On August 19, 2014, Exelon, PHI, Pepco, DPL and certain of their respective affiliates, filed an application with the MPSC seeking approval of the Merger. Maryland law requires the MPSC to approve a merger subject to its review if it finds that the merger is consistent with the public interest, convenience and necessity, including its benefits to and impact on consumers. Evidentiary hearings were held beginning on January 26, 2015. On March 10, 2015, Exelon, PHI, Pepco, DPL and certain of their respective affiliates, filed with the MPSC a settlement agreement entered into with one of the stakeholder groups participating in the MPSC approval proceeding. On March 16, 2015, Exelon, PHI, Pepco, DPL and certain of their respective affiliates, filed with the MPSC a settlement agreement entered into with Montgomery and Prince George’s Counties in Maryland, and a number of other parties. On May 15, 2015, the MPSC approved the Merger, with conditions, including conditions that modify and supplement those originally proposed. On May 18, 2015, Pepco Holdings and Exelon announced that they had completed their review of the MPSC’s order approving the Merger and have committed to fulfill the modified, more stringent conditions and package of customer benefits imposed by the MPSC.

Multiple parties have filed petitions for judicial review of the MPSC order by the Circuit Court of Queen Anne’s County, Maryland, seeking to appeal the MPSC order. In connection with these proceedings, the Maryland Office of People’s Counsel and several other parties to the Merger proceedings filed motions in the Circuit Court for Queen Anne’s County, Maryland, requesting a stay of the MPSC order. On August 7, 2015, the Circuit Court for Queen Anne’s County denied the motions for stay. On January 8, 2016, the Circuit Court affirmed the MPSC’s order in all respects. On January 20 and 22, 2016, respectively, the Maryland Office of People’s Counsel and environmental groups filed notices of appeal of the Circuit Court’s order to the Maryland Court of Special Appeals. Unless a motion to stay is filed and then granted by the court, the MPSC order will remain in effect during the appeals process.

New Jersey

On June 18, 2014, Exelon, PHI and ACE, and certain of their respective affiliates, filed a petition with the NJBPU seeking approval of the Merger. To approve the Merger, the NJBPU must find the Merger is in the public interest, and consider the impact of the Merger on (i) competition, (ii) rates of ratepayers affected by the Merger, (iii) ACE’s employees, and (iv) the provision of safe and reliable service at just and reasonable rates. On January 14, 2015, PHI, ACE, Exelon, certain of Exelon’s affiliates, the Staff of the NJBPU, and the Independent Energy Producers of New Jersey filed a stipulation of settlement (the Stipulation) with the NJBPU in this proceeding. On February 11, 2015, the NJBPU approved the Stipulation and the Merger and on March 6, 2015, the NJBPU issued a written order approving the Stipulation.

The NJBPU order states that the Merger must be closed by November 1, 2015 unless extended by the NJBPU. On October 15, 2015, the NJBPU voted to extend the effectiveness of its Merger approval until June 30, 2016.

Virginia

On June 3, 2014, Exelon, PHI, Pepco and DPL, and certain of their respective affiliates, filed an application with the VSCC seeking approval of the Merger. Virginia law provides that, if the VSCC determines, with or without hearing, that adequate service to the public at just and reasonable rates will not be impaired or jeopardized by granting the application for approval, then the VSCC shall approve a merger with such conditions that the VSCC deems to be appropriate in order to satisfy this standard. On October 7, 2014,

the VSCC issued an order approving the Merger.

Federal Energy Regulatory Commission

On May 30, 2014, Exelon, PHI, Pepco, DPL and ACE, and certain of their respective affiliates, submitted to FERC a Joint Application for Authorization of Disposition of Jurisdictional Assets and Merger under Section 203 of the FPA. Under that section, FERC shall approve a merger if it finds that the proposed transaction will be consistent with the public interest. On November 20, 2014, FERC issued an order approving the Merger.

Hart-Scott-Rodino Act

The HSR Act, which is the U.S. federal pre-merger notification statute, and its related rules and regulations provide that acquisition transactions that meet the HSR Act’s coverage thresholds may not be completed until a Notification and Report Form has been furnished to the Department of Justice (DOJ) and the Federal Trade Commission (FTC), and that the waiting period required by the HSR Act has been terminated or has expired. Pursuant to the HSR Act requirements, Pepco Holdings and Exelon filed the required Notification and Report Forms with the DOJ and the FTC, and the waiting period under the HSR Act expired on December 2, 2015, which allows for the closing of the Merger at any time on or before December 1, 2016.

Potomac Electric Power Co [Member]

Regulatory Matters

(6) REGULATORY MATTERS

Regulatory Assets and Regulatory Liabilities

The components of Pepco’s regulatory asset and liability balances at December 31, 2015 and 2014 are as follows:

	2015		2014
	(millions of dollars)
Regulatory Assets
Demand-side management costs	$	292	$	238
Smart Grid costs		181		175
Recoverable income taxes		142		148
Recoverable workers’ compensation and long-term disability costs		31		30
Incremental storm restoration costs		19		29
Deferred debt extinguishment costs		19		22
MAPP abandonment costs		4		19
Deferred energy supply costs		3		3
Other		29		33
Total Regulatory Assets	$	720	$	697
Regulatory Liabilities
Asset removal costs	$	58	$	84
Reserves for FERC ROE transmission challenges		13		2
Deferred income taxes due to customers		6		4
Deferred energy supply costs		5		3
Other		10		11
Total Regulatory Liabilities	$	92	$	104

A description for each category of regulatory assets and regulatory liabilities follows:

Demand-Side Management Costs: Represents recoverable costs associated with customer direct load control and energy efficiency and conservation programs in all jurisdictions that are being recovered from customers. These programs are designed to reduce customer’s energy consumption. Pepco earns a return on these regulatory assets.

Smart Grid Costs: Represents advanced metering infrastructure (AMI) costs associated with the installation of smart meters and the early retirement of legacy meters throughout Pepco’s service territory that are recoverable from customers. Pepco generally is deferring carrying charges on these regulatory assets.

Recoverable Income Taxes: Represents amounts recoverable from Pepco’s customers for tax benefits applicable to utility operations that were previously recognized in income tax expense before the company was ordered to record the tax benefits as deferred income taxes. As the temporary differences between the financial statement basis and tax basis of assets reverse, the deferred recoverable balances are reversed.

Recoverable Workers’ Compensation and Long-Term Disability Costs: Represents accrued workers’ compensation and long-term disability costs for Pepco, which are recoverable from customers when actual claims are paid to employees. Pepco does not earn a return on these regulatory assets.

Incremental Storm Restoration Costs: Represents total incremental storm restoration costs incurred for repair work due to major storm events in 2012 and 2011, including Hurricane Sandy, the June 2012 derecho, Hurricane Irene, and the 2011 severe winter storm, that are recoverable from customers in the Maryland jurisdiction. Pepco’s costs related to Hurricane Sandy, the June 2012 derecho, Hurricane Irene and the 2011 severe winter storm are being amortized and recovered from customers, each over a five-year period. Pepco does not earn a return on these regulatory assets.

Deferred Debt Extinguishment Costs: Represents deferred costs of debt extinguishment that are amortized to interest expense and recovered from customers. Pepco generally earns a return on these regulatory assets.

MAPP Abandonment Costs: Represents abandonment costs incurred in connection with the Mid-Atlantic Power Pathway (MAPP) transmission line construction project which was terminated by PJM Interconnection, LLC (PJM) on August 24, 2012. These regulatory assets are being amortized and recovered in transmission rates through May 2016. Pepco generally does not earn a return on these regulatory assets.

Deferred Energy Supply Costs: The regulatory asset represents primarily deferred costs associated with a net under-recovery of Default Electricity Supply costs incurred by Pepco and are being or are expected to be recovered from customers. Pepco does not earn a return on these regulatory assets. The regulatory liability represents primarily deferred costs associated with a net over-recovery of Default Electricity Supply costs incurred that will be refunded by Pepco to customers.

Other: Represents miscellaneous regulatory assets that generally are being amortized over 1 to 20 years.

Asset Removal Costs: The depreciation rates for Pepco include a component for removal costs, as approved by the relevant federal and state regulatory commissions. Accordingly, Pepco has recorded regulatory liabilities for its estimate of the difference between incurred removal costs and the amount of removal costs recovered through depreciation rates.

Reserves for FERC ROE Transmission Challenges: Represents reserves established under a settlement agreement filed with FERC for the resolution of certain challenges filed by a group of complainants of the base return on equity (ROE) currently authorized by FERC for the transmission service that Pepco provides.

Deferred Income Taxes Due to Customers: Represents the portions of deferred income tax assets applicable to utility operations of Pepco that have not been reflected in current customer rates for which future payment to customers is probable. As the temporary differences between the financial statement basis and tax basis of assets reverse, deferred recoverable income taxes are amortized.

Other: Represents miscellaneous regulatory liabilities.

Rate Proceedings

As further described in Note (1), “Organization,” on April 29, 2014, PHI entered into the Merger Agreement with Exelon and Merger Sub. Subject to certain exceptions, prior to the Merger or the termination of the Merger Agreement, PHI and its subsidiaries may not, without the consent of Exelon, initiate, file or pursue any rate cases, other than pursuing the conclusion of certain proceedings, as described below. To date, Pepco has not requested such consent from Exelon and has not filed any new distribution base rate cases since entering into the Merger Agreement.

Bill Stabilization Adjustment

A decoupling mechanism, the BSA, was approved and implemented for Pepco electric service in Maryland and in the District of Columbia.

Maryland

Pepco Electric Distribution Base Rates

2011 Base Rate Proceeding

In December 2011, Pepco submitted an application with the MPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $68.4 million (subsequently adjusted by Pepco to approximately $66.2 million), based on a requested ROE of 10.75%. In July 2012, the MPSC issued an order approving an annual rate increase of approximately $18.1 million, based on an ROE of 9.31%. Among other things, the order also authorized Pepco to recover the actual cost of AMI meters installed during the 2011 test year, stating that cost recovery for AMI deployment will be allowed in future rate cases in which Pepco demonstrates that the system is cost effective. The new rates became effective on July 20, 2012. The Maryland Office of People’s Counsel has sought rehearing on the portion of the order allowing Pepco to recover the costs of AMI meters installed during the test year; that motion remains pending.

2012 Base Rate Proceeding – Phase I

In November 2012, Pepco submitted an application with the MPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $60.8 million, based on a requested ROE of 10.25%. In July 2013, the MPSC issued an order in this proceeding approving an annual rate increase of approximately $27.9 million, based on an ROE of 9.36%. The order excludes the cost of AMI meters from Pepco’s rate base until such time as Pepco demonstrates the cost effectiveness of the AMI system; as a result, costs for AMI meters incurred with respect to the 2012 test year and beyond will be treated as other incremental AMI costs incurred in conjunction with the deployment of the AMI system that are deferred and on which a carrying charge is deferred, but only until such cost effectiveness has been demonstrated and such costs are included in rates. However, MPSC’s July 2012 order issued in connection with Pepco’s 2011 base rate proceeding, which allowed Pepco to recover the costs of meters installed during the 2011 test year for that case, remains in effect.

The July 2013 order also approved a Grid Resiliency Charge, which went into effect on January 1, 2014, for recovery of costs totaling approximately $24.0 million associated with Pepco’s proposed plan to accelerate investments related to certain priority feeders, provided that, before implementing the surcharge, Pepco (i) provides additional information to the MPSC related to performance objectives, milestones and costs, and (ii) makes annual filings with the MPSC thereafter concerning this project, which will permit the MPSC to establish the applicable Grid Resiliency Charge rider for each following year. These conditions have been met. The MPSC rejected certain other cost recovery mechanisms, including Pepco’s proposed reliability performance-based mechanism. The new rates were effective on July 12, 2013.

In July 2013, Pepco filed a notice of appeal of the July 2013 order in the Circuit Court for Baltimore City. Other parties also filed notices of appeal, which were consolidated with Pepco’s appeal. In its appeal, Pepco asserted that the MPSC erred in failing to grant Pepco an adequate ROE, denying a number of other cost recovery mechanisms and limiting Pepco’s test year data to no more than four months of forecasted data in future rate cases. The other parties primarily asserted that the MPSC erred or acted arbitrarily and capriciously in allowing the recovery of certain costs by Pepco, in approving the Grid Resiliency Charge, and in refusing to reduce Pepco’s rate base by known and measurable accumulated depreciation. In November 2014, the Circuit Court issued an order reversing the MPSC’s decision on Pepco’s ROE and directing the MPSC to make more specific findings regarding the impact of improved service reliability and the BSA in calculating Pepco’s ROE. On all other issues that were the subject of an appeal, the Circuit Court affirmed the MPSC’s July 2013 order.

Other parties to this proceeding filed notices of appeal of the Circuit Court’s decision to the Maryland Court of Special Appeals. On December 15, 2015, the Court of Special Appeals issued its decision in this matter (i) affirming the Circuit Court’s decision upholding the MPSC’s decision to approve the use of the Grid Resiliency Charge for Pepco, and (ii) reversing the Circuit Court on the ROE issue, finding that the MPSC’s original ROE of 9.36% was within the zone of reasonableness. Because none of the parties to the proceeding, including Pepco, appealed this Court of Special Appeals decision, the MPSC decision is now final.

2013 Base Rate Proceeding – Phase I

In December 2013, Pepco submitted an application with the MPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $43.3 million (adjusted by Pepco to approximately $37.4 million on April 15, 2014), based on a requested ROE of 10.25%. The requested rate increase sought to recover expenses associated with Pepco’s ongoing investments in reliability enhancement improvements and efforts to maintain safe and reliable service. In July 2014, the MPSC issued an order approving an annual rate increase of approximately $8.75 million, based on an ROE of 9.62%. The new rates became effective on July 4, 2014. In July 2014, Pepco filed a petition for rehearing seeking reconsideration of the recovery of certain expenses, which the MPSC denied by its order issued in November 2014 (described below). In December 2014, Pepco filed a petition for judicial review of this MPSC order with the Circuit Court for Baltimore City. On August 7, 2015, the Circuit Court for Baltimore City affirmed the MPSC’s decision and denied Pepco’s appeal. Pepco has elected not to appeal the decision of the Circuit Court.

2012 and 2013 Base Rate Proceedings – Phase II

In August 2014, the MPSC issued an order establishing a Phase II proceeding in the 2012 base rate case described above (the 2012 Phase II proceeding) to address the tax implications of Pepco’s net operating loss carryforward (NOLC), which had impacted certain of Pepco’s rate adjustments in the 2012 base rate proceeding. Pepco filed a motion to dismiss the 2012 Phase II proceeding, asserting that the MPSC no longer has jurisdiction over the 2012 base rate case due to appeals having been filed by numerous parties. In September 2014, the MPSC issued an order staying the 2012 Phase II proceeding until further notice. In a similar Phase II proceeding in the 2013 base rate case described above, the MPSC issued an order in November 2014 upholding Pepco’s treatment of the NOLC. Although Pepco believes the November 2014 MPSC order should be dispositive of the issues raised in the 2012 Phase II proceeding, the 2012 Phase II proceeding has remained open pending the resolution of all appeals of the 2012 base rate proceeding. Now that the MPSC decision in that proceeding is final, the MPSC will have authority to act on Phase II.

FERC Transmission ROE Challenges

In February 2013, the public service commissions and public advocates of the District of Columbia, Maryland, Delaware and New Jersey, as well as the Delaware Municipal Electric Corporation, Inc., filed a joint complaint at FERC against Pepco and its affiliates, Delmarva Power & Light Company (DPL) and Atlantic City Electric Company (ACE), as well as Baltimore Gas and Electric Company (BGE). The complainants challenged the base ROE and certain protocols regarding the formula rate process associated with the transmission service that the utilities provide. The complainants support an ROE within a zone of reasonableness of 6.78% and 10.33%, and have argued for a base ROE of 8.7%. The base ROE currently authorized by FERC for PHI’s utilities is (i) 11.3% for facilities placed into service after January 1, 2006, and (ii) 10.8% for facilities placed into service prior to 2006. The 10.8% base ROE for facilities placed into service prior to 2006 receives a 50-basis-point incentive adder for being a member of a regional transmission organization. In August 2014, FERC issued an order setting the matters in this proceeding for hearing, but holding the hearing in abeyance pending settlement discussions. The order also (i) directed that the evidence and analysis presented concerning ROE be guided by the new ROE methodology adopted by FERC in another proceeding (discussed below), and (ii) set a 15-month refund period that commenced on February 27, 2013, should a refund result from this proceeding. After settlement discussions among the parties in this matter reached an impasse, the settlement judge, in November 2014, issued an order terminating the settlement discussions and referring the matter to a presiding administrative law judge.

In June 2014, FERC issued an order in a proceeding in which Pepco was not involved, in which it adopted a new ROE methodology for electric utilities. This new methodology replaces the existing one-step discounted cash flow analysis (which incorporates only short-term growth rates) traditionally used to derive ROE for electric utilities with the two-step discounted cash flow analysis (which incorporates both short-term and long-term measures of growth) used for natural gas and oil pipelines. As a result of the August 2014 FERC order discussed in the preceding paragraph, Pepco applied an estimated ROE based on the two-step methodology announced by FERC for the 15-month period over which its transmission revenues would be subject to refund as a result of the challenge, and recorded estimated reserves for the entire 15-month refund period in the second quarter of 2014.

On December 8, 2014, the parties that filed the February 2013 complaint filed a second complaint against Pepco, DPL, ACE, as well as BGE, regarding the base transmission ROE, seeking a reduction from 10.8% to 8.8%. By order issued on February 9, 2015, FERC established a hearing on the second complaint and established a second 15-month refund period that commenced on December 8, 2014. Consistent with the prior challenge, Pepco applied an estimated ROE based on the two-step methodology described above, and in the fourth quarter of 2014 and in the first, second and third quarters of 2015 established reserves for the estimated refund based on the effective date of the second refund period of December 8, 2014. On February 20, 2015, the chief judge issued an order consolidating the two complaint proceedings and established an initial decision issuance deadline of February 29, 2016. On March 2, 2015, the presiding administrative law judge issued an order establishing a procedural schedule for the consolidated proceedings that provided for the hearing to commence on October 20, 2015.

Also during the third quarter of 2015, Pepco further evaluated the reserves established for each of the two refund periods and, based on an updated assessment of market conditions, developments in other cases before FERC, litigation risk and other factors, increased its reserves to reflect management’s best estimate of the refund that is expected to result from these consolidated proceedings. A settlement entered into by the parties regarding the protocols (but not the ROE) raised in the February 2013 complaint was submitted to FERC on July 31, 2015 and was approved by FERC in November 2015.

On November 6, 2015, the parties filed a settlement agreement with FERC regarding the ROE. This settlement agreement provides for (i) a base ROE of 10.0%, effective March 8, 2016, to which a 50-basis-point incentive adder will be applied for being a member of a regional transmission organization, and (ii) customer refunds in the amount of approximately $14.2 million for Pepco covering the two 15-month refund periods described above. In addition, under this settlement agreement, no party may file to change the base ROE or any incentives prior to June 1, 2018. The parties have requested that FERC approve this settlement agreement by March 16, 2016, in order to incorporate the new ROE and applicable refunds into each utility’s 2016 transmission formula rate update. As of December 31, 2015, Pepco’s reserves for both of the refund periods totaled $13 million as required under the settlement agreement.

MPSC New Generation Contract Requirement

In April 2012, the MPSC issued an order that requires Maryland electric distribution companies (EDCs) Pepco, DPL and BGE (collectively, the Contract EDCs) to negotiate and enter into a contract with the winning bidder of a competitive bidding process to build one new power plant in the range of 650 to 700 megawatts (MWs) beginning in 2015, in amounts proportional to their relative standard offer service (SOS) loads. Under the terms of the order, the winning bidder was to construct a 661 MW natural gas-fired combined cycle generation plant in Waldorf, Maryland, with an originally expected commercial operation date of June 1, 2015 (which is now deferred pending the outcome of the proceedings discussed below), and each of the Contract EDCs was to recover its costs associated with the contract through surcharges on its respective SOS customers.

In response to a complaint filed by a group of generating companies in the PJM region, in September 2013, the U.S. District Court for the District of Maryland (the Federal District Court) issued a ruling that the MPSC’s April 2012 order violated the Supremacy Clause of the U.S. Constitution by attempting to regulate wholesale prices. In contrast, in October 2013, in response to appeals filed by the Contract EDCs and other parties, the Maryland Circuit Court for Baltimore City (the Maryland Circuit Court) upheld the MPSC’s orders requiring the Contract EDCs to enter into the contracts.

In October 2013, the Federal District Court issued an order ruling that the contracts are illegal and unenforceable. The Contract EDCs, the Maryland Office of People’s Counsel and one generating company have appealed the Maryland Circuit Court’s decision to the Maryland Court of Special Appeals. In addition, in November 2013 both the winning bidder and the MPSC appealed the Federal District Court decision to the U.S. Court of Appeals for the Fourth Circuit, which affirmed the decision. In November 2014, the winning bidder and the MPSC each petitioned the U.S. Supreme Court to consider hearing an appeal of the Fourth Circuit decision and, on October 19, 2015, the U.S. Supreme Court agreed to review that decision.

Assuming the contracts, as currently written, become effective following the satisfaction of all relevant conditions, including the completion of the proceedings discussed above, Pepco continues to believe that it may be required to record its proportional share of the contracts as derivative instruments at fair value and record related regulatory assets of approximately the same amount because it would be entitled to recover any payments under the contracts from SOS customers. Pepco has concluded that any accounting for these contracts would not be required until all legal proceedings related to these contracts and the actions of the MPSC in the related proceeding have been resolved.

District of Columbia Power Line Undergrounding Initiative

In May 2014, the Council of the District of Columbia enacted the Electric Company Infrastructure Improvement Financing Act of 2014 (the Improvement Financing Act), which provides enabling legislation for the District of Columbia Power Line Undergrounding (DC PLUG) initiative. This $1 billion initiative seeks to selectively place underground some of the District of Columbia’s most outage-prone power lines, which lines and surrounding conduit would be owned and maintained by Pepco.

The Improvement Financing Act provides that: (i) Pepco is to fund approximately $500 million of the estimated cost to complete the DC PLUG initiative, recovering those costs through a surcharge on the electric bills of Pepco District of Columbia customers; (ii) $375 million of the DC PLUG initiative cost is to be financed by the District of Columbia’s issuance of securitized bonds, which bonds will be repaid through a surcharge on the electric bills of Pepco District of Columbia customers that Pepco will collect on behalf of and remit to the District of Columbia; and (iii) the remaining costs up to $125 million are to be covered by the existing capital projects program of the District of Columbia Department of Transportation (DDOT). Pepco will not earn a return on or a return of the cost of the assets funded with the proceeds of the securitized bonds or assets that are constructed by DDOT under its capital projects program, but ownership and responsibility for the operation and maintenance of such assets will be transferred to Pepco for a nominal amount.

In June 2014, Pepco and DDOT filed a Triennial Plan related to the construction of selected underground feeders in the District of Columbia and recovery of Pepco’s investment through a volumetric surcharge (the Triennial Plan), all in accordance with the Improvement Financing Act. In August 2014, Pepco filed an application for the issuance of a financing order to provide for the issuance of the District’s bonds and a volumetric surcharge for the District of Columbia to recover the costs associated with the bond issuance (the DDOT surcharge).

In November 2014, the DCPSC issued an order approving the Triennial Plan, including Pepco’s volumetric surcharge, and issued the financing order, including approval of the DDOT surcharge. Together these orders permit (i) Pepco and DDOT to commence proposed construction under the Triennial Plan; (ii) the District of Columbia to issue the necessary bonds to fund the District of Columbia’s portion of the DC PLUG initiative; and (iii) the establishment of the customer surcharges contemplated by the Improvement Financing Act. In December 2014, a party to the proceeding sought reconsideration from the DCPSC of both decisions. Final decisions denying both requests for reconsideration were issued by the DCPSC on January 22, 2015 and February 2, 2015, respectively.

In March 2015, a party to the DCPSC proceedings filed with the District of Columbia Court of Appeals a petition for review of the order approving the Triennial Plan and the issuance of the financing order. On January 14, 2016, the District of Columbia Court of Appeals affirmed the orders of the DCPSC. On January 27, 2016, the original petitioning party sought rehearing of the District of Columbia Court of Appeals decision. A determination whether the Court of Appeals will rehear the case is pending.

Separately, in June 2015, an agency of the federal government served by Pepco asserted that the DDOT surcharge constitutes a tax on end users from which the federal government is immune. PHI is currently evaluating the assertion and the resolution of this matter will likely delay implementation of the DC PLUG initiative.

Merger Approval Proceedings

District of Columbia

On June 18, 2014, Exelon, PHI and Pepco, and certain of their respective affiliates, filed an application with the DCPSC seeking approval of the Merger. To approve the Merger, the DCPSC must find that the Merger is in the public interest. In an order issued August 22, 2014, the DCPSC stated that to make the determination of whether the transaction is in the public interest, it will analyze the transaction in the context of seven factors to determine whether the transaction balances the interests of shareholders and investors with ratepayers and the community, whether the benefits to shareholders do or do not come at the expense of the ratepayers, and whether the transaction produces a direct and tangible benefit to ratepayers. The seven factors identified by the DCPSC are the effects of the transaction on: (i) ratepayers, shareholders, the financial health of the utility standing alone and as merged, and the local economy; (ii) utility management and administrative operations; (iii) the public safety and the safety and reliability of services; (iv) risks associated with all of the affiliated non-jurisdictional business operations, including nuclear operations, of the applicants; (v) the DCPSC’s ability to regulate the utility effectively following the Merger; (vi) competition in the local retail and wholesale markets that impacts the District and District ratepayers; and (vii) conservation of natural resources and preservation of environmental quality. District of Columbia law does not impose any time limit on the DCPSC’s review of the Merger. The DCPSC held evidentiary hearings in March and April of 2015 and the record was closed on May 27, 2015.

On August 27, 2015, the DCPSC issued a written order denying the application seeking approval of the Merger. On September 28, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, filed an application for reconsideration before the DCPSC. Following the DCPSC’s decision on reconsideration, Exelon and Pepco Holdings have the option of filing further appeals with the DC Court of Appeals.

On October 6, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, entered into the DC Settlement Agreement with the District of Columbia Government, the Office of the People’s Counsel and other parties. Also on October 6, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates filed with the DCPSC the Motion to Reopen requesting consideration of the DC Settlement Agreement and approval of the Merger on such terms and conditions set forth in the DC Settlement Agreement, without condition or modification, and to stay further proceedings on the application for reconsideration filed by the parties on September 28, 2015, and suspend the time period for reconsideration pending the DCPSC’s consideration of the DC Settlement Agreement.

On October 28, 2015, the DCPSC approved the Motion to Reopen and set a procedural schedule for its review of this matter. Upon completion of the public input and evidentiary hearings, the record was closed as of December 23, 2015. Although District of Columbia law does not impose any time limit on the DCPSC’s review of the Merger, the parties requested a decision by March 4, 2016.

Maryland

On August 19, 2014, Exelon, PHI, Pepco, DPL and certain of their respective affiliates, filed an application with the MPSC seeking approval of the Merger. Maryland law requires the MPSC to approve a merger subject to its review if it finds that the merger is consistent with the public interest, convenience and necessity, including its benefits to and impact on consumers. Evidentiary hearings were held beginning on January 26, 2015. On March 10, 2015, Exelon, PHI, Pepco, DPL and certain of their respective affiliates, filed with the MPSC a settlement agreement entered into with one of the stakeholder groups participating in the MPSC approval proceeding. On March 16, 2015, Exelon, PHI, Pepco, DPL and certain of their respective affiliates, filed with the MPSC a settlement agreement entered into with Montgomery and Prince George’s Counties in Maryland, and a number of other parties. On May 15, 2015, the MPSC approved the Merger, with conditions, including conditions that modify and supplement those originally proposed. On May 18, 2015, Pepco Holdings and Exelon announced that they had completed their review of the MPSC’s order approving the Merger and have committed to fulfill the modified, more stringent conditions and package of customer benefits imposed by the MPSC.

Multiple parties have filed petitions for judicial review of the MPSC order by the Circuit Court of Queen Anne’s County, Maryland, seeking to appeal the MPSC order. In connection with these proceedings, the Maryland Office of People’s Counsel and several other parties to the Merger proceedings filed motions in the Circuit Court for Queen Anne’s County, Maryland, requesting a stay of the MPSC order. On August 7, 2015, the Circuit Court for Queen Anne’s County denied the motions for stay. On January 8, 2016, the Circuit Court affirmed the MPSC’s order in all respects. On January 20 and 22, 2016, respectively, the Maryland Office of People’s Counsel and environmental groups filed notices of appeal of the Circuit Court’s order to the Maryland Court of Special Appeals. Unless a motion to stay is filed and then granted by the court, the MPSC order will remain in effect during the appeals process.

Virginia

On June 3, 2014, Exelon, PHI, Pepco and DPL, and certain of their respective affiliates, filed an application with the VSCC seeking approval of the Merger. Virginia law provides that, if the VSCC determines, with or without hearing, that adequate service to the public at just and reasonable rates will not be impaired or jeopardized by granting the application for approval, then the VSCC shall approve a merger with such conditions that the VSCC deems to be appropriate in order to satisfy this standard. On October 7, 2014, the VSCC issued an order approving the Merger.

Federal Energy Regulatory Commission

On May 30, 2014, Exelon, PHI, Pepco, DPL and ACE, and certain of their respective affiliates, submitted to FERC a Joint Application for Authorization of Disposition of Jurisdictional Assets and Merger under Section 203 of the Federal Power Act. Under that section, FERC shall approve a merger if it finds that the proposed transaction will be consistent with the public interest. On November 20, 2014, FERC issued an order approving the Merger.

Delmarva Power & Light Co/De [Member]

Regulatory Matters

(7) REGULATORY MATTERS

Regulatory Assets and Regulatory Liabilities

The components of DPL’s regulatory asset and liability balances at December 31, 2015 and 2014 are as follows:

	2015		2014
	(millions of dollars)
Regulatory Assets
Demand-side management costs	$	111	$	91
Smart Grid costs		85		86
Recoverable income taxes		38		84
COPCO acquisition adjustment		13		18
Deferred debt extinguishment costs		10		12
Incremental storm restoration costs		6		7
MAPP abandonment costs		3		14
Deferred energy supply costs		2		12
Deferred losses on gas derivatives		2		4
Other		38		28
Total Regulatory Assets	$	308	$	356
Regulatory Liabilities
Asset removal costs	$	153	$	166
Reserves for FERC ROE transmission challenges		11		1
Deferred energy supply costs		6		—
Deferred income taxes due to customers		3		37
Other		16		21
Total Regulatory Liabilities	$	189	$	225

A description for each category of regulatory assets and regulatory liabilities follows:

Demand-Side Management Costs: Represents recoverable costs associated with customer direct load control and energy efficiency and conservation programs in all jurisdictions that are being recovered from customers. These programs are designed to reduce customers’ energy consumption. DPL earns a return on these regulatory assets.

Smart Grid Costs: Represents advanced metering infrastructure costs associated with the installation of smart meters and the early retirement of legacy meters throughout DPL’s service territory that are recoverable from customers. DPL generally is deferring carrying charges on these regulatory assets.

Recoverable Income Taxes: Represents amounts recoverable from DPL’s customers for tax benefits applicable to utility operations that were previously recognized in income tax expense before the company was ordered to record the tax benefits as deferred income taxes. As the temporary differences between the financial statement basis and tax basis of assets reverse, the deferred recoverable balances are reversed.

COPCO Acquisition Adjustment: On July 19, 2007, the MPSC issued an order which provided for the recovery of a portion of DPL’s goodwill. As a result of this order, $41 million in DPL goodwill was transferred to a regulatory asset. This item is being amortized from August 2007 through August 2018. DPL earns a return of 12.95% on these regulatory assets.

Deferred Debt Extinguishment Costs: Represents deferred costs of debt extinguishment that are amortized to interest expense and recovered from customers. DPL generally earns a return on these regulatory assets.

Incremental Storm Restoration Costs: Represents total incremental storm restoration costs incurred for repair work due to major storm events in 2015, 2012 and 2011, including the June 2015 storm, Hurricane Sandy, the June 2012 derecho, and Hurricane Irene, that are recoverable from customers in the Maryland jurisdiction. DPL’s costs related to Hurricane Sandy, the June 2012 derecho and Hurricane Irene are being amortized and recovered from customers, each over a five-year period. DPL generally earns a return on these regulatory assets.

MAPP Abandonment Costs: Represents abandonment costs incurred in connection with the Mid-Atlantic Power Pathway (MAPP) transmission line construction project which was terminated by PJM Interconnection, LLC (PJM) on August 24, 2012. These regulatory assets are being amortized and recovered in transmission rates through May 2016. DPL generally does not earn a return on these regulatory assets.

Deferred Energy Supply Costs: The regulatory asset represents primarily deferred costs associated with a net under-recovery of Default Electricity Supply costs incurred by DPL that are being or expected to be recovered from customers. DPL earns a return on these regulatory assets in Delaware. The regulatory liability represents primarily deferred costs associated with a net over-recovery of Default Electricity Supply costs incurred that will be refunded by DPL to customers.

Deferred Losses on Gas Derivatives: Represents losses associated with hedges of natural gas purchases that are recoverable from customers through the Gas Cost Rate (GCR) approved by the DPSC. DPL does not earn a return on these regulatory assets.

Other: Represents miscellaneous regulatory assets that generally are being amortized over 1 to 20 years.

Asset Removal Costs: The depreciation rates for DPL include a component for removal costs, as approved by the relevant federal and state regulatory commissions. Accordingly, DPL has recorded regulatory liabilities for its estimate of the difference between incurred removal costs and the amount of removal costs recovered through depreciation rates.

Reserves for FERC ROE Transmission Challenges: Represents reserves established under a settlement agreement filed with FERC for the resolution of certain challenges filed by a group of complainants of the base return on equity (ROE) currently authorized by FERC for the transmission service that DPL provides.

Deferred Income Taxes Due to Customers: Represents the portions of deferred income tax assets applicable to utility operations of DPL that have not been reflected in current customer rates for which future payment to customers is probable. As the temporary differences between the financial statement basis and tax basis of assets reverse, deferred recoverable income taxes are amortized.

Other: Represents miscellaneous regulatory liabilities.

Rate Proceedings

As further described in Note (1), “Organization,” on April 29, 2014, PHI entered into the Merger Agreement with Exelon and Merger Sub. Subject to certain exceptions, prior to the Merger or the termination of the Merger Agreement, PHI and its subsidiaries may not, without the consent of Exelon, initiate, file or pursue any rate cases, other than pursuing the conclusion of certain proceedings, as described below. To date, DPL has not requested such consent from Exelon and has not filed any new distribution base rate cases since entering into the Merger Agreement.

Bill Stabilization Adjustment

A decoupling mechanism, the BSA, was approved and implemented for DPL electric service in Maryland. DPL’s decoupling proposal in Delaware has not to date been adopted.

Delaware

Electric Distribution Base Rates

In March 2013, DPL submitted an application with the DPSC to increase its electric distribution base rates. The application sought approval of an annual rate increase of approximately $42 million (adjusted by DPL to approximately $39 million on September 20, 2013), based on a requested ROE of 10.25%. The requested rate increase sought to recover expenses associated with DPL’s ongoing investments in reliability enhancement improvements and efforts to maintain safe and reliable service. In August 2014, the DPSC issued a final order in this proceeding providing for an annual increase in DPL’s electric distribution base rates of approximately $15.1 million, based on an ROE of 9.70%. The new rates became effective on May 1, 2014.

In September 2014, DPL filed an appeal with the Delaware Superior Court of the DPSC’s August 2014 order in this proceeding, seeking the court’s review of the DPSC’s decision relating to the recovery of costs associated with one component of employee compensation, certain retirement benefits and credit facility expenses. The Division of the Public Advocate filed a cross-appeal in September 2014, pertaining to the treatment of a prepaid pension expense and other postretirement benefit obligations in base rates. Under the settlement agreement related to the Merger described below in “Merger Approval Proceedings – Delaware,” the parties agreed to suspend the appeal and, if the Merger is completed, to the withdrawal of the appeal and the cross-appeal with prejudice.

Forward Looking Rate Plan

In October 2013, DPL filed a multi-year rate plan, referred to as the Forward Looking Rate Plan (FLRP). As proposed, the FLRP would provide for annual electric distribution base rate increases over a four-year period in the aggregate amount of approximately $56 million. The FLRP as proposed provides the opportunity to achieve estimated earned ROEs of 7.41% and 8.80% in years one and two, respectively, and 9.75% in both years three and four of the plan.

In addition, DPL proposed that as part of the FLRP, in order to provide a higher minimum required standard of reliability for DPL’s customers than that to which DPL is currently subject, the standards by which DPL’s reliability is measured would be made more stringent in each year of the FLRP. DPL has also offered to refund an aggregate of $500,000 to customers in each year of the FLRP that it fails to meet the proposed stricter minimum reliability standards.

In October 2013, the DPSC opened a docket for the purpose of reviewing the details of the FLRP, but stated that it would not address the FLRP until the electric distribution base rate case discussed above was concluded. Although the rate case has been concluded, a schedule for the FLRP docket has not yet been established.

Under the Merger Agreement, DPL is permitted to pursue this matter; however, under the settlement agreement related to the Merger described below in “Merger Approval Proceedings – Delaware,” DPL agreed to withdraw the FLRP if the Merger is completed, without prejudice to the right to make future filings with the DPSC proposing alternative regulatory methodologies that could include, but are not limited to, a multi-year rate plan.

Gas Cost Rates

DPL makes an annual GCR filing with the DPSC for the purpose of allowing DPL to recover natural gas procurement costs through customer rates.

In August 2015, DPL made its 2015 GCR filing. The rates proposed in the 2015 GCR filing would result in a GCR decrease of approximately 26%, primarily reflecting lower natural gas prices. On September 22, 2015, the DPSC issued an order allowing DPL to place the new rates into effect on November 1, 2015, subject to refund and pending final DPSC approval.

Under the Merger Agreement, DPL is permitted to continue to file its required annual GCR cases in Delaware.

FERC Transmission ROE Challenges

In February 2013, the public service commissions and public advocates of the District of Columbia, Maryland, Delaware and New Jersey, as well as the Delaware Municipal Electric Corporation, Inc., filed a joint complaint at FERC against DPL and its affiliates, Pepco and Atlantic City Electric Company (ACE), as well as Baltimore Gas and Electric Company (BGE). The complainants challenged the base ROE and certain protocols regarding the formula rate process associated with the transmission service that the utilities provide. The complainants support an ROE within a zone of reasonableness of 6.78% and 10.33%, and have argued for a base ROE of 8.7%. The base ROE currently authorized by FERC for PHI’s utilities is (i) 11.3% for facilities placed into service after January 1, 2006, and (ii) 10.8% for facilities placed into service prior to 2006. The 10.8% base ROE for facilities placed into service prior to 2006 receives a 50-basis-point incentive adder for being a member of a regional transmission organization. In August 2014, FERC issued an order setting the matters in this proceeding for hearing, but holding the hearing in abeyance pending settlement discussions. The order also (i) directed that the evidence and analysis presented concerning ROE be guided by the new ROE methodology adopted by FERC in another proceeding (discussed below), and (ii) set a 15-month refund period that commenced on February 27, 2013, should a refund result from this proceeding. After settlement discussions among the parties in this matter reached an impasse, the settlement judge, in November 2014, issued an order terminating the settlement discussions and referring the matter to a presiding administrative law judge.

In June 2014, FERC issued an order in a proceeding in which DPL was not involved, in which it adopted a new ROE methodology for electric utilities. This new methodology replaces the existing one-step discounted cash flow analysis (which incorporates only short-term growth rates) traditionally used to derive ROE for electric utilities with the two-step discounted cash flow analysis (which incorporates both short-term and long-term measures of growth) used for natural gas and oil pipelines. As a result of the August 2014 FERC order discussed in the preceding paragraph, DPL applied an estimated ROE based on the two-step methodology announced by FERC for the 15-month period over which its transmission revenues would be subject to refund as a result of the challenge, and recorded estimated reserves for the entire 15-month refund period in the second quarter of 2014.

On December 8, 2014, the parties that filed the February 2013 complaint filed a second complaint against Pepco, DPL, ACE, as well as BGE, regarding the base transmission ROE, seeking a reduction from 10.8% to 8.8%. By order issued on February 9, 2015, FERC established a hearing on the second complaint and established a second 15-month refund period that commenced on December 8, 2014. Consistent with the prior challenge, DPL applied an estimated ROE based on the two-step methodology described above, and in the fourth quarter of 2014 and in the first, second and third quarters of 2015 established reserves for the estimated refund based on the effective date of the second refund period of December 8, 2014. On February 20, 2015, the chief judge issued an order consolidating the two complaint proceedings and established an initial decision issuance deadline of February 29, 2016. On March 2, 2015, the presiding administrative law judge issued an order establishing a procedural schedule for the consolidated proceedings that provided for the hearing to commence on October 20, 2015.

Also during the third quarter of 2015, DPL further evaluated the reserves established for each of the two refund periods and, based on an updated assessment of market conditions, developments in other cases before FERC, litigation risk and other factors, increased its reserves to reflect management’s best estimate of the refund that is expected to result from these consolidated proceedings. A settlement entered into by the parties regarding the protocols (but not the ROE) raised in the February 2013 complaint was submitted to FERC on July 31, 2015 and was approved by FERC in November 2015.

On November 6, 2015, the parties filed a settlement agreement with FERC regarding the ROE. This settlement agreement provides for (i) a base ROE of 10.0%, effective March 8, 2016, to which a 50-basis-point incentive adder will be applied for being a member of a regional transmission organization, and (ii) customer refunds in the amount of approximately $11.9 million for DPL covering the two 15-month refund periods described above. In addition, under this settlement agreement, no party may file to change the base ROE or any incentives prior to June 1, 2018. The parties have requested that FERC approve this settlement agreement by March 16, 2016, in order to incorporate the new ROE and applicable refunds into each utility’s 2016 transmission formula rate update. As of December 31, 2015, DPL’s reserves for both of the refund periods totaled $11 million as required under the settlement agreement.

MPSC New Generation Contract Requirement

In April 2012, the MPSC issued an order that requires Maryland electric distribution companies (EDCs) Pepco, DPL and BGE (collectively, the Contract EDCs) to negotiate and enter into a contract with the winning bidder of a competitive bidding process to build one new power plant in the range of 650 to 700 megawatts (MWs) beginning in 2015, in amounts proportional to their relative standard offer service (SOS) loads. Under the terms of the order, the winning bidder was to construct a 661 MW natural gas-fired combined cycle generation plant in Waldorf, Maryland, with an originally expected commercial operation date of June 1, 2015 (which is now deferred pending the outcome of the proceedings discussed below), and each of the Contract EDCs was to recover its costs associated with the contract through surcharges on its respective SOS customers.

In response to a complaint filed by a group of generating companies in the PJM region, in September 2013, the U.S. District Court for the District of Maryland (the Federal District Court) issued a ruling that the MPSC’s April 2012 order violated the Supremacy Clause of the U.S. Constitution by attempting to regulate wholesale prices. In contrast, in October 2013, in response to appeals filed by the Contract EDCs and other parties, the Maryland Circuit Court for Baltimore City (the Maryland Circuit Court) upheld the MPSC’s orders requiring the Contract EDCs to enter into the contracts.

In October 2013, the Federal District Court issued an order ruling that the contracts are illegal and unenforceable. The Contract EDCs, the Maryland Office of People’s Counsel and one generating company have appealed the Maryland Circuit Court’s decision to the Maryland Court of Special Appeals. In addition, in November 2013 both the winning bidder and the MPSC appealed the Federal District Court decision to the U.S. Court of Appeals for the Fourth Circuit, which affirmed the decision. In November 2014, the winning bidder and the MPSC each petitioned the U.S. Supreme Court to consider hearing an appeal of the Fourth Circuit decision and, on October 19, 2015, the U.S. Supreme Court agreed to review that decision.

Assuming the contracts, as currently written, become effective following the satisfaction of all relevant conditions, including the completion of the proceedings discussed above, DPL continues to believe that it may be required to record its proportional share of the contracts as derivative instruments at fair value and record related regulatory assets of approximately the same amount because it would be entitled to recover any payments under the contracts from SOS customers. DPL has concluded that any accounting for these contracts would not be required until all legal proceedings related to these contracts and the actions of the MPSC in the related proceeding have been resolved.

Merger Approval Proceedings

Delaware

On June 18, 2014, Exelon, PHI and DPL, and certain of their respective affiliates, filed an application with the DPSC seeking approval of the Merger. Delaware law requires the DPSC to approve the Merger when it determines that the transaction is in accordance with law, for a proper purpose, and is consistent with the public interest. The DPSC must further find that the successor will continue to provide safe and reliable service, will not terminate or impair existing collective bargaining agreements and will engage in good faith bargaining with organized labor. On February 13, 2015, Exelon, DPL, the DPSC staff, the Division of the Public Advocate and certain other parties filed a settlement agreement with the DPSC, which was amended in April 2015. The DPSC approved the amended settlement agreement at its meeting held on May 19, 2015, memorializing this decision by written order issued on June 2, 2015. The specific grounds for the DPSC’s approval of the Merger, as well as the specific conditions, will be included in an order to be issued by the DPSC after the Merger closes.

Maryland

On August 19, 2014, Exelon, PHI, Pepco, DPL and certain of their respective affiliates, filed an application with the MPSC seeking approval of the Merger. Maryland law requires the MPSC to approve a merger subject to its review if it finds that the merger is consistent with the public interest, convenience and necessity, including its benefits to and impact on consumers. Evidentiary hearings were held beginning on January 26, 2015. On March 10, 2015, Exelon, PHI, Pepco, DPL and certain of their respective affiliates, filed with the MPSC a settlement agreement entered into with one of the stakeholder groups participating in the MPSC approval proceeding. On March 16, 2015, Exelon, PHI, Pepco, DPL and certain of their respective affiliates, filed with the MPSC a settlement agreement entered into with Montgomery and Prince George’s Counties in Maryland, and a number of other parties. On May 15, 2015, the MPSC approved the Merger, with conditions, including conditions that modify and supplement those originally proposed. On May 18, 2015, Pepco Holdings and Exelon announced that they had completed their review of the MPSC’s order approving the Merger and have committed to fulfill the modified, more stringent conditions and package of customer benefits imposed by the MPSC.

Multiple parties have filed petitions for judicial review of the MPSC order by the Circuit Court of Queen Anne’s County, Maryland, seeking to appeal the MPSC order. In connection with these proceedings, the Maryland Office of People’s Counsel and several other parties to the Merger proceedings filed motions in the Circuit Court for Queen Anne’s County, Maryland, requesting a stay of the MPSC order. On August 7, 2015, the Circuit Court for Queen Anne’s County denied the motions for stay. On January 8, 2016, the Circuit Court affirmed the MPSC’s order in all respects. On January 20 and 22, 2016, respectively, the Maryland Office of People’s Counsel and environmental groups filed notices of appeal of the Circuit Court’s order to the Maryland Court of Special Appeals. Unless a motion to stay is filed and then granted by the court, the MPSC order will remain in effect during the appeals process.

Virginia

On June 3, 2014, Exelon, PHI, Pepco and DPL, and certain of their respective affiliates, filed an application with the VSCC seeking approval of the Merger. Virginia law provides that, if the VSCC determines, with or without hearing, that adequate service to the public at just and reasonable rates will not be impaired or jeopardized by granting the application for approval, then the VSCC shall approve a merger with such conditions that the VSCC deems to be appropriate in order to satisfy this standard. On October 7, 2014, the VSCC issued an order approving the Merger.

Federal Energy Regulatory Commission

On May 30, 2014, Exelon, PHI, Pepco, DPL and ACE, and certain of their respective affiliates, submitted to FERC a Joint Application for Authorization of Disposition of Jurisdictional Assets and Merger under Section 203 of the Federal Power Act. Under that section, FERC shall approve a merger if it finds that the proposed transaction will be consistent with the public interest. On November 20, 2014, FERC issued an order approving the Merger.

Atlantic City Electric Co [Member]

Regulatory Matters

(6) REGULATORY MATTERS

Regulatory Assets and Regulatory Liabilities

The components of ACE’s regulatory asset and liability balances at December 31, 2015 and 2014 are as follows:

	2015		2014
	(millions of dollars)
Regulatory Assets
Securitized stranded costs	$	202	$	278
Recoverable income taxes		44		42
Deferred energy supply costs		27		58
Incremental storm restoration costs		18		15
Deferred debt extinguishment costs		7		8
Other		24		26
Total Regulatory Assets	$	322	$	427
Regulatory Liabilities
Federal and state tax benefits, related to securitized stranded costs	$	13	$	8
Reserves for FERC ROE transmission challenges		8		1
Deferred income taxes due to customers		3		3
Other		3		2
Total Regulatory Liabilities	$	27	$	14

A description for each category of regulatory assets and regulatory liabilities follows:

Securitized Stranded Costs: Certain contract termination payments under a contract between ACE and an unaffiliated non-utility generator (NUG) and costs associated with the regulated operations of ACE’s electricity generation business are no longer recoverable through customer rates (collectively referred to as “stranded costs”). The stranded costs are amortized over the life of Transition Bonds issued by ACE Funding to securitize the recoverability of these stranded costs (the Transition Bonds). These Transition Bonds mature between 2016 and 2023. A customer surcharge is collected by ACE to fund principal and interest payments on the Transition Bonds. ACE earns a return on these regulatory assets.

Recoverable Income Taxes: Represents amounts recoverable from ACE’s customers for tax benefits applicable to utility operations previously recognized in income tax expense before the company was ordered to record the tax benefits as deferred income taxes. As the temporary differences between the financial statement basis and tax basis of assets reverse, the deferred recoverable balances are reversed.

Deferred Energy Supply Costs: The regulatory asset represents primarily deferred costs associated with a net under-recovery of energy supply costs incurred by ACE that are being or are expected to be recovered from customers. ACE earns a return on these regulatory assets.

Incremental Storm Restoration Costs: Represents total incremental storm restoration costs incurred for repair work due to major storm events in 2015, 2012 and 2011, including the June 2015 storm, Hurricane Sandy, the June 2012 derecho, and Hurricane Irene, that are recoverable from customers. ACE’s costs related to Hurricane Sandy, the June 2012 derecho and Hurricane Irene are being amortized and recovered from customers, each over a three-year period. ACE does not earn a return on these regulatory assets.

Deferred Debt Extinguishment Costs: Represents deferred costs of debt extinguishment that are amortized to interest expense and recovered from customers. ACE generally earns a return on these regulatory assets.

Other: Represents miscellaneous regulatory assets that generally are being amortized over 1 to 20 years.

Federal and State Tax Benefits, Related to Securitized Stranded Costs: Securitized stranded costs include a portion attributable to the future tax benefit expected to be realized when the higher tax basis of the generating facilities divested by ACE is deducted for New Jersey state income tax purposes, as well as the future benefit to be realized through the reversal of federal excess deferred taxes. To account for the possibility that these tax benefits may be given to ACE’s customers through lower rates in the future, ACE established a regulatory liability. The regulatory liability related to federal excess deferred taxes will remain until such time as the Internal Revenue Service (IRS) issues its final regulations with respect to normalization of these federal excess deferred taxes.

Reserves for FERC ROE Transmission Challenges: Represents reserves established under a settlement agreement filed with FERC for the resolution of certain challenges filed by a group of complainants of the base return on equity (ROE) currently authorized by FERC for the transmission service that ACE provides.

Deferred Income Taxes Due to Customers: Represents the portions of deferred income tax assets applicable to utility operations of ACE that have not been reflected in current customer rates for which future payment to customers is probable. As the temporary differences between the financial statement basis and tax basis of assets reverse, deferred recoverable income taxes are amortized.

Other: Represents miscellaneous regulatory liabilities.

Rate Proceedings

As further described in Note (1), “Organization,” on April 29, 2014, PHI entered into the Merger Agreement with Exelon and Merger Sub. Subject to certain exceptions, prior to the Merger or the termination of the Merger Agreement, PHI and its subsidiaries may not, without the consent of Exelon, initiate, file or pursue any rate cases, other than pursuing the conclusion of certain proceedings, as described below. To date, ACE has not requested such consent from Exelon and has not filed any new distribution base rate cases since entering into the Merger Agreement.

Bill Stabilization Adjustment

Although ACE proposed the adoption of a mechanism to decouple retail distribution revenue from the amount of power delivered to retail customers, this decoupling proposal has not to date been adopted.

New Jersey

Update and Reconciliation of Certain Under-Recovered Balances

In March 2015, ACE submitted its 2015 annual petition with the NJBPU seeking to reconcile and update (i) charges related to the recovery of above-market costs associated with ACE’s long-term power purchase contracts with the NUGs, and (ii) costs related to surcharges for the New Jersey Societal Benefit Program (a statewide public interest program that is intended to benefit low income customers and address other public policy goals) and for ACE’s uncollected accounts. As filed, the net impact of the proposed changes would have been an annual rate increase of approximately $52.0 million (revised to an increase of approximately $33.9 million on April 17, 2015, based upon updates for actual data through March 31, 2015). On May 19, 2015, the NJBPU approved a stipulation of settlement entered into by the parties providing for a provisional overall annual rate increase of $33.9 million effective June 1, 2015. On September 11, 2015, the NJBPU approved a stipulation of settlement in this proceeding, which made final the provisional rates that were placed into effect as of June 1, 2015, with an adjustment that decreased the rate applicable to the residential class by $1.3 million. This rate increase of approximately $32.6 million will have no effect on ACE’s operating income, since these revenues provide for recovery of deferred costs under an approved deferral mechanism.

On February 1, 2016, ACE submitted its 2016 annual petition with the NJBPU seeking to reconcile and update the same categories of charges and costs described in (i) and (ii) in the above paragraph. The net impact of adjusting the charges as proposed is an overall annual rate increase of approximately $8.8 million, including New Jersey Sales and Use Tax. The matter is pending at the NJBPU and will be updated for January through March 2016 actual data. ACE has requested that the NJBPU place the new rates into effect by June 1, 2016.

Service Extension Contributions Refund Order

In July 2013, in compliance with a 2012 Superior Court of New Jersey Appellate Division (Appellate Division) court decision, the NJBPU released an order requiring utilities to issue refunds to persons or entities that paid non-refundable contributions for utility service extensions to certain areas described as “Areas Not Designated for Growth.” The order is limited to eligible contributions paid between March 20, 2005 and December 20, 2009. ACE is processing the refund requests that meet the eligibility criteria established in the order as they are received. Although ACE estimates that it received approximately $11 million of contributions between March 20, 2005 and December 20, 2009, it is currently unable to reasonably estimate the amount that it may be required to refund using the eligibility criteria established by the order. Since the July 2013 order was released, ACE has paid less than $1 million in refund claims, the validity of each of which is investigated by ACE prior to making any such refunds. In September 2014, the NJBPU commenced a rulemaking proceeding to further implement the directives of the Appellate Division decision. In November 2015, the NJBPU adopted new regulations that remove provisions distinguishing between growth areas and not-for-growth areas and provide formulae for allocating extension costs. At this time, ACE does not expect the amount it is ultimately required to refund will have a material effect on its consolidated financial condition, results of operations or cash flows, as the amount refunded will generally increase the value of ACE’s property, plant and equipment and may ultimately be recovered through depreciation expense and cost of service in future electric distribution base rate cases.

Generic Consolidated Tax Adjustment Proceeding

In January 2013, the NJBPU initiated a generic proceeding to examine whether a consolidated tax adjustment (CTA) should continue to be used, and if so, how it should be calculated in determining a utility’s cost of service. Under the NJBPU’s current policy, when a New Jersey utility is included in a consolidated group income tax return, an allocated amount of any reduction in the consolidated group’s taxes as a result of losses by affiliates is used to reduce the utility’s rate base, upon which the utility earns a return. This policy has negatively impacted ACE’s electric distribution base rate case outcomes and ACE’s position is that the CTA should be eliminated. In an order issued in October 2014, the NJBPU determined that it is appropriate for affected consolidated groups to continue to include a CTA in New Jersey base rate filings, but that the CTA calculation will be modified to limit the look-back period for the calculation to five years, exclude transmission assets from the calculation, and allocate 25 percent of the final CTA amount as a reduction to the distribution revenue requirement. ACE anticipates that this revised methodology will significantly reduce the negative effects of the CTA in future base rate cases. In November 2014, the New Jersey Division of Rate Counsel filed an appeal of the NJBPU’s CTA order in the Appellate Division. No stay of the October 2014 CTA order was requested in connection with the appeal. As such, barring an adverse finding by the Appellate Division, the order is in effect. The appeal remains pending.

FERC Transmission ROE Challenges

In February 2013, the public service commissions and public advocates of the District of Columbia, Maryland, Delaware and New Jersey, as well as the Delaware Municipal Electric Corporation, Inc., filed a joint complaint at FERC against ACE and its affiliates, Pepco and Delmarva Power & Light Company (DPL), as well as Baltimore Gas and Electric Company (BGE). The complainants challenged the base ROE and certain protocols regarding the formula rate process associated with the transmission service that the utilities provide. The complainants support an ROE within a zone of reasonableness of 6.78% and 10.33%, and have argued for a base ROE of 8.7%. The base ROE currently authorized by FERC for PHI’s utilities is (i) 11.3% for facilities placed into service after January 1, 2006, and (ii) 10.8% for facilities placed into service prior to 2006. The 10.8% base ROE for facilities placed into service prior to 2006 receives a 50-basis-point incentive adder for being a member of a regional transmission organization. In August 2014, FERC issued an order setting the matters in this proceeding for hearing, but holding the hearing in abeyance pending settlement discussions. The order also (i) directed that the evidence and analysis presented concerning ROE be guided by the new ROE methodology adopted by FERC in another proceeding (discussed below), and (ii) set a 15-month refund period that commenced on February 27, 2013, should a refund result from this proceeding. After settlement discussions among the parties in this matter reached an impasse, the settlement judge, in November 2014, issued an order terminating the settlement discussions and referring the matter to a presiding administrative law judge.

In June 2014, FERC issued an order in a proceeding in which ACE was not involved, in which it adopted a new ROE methodology for electric utilities. This new methodology replaces the existing one-step discounted cash flow analysis (which incorporates only short-term growth rates) traditionally used to derive ROE for electric utilities with the two-step discounted cash flow analysis (which incorporates both short-term and long-term measures of growth) used for natural gas and oil pipelines. As a result of the August 2014 FERC order discussed in the preceding paragraph, ACE applied an estimated ROE based on the two-step methodology announced by FERC for the 15-month period over which its transmission revenues would be subject to refund as a result of the challenge, and recorded estimated reserves for the entire 15-month refund period in the second quarter of 2014.

On December 8, 2014, the parties that filed the February 2013 complaint filed a second complaint against Pepco, DPL, ACE, as well as BGE, regarding the base transmission ROE, seeking a reduction from 10.8% to 8.8%. By order issued on February 9, 2015, FERC established a hearing on the second complaint and established a second 15-month refund period that commenced on December 8, 2014. Consistent with the prior challenge, ACE applied an estimated ROE based on the two-step methodology described above, and in the fourth quarter of 2014 and in the first, second and third quarters of 2015 established reserves for the estimated refund based on the effective date of the second refund period of December 8, 2014. On February 20, 2015, the chief judge issued an order consolidating the two complaint proceedings and established an initial decision issuance deadline of February 29, 2016. On March 2, 2015, the presiding administrative law judge issued an order establishing a procedural schedule for the consolidated proceedings that provided for the hearing to commence on October 20, 2015.

Also during the third quarter of 2015, ACE further evaluated the reserves established for each of the two refund periods and, based on an updated assessment of market conditions, developments in other cases before FERC, litigation risk and other factors, increased its reserves to reflect management’s best estimate of the refund that is expected to result from these consolidated proceedings. A settlement entered into by the parties regarding the protocols (but not the ROE) raised in the February 2013 complaint was submitted to FERC on July 31, 2015 and was approved by FERC in November 2015.

On November 6, 2015, the parties filed a settlement agreement with FERC regarding the ROE. This settlement agreement provides for (i) a base ROE of 10.0%, effective March 8, 2016, to which a 50-basis-point incentive adder will be applied for being a member of a regional transmission organization, and (ii) customer refunds in the amount of approximately $9.5 million for ACE covering the two 15-month refund periods described above. In addition, under this settlement agreement, no party may file to change the base ROE or any incentives prior to June 1, 2018. The parties have requested that FERC approve this settlement agreement by March 16, 2016, in order to incorporate the new ROE and applicable refunds into each utility’s 2016 transmission formula rate update. As of December 31, 2015, ACE’s reserves for both of the refund periods totaled $8 million as required under the settlement agreement.

ACE Standard Offer Capacity Agreements

In April 2011, ACE entered into three Standard Offer Capacity Agreements (SOCAs) by order of the NJBPU, each with a different generation company. ACE entered into the SOCAs under protest, as did the other electric distribution companies (EDCs) in New Jersey, arguing that the EDCs were denied due process and that the SOCAs violated certain of the requirements of the New Jersey law under which the SOCAs were established (the NJ SOCA Law). In October 2013, in light of the decision of the U.S. District Court for the District of New Jersey described below, the state appeals of the NJBPU implementation orders filed by the EDCs and generators were dismissed without prejudice, subject to the parties exercising their appellate rights in the Federal courts.

In February 2011, ACE joined other plaintiffs in an action filed in the U.S. District Court for the District of New Jersey challenging the NJ SOCA Law on the grounds that it violates the Commerce Clause and the Supremacy Clause of the U.S. Constitution. In October 2013, the Federal district court ruled that the NJ SOCA Law is preempted by the Federal Power Act (FPA) and violates the Supremacy Clause, and is therefore null and void. In October 2013, the Federal district court issued an order ruling that the SOCAs are void, invalid and unenforceable, which order was affirmed by the U.S. Court of Appeals for the Third Circuit in September 2014. In November 2014 and December 2014, respectively, one of the generation companies and the NJBPU petitioned the U.S. Supreme Court to consider hearing an appeal of the Third Circuit decision. The U.S. Supreme Court has not yet agreed to review the Third Circuit decision and the petitions for such review remain pending.

ACE terminated one of the three SOCAs effective July 1, 2013 due to the occurrence of an event of default on the part of the generation company counterparty. ACE terminated the remaining two SOCAs effective November 19, 2013, in response to the October 2013 Federal district court decision.

In response to the October 2013 Federal district court order, ACE, in the fourth quarter of 2013, derecognized both the derivative assets (liabilities) for the estimated fair value of the SOCAs and the related regulatory liabilities (assets) that it had established with respect to the SOCAs.

Merger Approval Proceedings

New Jersey

On June 18, 2014, Exelon, PHI and ACE, and certain of their respective affiliates, filed a petition with the NJBPU seeking approval of the Merger. To approve the Merger, the NJBPU must find the Merger is in the public interest, and consider the impact of the Merger on (i) competition, (ii) rates of ratepayers affected by the Merger, (iii) ACE’s employees, and (iv) the provision of safe and reliable service at just and reasonable rates. On January 14, 2015, PHI, ACE, Exelon, certain of Exelon’s affiliates, the Staff of the NJBPU, and the Independent Energy Producers of New Jersey filed a stipulation of settlement (the Stipulation) with the NJBPU in this proceeding. On February 11, 2015, the NJBPU approved the Stipulation and the Merger and on March 6, 2015, the NJBPU issued a written order approving the Stipulation.

The NJBPU order states that the Merger must be closed by November 1, 2015 unless extended by the NJBPU. On October 15, 2015, the NJBPU voted to extend the effectiveness of its Merger approval until June 30, 2016.

Federal Energy Regulatory Commission

On May 30, 2014, Exelon, PHI, Pepco, DPL and ACE, and certain of their respective affiliates, submitted to FERC a Joint Application for Authorization of Disposition of Jurisdictional Assets and Merger under Section 203 of the FPA. Under that section, FERC shall approve a merger if it finds that the proposed transaction will be consistent with the public interest. On November 20, 2014, FERC issued an order approving the Merger.

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Property, Plant and Equipment

12 Months Ended

Dec. 31, 2015

Property, Plant and Equipment

(8) PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment is comprised of the following:

	Original Cost		Accumulated Depreciation		Net Book Value
	(millions of dollars)
At December 31, 2015
Generation	$	23	$	19	$	4
Distribution		10,051		3,161		6,890
Transmission		3,554		962		2,592
Gas		546		163		383
Construction work in progress		604		—		604
Non-operating and other property		1,440		609		831
Total	$	16,218	$	4,914	$	11,304
At December 31, 2014
Generation	$	104	$	100	$	4
Distribution		9,527		3,021		6,506
Transmission		3,252		934		2,318
Gas		511		153		358
Construction work in progress		688		—		688
Non-operating and other property		1,383		751		632
Total	$	15,465	$	4,959	$	10,506

The non-operating and other property amounts include balances for general plant, intangible plant, distribution plant and transmission plant held for future use as well as other property held by non-utility subsidiaries. Utility plant is generally subject to a first mortgage lien.

Pepco Holdings’ utility subsidiaries use separate depreciation rates for each electric plant account. The rates vary from jurisdiction to jurisdiction.

Jointly Owned Plant

PHI’s consolidated balance sheets include its proportionate share of assets and liabilities related to jointly owned plant. At December 31, 2015 and 2014, PHI’s subsidiaries had a net book value ownership interest of $16 million and $15 million, respectively, in transmission and other facilities in which various parties also have ownership interests. PHI’s share of the operating and maintenance expenses of the jointly owned plant is included in the corresponding expenses in the consolidated statements of income (loss). PHI is responsible for providing its share of the financing for the above jointly owned facilities.

Capital Leases

Pepco leases its consolidated control center, which is an integrated energy management center used by Pepco to centrally control the operation of its transmission and distribution systems. This lease is accounted for as a capital lease and was initially recorded at the present value of future lease payments, which totaled $152 million. The lease requires semi-annual payments of approximately $8 million over a 25-year period that began in December 1994, and provides for transfer of ownership of the system to Pepco for $1 at the end of the lease term. Under FASB guidance on regulated operations, the amortization of leased assets is modified so that the total interest expense charged on the obligation and amortization expense of the leased asset is equal to the rental expense allowed for rate-making purposes. The amortization expense is included within Depreciation and amortization in the consolidated statements of income (loss). This lease is treated as an operating lease for rate-making purposes.

Capital lease assets recorded within Property, Plant and Equipment at December 31, 2015 and 2014 are comprised of the following:

	Original Cost		Accumulated Amortization		Net Book Value
	(millions of dollars)
At December 31, 2015
Transmission	$	76	$	51	$	25
Distribution		76		51		25
Total	$	152	$	102	$	50
At December 31, 2014
Transmission	$	76	$	46	$	30
Distribution		76		46		30
Total	$	152	$	92	$	60

The approximate annual commitments under all capital leases are $15 million in each of the years 2016 through 2018 and $16 million in 2019.

Gains on Sales of Land

Since 2002, Pepco has owned a 3.5 acre parcel of unimproved land (held as non-utility property) in the Buzzard Point area of southeast Washington, D.C. On July 2, 2015, Pepco entered into a purchase and sale agreement with the District of Columbia to sell the 3.5-acre parcel with a carrying value of $2 million at a purchase price of $39 million. The transaction was consummated on November 10, 2015 resulting in a $37 million pre-tax gain ($22 million after-tax) which was recorded in the fourth quarter of 2015.

Since 2003, Pepco has owned a 3.8 acre parcel of unimproved land (held as non-utility property) in the NoMa area of northeast Washington, D.C. On October 16, 2015, Pepco entered into a purchase and sale agreement with a third party to sell a two-acre parcel of the unimproved land with an allocated carrying value of $5 million at a purchase price of $14 million. The transaction was consummated on December 31, 2015 resulting in a $9 million pre-tax gain ($5 million after-tax) which was recorded in the fourth quarter of 2015. The purchase and sale agreement also provided the third party with a 90-day option to purchase the remaining 1.8-acre land parcel with an allocated carrying value of $4 million at a purchase price of $13 million.

Deactivation of Pepco Energy Services’ Generating Facilities

During 2012, Pepco Energy Services deactivated its Buzzard Point and Benning Road oil-fired generation facilities. Pepco Energy Services completed demolition of the Benning Road generation facility in July 2015 and recognized the scrap metal salvage value of the facility as a reduction in its demolition expenses over the life of the project.

Long-Lived Asset Impairment

During 2014, PHI recorded impairment losses of $81 million ($48 million after-tax) at Pepco Energy Services associated with its combined heat and power thermal generating facilities and operations in Atlantic City, which reduced the carrying amount of its long lived assets in Atlantic City from $83 million to $2 million at December 31, 2014. PHI performed long-lived asset impairment tests on asset groups comprising substantially all of the long-lived assets in Atlantic City as a result of significant adverse changes in the financial condition of its customers and the business climate in Atlantic City. The assets were written down to their estimated fair values because the future estimated undiscounted cash flows from the asset groups were significantly lower than their carrying value. PHI estimated the fair values of the asset groups from a market participant’s perspective by calculating the present value of estimated future cash flows over the useful lives of the assets using an appropriate discount rate. Both the estimated future cash flows and the discount rate were based on primarily unobservable, Level 3 inputs. The estimated future cash flows were probability weighted based on several potential outcomes regarding forecasted revenues and expenses associated with each asset group. Forecasted revenues and expenses were, in part, based on estimated future commodity prices from an external valuation specialist. In addition, PHI forecasted customer usage volumes and the associated operations and maintenance expenses and capital expenditures. A 10 percent change in the estimated cash flows would not have a significant impact on the estimated fair value of the assets. PHI also selected a discount rate that would reflect a market return on the estimated cash flows. PHI considered a range of discount rates between 10 percent and 16 percent. A one percent change in the discount rate assumptions would not have a significant impact on the estimated fair value of the assets.

During 2013, PHI recorded impairment losses of $4 million ($3 million after-tax) at Pepco Energy Services associated primarily with its investments in landfill gas-fired electric generation facilities. PHI performed a long-lived asset impairment test on the landfill generation facilities of Pepco Energy Services as a result of a sustained decline in energy prices and recent production levels. The asset value of the facilities was written down to the estimated fair value because the future expected cash flows of the facilities were not sufficient to provide recovery of the facilities’ carrying value. PHI estimated the fair value of the facilities by calculating the present value of expected future cash flows using an appropriate discount rate. Both the expected future cash flows and the discount rate used primarily unobservable inputs.

Asset Retirement Obligations

PHI recognizes liabilities related to the retirement of long-lived assets in accordance with ASC 410. As of December 31, 2015, PHI had an asset retirement obligation of $7 million on its consolidated balance sheet related to the Edge Moor coal ash landfill site. The asset retirement obligation reflects estimates of the costs for PHI to close the landfill and provide post-closure operations, maintenance and monitoring services.

Potomac Electric Power Co [Member]

Property, Plant and Equipment

(7) PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment is comprised of the following:

	Original Cost		Accumulated Depreciation		Net Book Value
	(millions of dollars)
At December 31, 2015
Distribution	$	5,996	$	2,199	$	3,797
Transmission		1,378		475		903
Construction work in progress		318		—		318
Non-operating and other property		399		125		274
Total	$	8,091	$	2,799	$	5,292
At December 31, 2014
Distribution	$	5,668	$	2,082	$	3,586
Transmission		1,306		463		843
Construction work in progress		312		—		312
Non-operating and other property		478		271		207
Total	$	7,764	$	2,816	$	4,948

The non-operating and other property amounts include balances for general plant, distribution plant and transmission plant held for future use, intangible plant and non-utility property. Utility plant is generally subject to a first mortgage lien.

Capital Leases

Pepco leases its consolidated control center, which is an integrated energy management center used by Pepco to centrally control the operation of its transmission and distribution systems. This lease is accounted for as a capital lease and was initially recorded at the present value of future lease payments, which totalled $152 million. The lease requires semi-annual payments of approximately $8 million over a 25-year period that began in December 1994, and provides for transfer of ownership of the system to Pepco for $1 at the end of the lease term. Under FASB guidance on regulated operations, the amortization of leased assets is modified so that the total interest expense charged on the obligation and amortization expense of the leased asset is equal to the rental expense allowed for rate-making purposes. The amortization expense is included within Depreciation and amortization in the statements of income. This lease is treated as an operating lease for rate-making purposes.

Capital lease assets recorded within Property, plant and equipment at December 31, 2015 and 2014 are comprised of the following:

	Original Cost		Accumulated Amortization		Net Book Value
	(millions of dollars)
At December 31, 2015
Transmission	$	76	$	51	$	25
Distribution		76		51		25
Total	$	152	$	102	$	50
At December 31, 2014
Transmission	$	76	$	46	$	30
Distribution		76		46		30
Total	$	152	$	92	$	60

The approximate annual commitments under all capital leases are $15 million in each of the years 2016 through 2018 and $16 million in 2019.

Gains on Sales of Land

Since 2002, Pepco has owned a 3.5 acre parcel of unimproved land (held as non-utility property) in the Buzzard Point area of southeast Washington, D.C. On July 2, 2015, Pepco entered into a purchase and sale agreement with the District of Columbia to sell the 3.5-acre parcel with a carrying value of $2 million at a purchase price of $39 million. The transaction was consummated on November 10, 2015 resulting in a $37 million pre-tax gain ($22 million after-tax) which was recorded in the fourth quarter of 2015.

Since 2003, Pepco has owned a 3.8 acre parcel of unimproved land (held as non-utility property) in the NoMa area of northeast Washington, D.C. On October 16, 2015, Pepco entered into a purchase and sale agreement with a third party to sell a two-acre parcel of the unimproved land with an allocated carrying value of $5 million at a purchase price of $14 million. The transaction was consummated on December 31, 2015 resulting in a $9 million pre-tax gain ($5 million after-tax) which was recorded in the fourth quarter of 2015. The purchase and sale agreement also provided the third party with a 90-day option to purchase the remaining 1.8-acre land parcel with an allocated carrying value of $4 million at a purchase price of $13 million.

Delmarva Power & Light Co/De [Member]

Property, Plant and Equipment

(8) PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment is comprised of the following:

	Original Cost		Accumulated Depreciation		Net Book Value
	(millions of dollars)
At December 31, 2015
Distribution	$	2,043	$	490	$	1,553
Transmission		1,208		259		949
Gas		546		163		383
Construction work in progress		107		—		107
Non-operating and other property		305		134		171
Total	$	4,209	$	1,046	$	3,163
At December 31, 2014
Distribution	$	1,928	$	489	$	1,439
Transmission		1,107		248		859
Gas		511		153		358
Construction work in progress		125		—		125
Non-operating and other property		275		131		144
Total	$	3,946	$	1,021	$	2,925

The non-operating and other property amounts include balances for general plant, plant held for future use, intangible plant and non-utility property. Utility plant is generally subject to a first mortgage lien.

Atlantic City Electric Co [Member]

Property, Plant and Equipment

(7) PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment is comprised of the following:

	Original Cost		Accumulated Depreciation		Net Book Value
	(millions of dollars)
At December 31, 2015
Distribution	$	2,012	$	472	$	1,540
Transmission		968		228		740
Construction work in progress		158		—		158
Non-operating and other property		167		64		103
Total	$	3,305	$	764	$	2,541
At December 31, 2014
Generation	$	10	$	9	$	1
Distribution		1,931		450		1,481
Transmission		839		223		616
Construction work in progress		115		—		115
Non-operating and other property		178		78		100
Total	$	3,073	$	760	$	2,313

The non-operating and other property amounts include balances for general plant, plant held for future use, intangible plant and non-utility property. Utility plant is generally subject to a first mortgage lien.

Jointly Owned Plant

ACE’s consolidated balance sheets include its proportionate share of assets and liabilities related to jointly owned plant. At each of December 31, 2015 and 2014, ACE’s subsidiaries had a net book value ownership interest of $11 million in transmission and other facilities in which various parties also have ownership interests. ACE’s share of the operating and maintenance expenses of the jointly owned plant is included in the corresponding expenses in the consolidated statements of income. ACE is responsible for providing its share of the financing for the above jointly owned facilities.

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Pension and Other Postretirement Benefits

12 Months Ended

Dec. 31, 2015

Pension and Other Postretirement Benefits

(9) PENSION AND OTHER POSTRETIREMENT BENEFITS

The following table shows changes in the benefit obligation and plan assets for the years ended December 31, 2015 and 2014:

	Pension Benefits						Other Postretirement Benefits
	2015			2014			2015			2014
	(millions of dollars)
Change in Benefit Obligation
Benefit obligation as of January 1	$	2,638		$	2,238		$	632		$	574
Service cost		57			44			7			7
Interest cost		109			109			24			26
Actuarial loss (gain)		(151	)		401			(61	)		59
Benefits paid		(163	)		(154	)		(39	)		(34	)
Benefit obligation as of December 31	$	2,490		$	2,638		$	563		$	632
Change in Plan Assets
Fair value of plan assets as of January 1	$	2,236		$	2,116		$	367		$	368
Actual return on plan assets		(61	)		268			1			21
Company and participant contributions		6			6			5			6
Benefits paid by plan		(163	)		(154	)		(25	)		(28	)
Fair value of plan assets as of December 31	$	2,018		$	2,236		$	348		$	367
Funded Status at end of year (plan assets less plan obligations)	$	(472	)	$	(402	)	$	(215	)	$	(265	)

At December 31, 2015 and 2014, the PHI Retirement Plan’s accumulated benefit obligation was approximately $2.3 billion and $2.4 billion, respectively. The accumulated benefit obligation differs from the pension benefit obligation presented in the table above in that the accumulated benefit obligation includes no assumption about future compensation levels.

The following table provides the amounts recorded in PHI’s consolidated balance sheets as of December 31, 2015 and 2014:

	Pension Benefits						Other Postretirement Benefits
	2015			2014			2015			2014
	(millions of dollars)
Regulatory asset	$	870		$	871		$	40		$	75
Current liabilities		(6	)		(6	)		—			—
Pension benefit obligation		(466	)		(396	)		—			—
Other postretirement benefit obligations		—			—			(215	)		(265	)
Deferred income tax liabilities		(162	)		(193	)		70			77
Accumulated other comprehensive loss, net of tax		28			37			—			—
Net amount recorded	$	264		$	313		$	(105	)	$	(113	)

Amounts included in AOCL (pre-tax) and Regulatory assets at December 31, 2015 and 2014 consist of:

	Pension Benefits				Other Postretirement Benefits
	2015		2014		2015			2014
	(millions of dollars)
Unrecognized net actuarial loss	$	910	$	925	$	128		$	176
Unamortized prior service cost (credit)		6		8		(88	)		(101	)
Total	$	916	$	933	$	40		$	75
Accumulated other comprehensive loss ($28 million and $37 million, net of tax, at December 31, 2015 and 2014, respectively)	$	46	$	62	$	—		$	—
Regulatory assets		870		871		40			75
Total	$	916	$	933	$	40		$	75

Under FASB guidance on regulated operations, a portion of actuarial gains and losses and prior service costs (credits) are included in Regulatory assets (liabilities) in the consolidated balance sheets to reflect expected regulatory recovery of such amounts, which otherwise would be recorded to AOCL. The table below provides the changes in plan assets and benefit obligations recognized in AOCL and Regulatory assets for the years ended December 31, 2015, 2014 and 2013:

	Pension Benefits									Other Postretirement Benefits
	2015			2014			2013			2015			2014			2013
	(millions of dollars)
Amounts amortized during the year:
Amortization of prior service (cost) credit	$	(2	)	$	(2	)	$	(2	)	$	13		$	13		$	11
Amortization of net actuarial loss		(65	)		(45	)		(67	)		(8	)		(3	)		(12	)
Amounts arising during the year:
Current year prior service cost (credit)		—			—			3			—			—			(124	)
Current year actuarial loss (gain)		50			276			(218	)		(39	)		62			(109	)
Total recognized in AOCL and Regulatory assets for the year ended December 31	$	(17	)	$	229		$	(284	)	$	(34	)	$	72		$	(234	)

The estimated net actuarial loss and prior service cost for the defined benefit pension plans that will be amortized from AOCL or Regulatory assets into net periodic benefit cost over the next reporting year are $63 million and $1 million, respectively. The estimated net actuarial loss and prior service credit for the OPEB plan that will be amortized from AOCL or Regulatory assets into net periodic benefit cost over the next reporting year are $7 million and $13 million, respectively.

The table below provides the components of net periodic benefit costs recognized for the years ended December 31, 2015, 2014 and 2013:

	Pension Benefits									Other Postretirement Benefits
	2015			2014			2013			2015			2014			2013
	(millions of dollars)
Service cost	$	57		$	44		$	53		$	7		$	7		$	8
Interest cost		109			109			100			24			26			29
Expected return on plan assets		(140	)		(141	)		(145	)		(22	)		(24	)		(20	)
Amortization of prior service cost (credit)		2			2			2			(13	)		(13	)		(11	)
Amortization of net actuarial loss		65			45			67			8			3			12
Net periodic benefit cost	$	93		$	59		$	77		$	4		$	(1	)	$	18

The table below provides the split of the combined pension and other postretirement net periodic benefit costs among subsidiaries for the years ended December 31, 2015, 2014 and 2013:

	2015		2014		2013
	(millions of dollars)
Pepco	$	30	$	22	$	34
DPL		15		7		18
ACE		15		13		17
Other subsidiaries		37		16		26
Total	$	97	$	58	$	95

The following weighted average assumptions were used to determine the benefit obligations at December 31, 2015 and 2014:

	Pension Benefits						Other Postretirement Benefits
	2015			2014			2015			2014
Discount rate		4.65% /4.55	% (a)		4.20	%		4.55	%		4.15	%
Rate of compensation increase		5.00	%		5.00	%		5.00	%		5.00	%
Health care cost trend rate assumed for current year – pre 65		—			—			6.33	%		6.67	%
Health care cost trend rate assumed for current year – post 65		—			—			5.40	%		5.50	%
Rate to which the cost trend rate is assumed to decline for all eligible retirees (the ultimate trend rate)		—			—			5.00	%		5.00	%
Year that the cost trend rate reaches the ultimate trend rate		—			—			2020			2020

(a) The discount rate for the qualified and nonqualified pension plans was 4.65% and 4.55%, respectively.

Assumed health care cost trend rates may have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects, in millions of dollars:

	1-Percentage- Point Increase		1-Percentage- Point Decrease
Increase (decrease) in total service and interest cost	$	1	$	(1	)
Increase (decrease) in postretirement benefit obligation	$	15	$	(18	)

The following weighted average assumptions were used to determine the net periodic benefit cost for the years ended December 31, 2015, 2014 and 2013:

	Pension Benefits									Other Postretirement Benefits
	2015			2014			2013			2015			2014			2013
Discount rate		4.20	%		5.05	%		4.15	%		4.15	%		5.00	%		4.10%/4.95	% (a)
Expected long-term return on plan assets		6.50	%		7.00	%		7.00	%		6.75	%		7.25	%		7.00	%
Rate of compensation increase		5.00	%		5.00	%		5.00	%		5.00	%		5.00	%		5.00	%
Health care cost trend rate		—			—			—			6.67	%		7.00	%		7.50	%

(a) The discount rate was updated for remeasurement to 4.95% on July 1, 2013.

PHI utilizes an analytical tool developed by its actuaries to select the discount rate. The analytical tool utilizes a high-quality bond portfolio with cash flows that match the benefit payments expected to be made under the plans.

PHI uses a building block approach to estimate the expected rate of return on plan assets. Under this approach, the percentage of plan assets in each asset class according to PHI’s target asset allocation, at the beginning of the year, is applied to the expected asset return for the related asset class. PHI incorporates long-term assumptions for real returns, inflation expectations, volatility and correlations among asset classes to determine expected returns for a given asset allocation. The pension and postretirement benefit plan assets consist of equity, fixed income, real estate and private equity investments. PHI periodically reviews its asset mix and rebalances assets to the target allocation.

The average remaining service periods for participating employees of the benefit plans was approximately 11 years for both 2015 and 2014. PHI utilizes plan census data to estimate these average remaining service periods. PHI uses mortality tables and mortality improvement scales issued by the Society of Actuaries to estimate participants’ life expectancy. In 2014, the Society of Actuaries issued updated mortality tables and mortality improvement scales which PHI applied in determining its benefit obligations as of December 31, 2014. In 2015, the Society of Actuaries modified the tables issued in 2014 to reflect updated mortality improvement experience. PHI applied these modified tables in determining its benefit obligations as of December 31, 2015.

Benefit Plan Modifications

During 2013, PHI approved two amendments to its other postretirement benefits plan. These amendments impacted the retiree health care and the retiree life insurance benefits, and were effective on January 1, 2014. As a result of the amendments, which were cumulatively significant, PHI remeasured its accumulated postretirement benefit obligation for other postretirement benefits as of July 1, 2013. The remeasurement resulted in a $193 million reduction of the accumulated postretirement benefit obligation, which included recording a prior service credit of $124 million, which will be amortized over approximately ten years, and a $69 million reduction from a change in the discount rate from 4.10% as of December 31, 2012 to 4.95% as of July 1, 2013. The remeasurement resulted in a $19 million reduction in net periodic benefit cost for other postretirement benefits during 2014, when compared to 2013. Approximately 36% of net periodic other postretirement benefit costs were capitalized in 2014.

Plan Assets

Investment Policies and Strategies

In developing its allocation policy for the assets in the PHI Retirement Plan and the other postretirement benefit plan, PHI examined projections of asset returns and volatility over a long-term horizon. In connection with this analysis, PHI evaluated the risk and return tradeoffs of alternative asset classes and asset mixes given long-term historical relationships as well as prospective capital market returns. PHI also conducted an asset-liability study to match projected asset growth with projected liability growth to determine whether there is sufficient liquidity for projected benefit payments. PHI developed its asset mix guidelines by incorporating the results of these analyses with an assessment of its risk posture, and taking into account industry practices. PHI periodically evaluates its investment strategy to ensure that plan assets are sufficient to meet the benefit obligations of the plans. As part of the ongoing evaluation, PHI may make changes to its targeted asset allocations and investment strategy.

PHI’s pension investment strategy is designed to meet the following investment objectives:

• Generate investment returns that, in combination with funding contributions from PHI, provide adequate funding to meet all current and future benefit obligations of the plan,

• Provide investment results that meet or exceed the assumed long-term rate of return, while maintaining the funded status of the plan at acceptable levels,

• Improve funded status over time, and

• Decrease contribution and expense volatility as funded status improves.

To achieve these investment objectives, PHI’s investment strategy divides the pension program into two primary portfolios:

Return-Seeking Assets - These assets are intended to provide investment returns in excess of pension liability growth and reduce existing deficits in the funded status of the plan. The category includes a diversified mix of U.S. large and small cap equities, non-U.S. developed and emerging market equities, real estate, and private equity.

Liability-Hedging Assets - These assets are intended to reflect the sensitivity of the plan’s liabilities to changes in discount rates. This category includes a diversified mix of long duration, primarily investment grade credit and U.S. treasury securities.

PHI follows an asset-liability management strategy for PHI Retirement Plan assets in order to reduce the effects of future volatility of the fair value of its pension plan assets relative to its pension plan liabilities. For example, in 2015, this strategy uses a 68% target allocation to fixed income investments, primarily in high quality, longer-maturity fixed income securities. The PHI Retirement Plan asset allocations at December 31, 2015 and 2014, by asset category, were as follows:

Asset Category	Plan Assets at December 31,						Target Plan Asset Allocation
	2015			2014			2015			2014
Equity		28	%		28	%		27	%		27	%
Fixed Income		66	%		65	%		68	%		68	%
Other (real estate, private equity)		6	%		7	%		5	%		5	%
Total		100	%		100	%		100	%		100	%

PHI’s other postretirement benefit plan asset allocations at December 31, 2015 and 2014, by asset category, were as follows:

Asset Category	Plan Assets at December 31,						Target Plan Asset Allocation
	2015			2014			2015			2014
Equity		63	%		64	%		60	%		60	%
Fixed Income		34	%		34	%		35	%		35	%
Cash		3	%		2	%		5	%		5	%
Total		100	%		100	%		100	%		100	%

PHI will rebalance the plan asset portfolios when the actual allocations fall outside the ranges outlined in the investment policy or as funded status improves over a reasonable period of time.

Risk Management

Pension and other postretirement benefit plan assets may be invested in separately managed accounts in which there is ownership of individual securities, shares of commingled funds or mutual funds, or limited partnerships. Commingled funds and mutual funds are subject to detailed policy guidelines set forth in the fund’s prospectus or fund declaration, and limited partnerships are subject to the terms of the partnership agreement.

Separate account investment managers are responsible for achieving a level of diversification in their portfolio that is consistent with their investment approach and their role in PHI’s overall investment structure. Separate account investment managers must follow risk management guidelines established by PHI unless authorized in writing by PHI.

Derivative instruments are permissible in an investment portfolio to the extent they comply with policy guidelines and are consistent with risk and return objectives. Under no circumstances may such instruments be used speculatively or to leverage the portfolio. Separately managed accounts are prohibited from holding securities issued by the following firms:

• PHI and its subsidiaries,

• PHI’s pension plan trustee, its parent or its affiliates,

• PHI’s pension plan consultant, its parent or its affiliates, and

• PHI’s pension plan investment manager, its parent or its affiliates.

Fair Value of Plan Assets

As defined in the FASB guidance on fair value measurement (ASC 820), fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The FASB’s fair value framework includes a hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1) and the lowest priority to unobservable inputs (level 3). If the inputs used to measure the financial instruments fall within different levels of the hierarchy, the categorization is based on the lowest level input that is significant to the fair value measurement of the instrument. Investments are classified within the fair value hierarchy as follows:

Level 1: Investments are valued using quoted prices in active markets for identical instruments.

Level 2: Investments are valued using other significant observable inputs (e.g., quoted prices for similar investments, interest rates, credit risks, etc).

Level 3: Investments are valued using significant unobservable inputs, including internal assumptions.

There were no significant transfers between level 1 and level 2 during the years ended December 31, 2015 and 2014.

In accordance with new FASB guidance on fair value measurement, certain investments that are measured at fair value using the NAV per share as a practical expedient are no longer classified within the fair value hierarchy and are no longer assigned a level. The fair value measurements table at December 31, 2014, was reclassified to conform to the current year presentation, see Note (3), “Newly Adopted Accounting Standards,” for additional information.

The following tables present the fair values of PHI’s pension and other postretirement benefit plan assets by asset category included in and excluded from the fair value hierarchy levels, as of December 31, 2015 and 2014:

			Fair Value Measurements at December 31, 2015
	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
Asset Category
Pension Plan Assets:
Equity:
Domestic (a)	$	311	$	120	$	191	$	—
International (b)		216		215		—		1
Fixed Income (c)		820		—		810		10
Cash Equivalents (d)		50		50		—		—
		1,397	$	385	$	1,001	$	11
Investments measured at fair value using net asset value as a practical expedient:
Equity:
Domestic (a)		33
Fixed Income (c)		504
Other:
Private Equity		38
Real Estate		46
Pension Plan Assets Total	$	2,018
Other Postretirement Plan Assets:
Equity (e)	$	197	$	197	$	—	$	—
Fixed Income (f)		120		120		—		—
Cash Equivalents		9		9		—		—
		326	$	326	$	—	$	—
Investments measured at fair value using net asset value as a practical expedient:
Equity (e)		22
Postretirement Plan Assets Total	$	348

(a) Domestic equity assets predominantly include domestic common stock and commingled funds.

(b) International equity assets predominantly include foreign common and preferred stock and warrants.

(c) Fixed income assets predominantly include corporate bonds, government bonds, municipal/provincial bonds, collateralized mortgage obligations and commingled funds.

(d) Cash equivalents predominantly include cash investments in short-term investment funds.

(e) Equity assets include domestic and international commingled funds.

(f) Fixed income assets include fixed income commingled funds.

			Fair Value Measurements at December 31, 2014
	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
Asset Category
Pension Plan Assets:
Equity:
Domestic (a)	$	341	$	128	$	213	$	—
International (b)		255		254		—		1
Fixed Income (c)		916		—		905		11
Cash Equivalents (d)		45		45		—		—
		1,557	$	427	$	1,118	$	12
Investments measured at fair value using net asset value as a practical expedient:
Equity:
Domestic (a)		35
Fixed Income (c)		543
Other:
Private Equity		47
Real Estate		54
Pension Plan Assets Total	$	2,236
Other Postretirement Plan Assets:
Equity (e)	$	208	$	208	$	—	$	—
Fixed Income (f)		126		126		—		—
Cash Equivalents		6		6		—		—
		340	$	340	$	—	$	—
Investments measured at fair value using net asset value as a practical expedient:
Equity (e)		27
Postretirement Plan Assets Total	$	367

(a) Domestic equity assets predominantly include domestic common stock and commingled funds.

(b) International equity assets predominantly include foreign common and preferred stock and warrants.

(c) Fixed income assets predominantly include corporate bonds, government bonds, municipal/provincial bonds, collateralized mortgage obligations and commingled funds.

(d) Cash equivalents predominantly include cash investments in short-term investment funds.

(e) Equity assets include domestic and international commingled funds.

(f) Fixed income assets include fixed income commingled funds.

There were no significant concentrations of risk in pension and OPEB plan assets at December 31, 2015 and 2014.

Valuation Techniques Used to Determine Fair Value

Equity

Equity securities are primarily comprised of securities issued by public companies in domestic and foreign markets plus investments in commingled funds, which are valued on a daily basis. PHI can exchange shares of the publicly traded securities and the fair values are primarily sourced from the closing prices on stock exchanges where there is active trading, therefore they would be classified as level 1 investments. If there is less active trading, then the publicly traded securities would typically be priced using observable data, such as bid/ask prices, and these measurements would be classified as level 2 investments. Investments that are not publicly traded and valued using unobservable inputs would be classified as level 3 investments. Investments that are measured at fair value using the NAV per share as a practical expedient are not classified within the fair value hierarchy.

Commingled funds with publicly quoted prices and active trading are classified as level 1 investments. For commingled funds that are not publicly traded and have ongoing subscription and redemption activity or have redemption restrictions, the fair value of the investment is the NAV per fund share, derived from the underlying securities’ quoted prices in active markets, and are not classified within the fair value hierarchy.

Fixed Income

Fixed income investments are primarily comprised of fixed income securities and fixed income commingled funds. The prices for direct investments in fixed income securities are generated on a daily basis. Like the equity securities, fair values generated from active trading on exchanges are classified as level 1 investments. Prices generated from less active trading with wider bid/ask prices are classified as level 2 investments. If prices are based on uncorroborated and unobservable inputs, then the investments are classified as level 3 investments. Investments that are measured at fair value using the NAV per share as a practical expedient are not classified within the fair value hierarchy.

Commingled funds with publicly quoted prices and active trading are classified as level 1 investments. For commingled funds that are not publicly traded and have ongoing subscription and redemption activity or redemption restrictions, the fair value of the investment is the NAV per fund share, derived from the underlying securities’ quoted prices in active markets, and are not classified within the fair value hierarchy.

Other – Private Equity and Real Estate

Investments in private equity and real estate funds are primarily invested in privately held real estate investment properties, trusts and partnerships, as well as equity and debt issued by public or private companies. As a practical expedient, PHI’s interest in the fund or partnership is estimated at NAV. PHI’s interest in these funds cannot be readily redeemed due to the inherent lack of liquidity and the primarily long-term nature of the underlying assets. Distribution is made through the liquidation of the underlying assets. PHI views these investments as part of a long-term investment strategy. These investments are valued by each investment manager based on the underlying assets. The majority of the underlying assets are valued using significant unobservable inputs and often require significant management judgment or estimation based on the best available information. Market data includes observations of the trading multiples of public companies considered comparable to the private companies being valued. The funds utilize valuation techniques consistent with the market, income and cost approaches to measure the fair value of certain real estate investments. In accordance with FASB guidance on fair value measurement, PHI does not classify these investments within the fair value hierarchy.

The investments in private equity and real estate funds require capital commitments, which may be called over a specific number of years. Unfunded capital commitments as of December 31, 2015 and 2014 totaled $9 million and $11 million, respectively.

Reconciliations of the beginning and ending balances of PHI’s fair value measurements using significant unobservable inputs (level 3) for investments in the pension plan for the years ended December 31, 2015 and 2014 are shown below:

	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Equity		Fixed Income			Total Level 3
			(millions of dollars)
Balance as of January 1, 2015	$	1	$	11		$	12
Transfer in (out) of Level 3		—		—			—
Purchases		—		—			—
Sales		—		—			—
Settlements		—		(1	)		(1	)
Unrealized gain (loss)		—		—			—
Realized gain		—		—			—
Balance as of December 31, 2015	$	1	$	10		$	11
	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Equity		Fixed Income			Total Level 3
			(millions of dollars)
Balance as of January 1, 2014	$	1	$	11		$	12
Transfer in (out) of Level 3		—		—			—
Purchases		—		—			—
Sales		—		—			—
Settlements		—		—			—
Unrealized gain (loss)		—		—			—
Realized gain		—		—			—
Balance as of December 31, 2014	$	1	$	11		$	12

Cash Flows

Contributions - PHI Retirement Plan

PHI’s funding policy with regard to the PHI Retirement Plan is to maintain a funding level that is at least equal to the target liability as defined under the Pension Protection Act of 2006, as modified by subsequent legislation. During 2015 and 2014, PHI, Pepco, DPL and ACE did not make any discretionary tax-deductible contributions to the PHI Retirement Plan as its assets met or exceeded the funding target level for 2015 and 2014.

Contributions - Other Postretirement Benefit Plan

In 2015 and 2014, Pepco contributed $2 million and $1 million, respectively, DPL made no contributions in either year, and ACE contributed $3 million and $3 million, respectively, to the other postretirement benefit plan. In 2015 and 2014, no contributions were made by PHI’s other subsidiaries.

Expected Benefit Payments

Estimated future benefit payments to participants in PHI’s pension and other postretirement benefit plans, which reflect expected future service as appropriate, are as follows:

Years	Pension Benefits		Other Postretirement Benefits
	(millions of dollars)
2016	$	143	$	38
2017		143		38
2018		148		38
2019		153		38
2020		158		38
2021 through 2025		836		189

Pepco Holdings Retirement Savings Plan

Pepco Holdings has a defined contribution retirement savings plan. Participation in the plan is voluntary. All participants are 100% vested and have a nonforfeitable interest in their own contributions and in the Pepco Holdings’ company matching contributions, including any earnings or losses thereon. Pepco Holdings’ matching contributions were $14 million, $13 million and $12 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Potomac Electric Power Co [Member]

Pension and Other Postretirement Benefits

(8) PENSION AND OTHER POSTRETIREMENT BENEFITS

Pepco accounts for its participation in PHI’s single-employer plans, the PHI Retirement Plan and its other postretirement benefits plan, the Pepco Holdings, Inc. Welfare Plan for Retirees (the OPEB Plan), as participation in multiemployer plans. For 2015, 2014 and 2013, Pepco was responsible for $30 million, $22 million and $34 million, respectively, of the pension and other postretirement net periodic benefit cost incurred by PHI. For the years ended December 31, 2015, 2014 and 2013, Pepco made no discretionary tax-deductible contributions to the PHI Retirement Plan. Pepco made contributions of $2 million, $1 million and $6 million, respectively, to the OPEB Plan for the years ended December 31, 2015, 2014 and 2013. At December 31, 2015 and 2014, Pepco’s Prepaid pension expense of $291 million and $316 million, respectively, and Other postretirement benefit obligations of $49 million and $57 million, respectively, effectively represent assets and benefit obligations resulting from Pepco’s participation in the Pepco Holdings benefit plans.

Other Postretirement Benefit Plan Amendments

During 2013, PHI approved two amendments to its other postretirement benefits plan. These amendments impacted the retiree medical plan and the retiree life insurance benefits, and became effective on January 1, 2014. As a result of the amendments, which were cumulatively significant, PHI remeasured its projected benefit obligation for other postretirement benefits as of July 1, 2013. The remeasurement resulted in a $7 million reduction in Pepco’s net periodic benefit cost for other postretirement benefits in 2014, when compared to 2013. Approximately 40% of net periodic other postretirement benefit costs were capitalized in 2014.

Delmarva Power & Light Co/De [Member]

Pension and Other Postretirement Benefits

(9) PENSION AND OTHER POSTRETIREMENT BENEFITS

DPL accounts for its participation in PHI’s single-employer plans, the PHI Retirement Plan and its other postretirement benefits plan, the Pepco Holdings, Inc. Welfare Plan for Retirees (the OPEB Plan), as participation in multiemployer plans. For 2015, 2014 and 2013, DPL was responsible for $15 million, $7 million and $18 million, respectively, of the pension and other postretirement net periodic benefit cost incurred by PHI. DPL made a discretionary tax-deductible contribution to the PHI Retirement Plan of zero, zero and $10 million for the years ended December 31, 2015, 2014 and 2013, respectively. In addition, DPL made contributions of zero, zero and $3 million, respectively, to the OPEB Plan for the years ended December 31, 2015, 2014 and 2013. At December 31, 2015 and 2014, DPL’s Prepaid pension expense of $205 million and $220 million, respectively, and Other postretirement benefit obligations of $19 million and $21 million, respectively, effectively represent assets and benefit obligations resulting from DPL’s participation in the PHI benefit plans.

Other Postretirement Benefit Plan Amendments

During 2013, PHI approved two amendments to its other postretirement benefits plan. These amendments impacted the retiree medical plan and the retiree life insurance benefits, and became effective on January 1, 2014. As a result of the amendments, which were cumulatively significant, PHI remeasured its projected benefit obligation for other postretirement benefits as of July 1, 2013. The remeasurement resulted in a $4 million reduction in DPL’s net periodic benefit cost for other postretirement benefits in 2014, when compared to 2013.

Atlantic City Electric Co [Member]

Pension and Other Postretirement Benefits

(8) PENSION AND OTHER POSTRETIREMENT BENEFITS

ACE accounts for its participation in PHI’s single-employer plans, the PHI Retirement Plan and its other postretirement benefits plan, the Pepco Holdings, Inc. Welfare Plan for Retirees (the OPEB Plan), as participation in multiemployer plans. For 2015, 2014 and 2013, ACE was responsible for $15 million, $13 million and $17 million, respectively, of the pension and other postretirement net periodic benefit cost incurred by PHI. ACE made discretionary tax-deductible contributions of zero, zero and $30 million to the PHI Retirement Plan for the years ended December 31, 2015, 2014 and 2013, respectively. In addition, ACE made contributions of $3 million, $3 million and $6 million to the OPEB Plan for the years ended December 31, 2015, 2014 and 2013, respectively. At December 31, 2015 and 2014, ACE’s Prepaid pension expense of $83 million and $96 million, and Other postretirement benefit obligations of $33 million and $36 million, respectively, effectively represent assets and benefit obligations resulting from ACE’s participation in these PHI benefit plans.

Other Postretirement Benefit Plan Amendments

During 2013, PHI approved two amendments to its other postretirement benefits plan. These amendments impacted the retiree medical plan and the retiree life insurance benefits, and became effective on January 1, 2014. As a result of the amendments, which were cumulatively significant, PHI remeasured its projected benefit obligation for other postretirement benefits as of July 1, 2013. The remeasurement resulted in a $3 million reduction in ACE’s net periodic benefit cost for other postretirement benefits in 2014, when compared to 2013. Approximately 45% of net periodic other postretirement benefit costs were capitalized in 2014.

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Debt

12 Months Ended

Dec. 31, 2015

Debt

(10) DEBT

Long-Term Debt

The components of long-term debt are shown in the table below:

		At December 31,
Interest Rate	Maturity	2015		2014
		(millions of dollars)
First Mortgage Bonds
Pepco:
3.05%	2022	$	200	$	200
6.20% (a)(b)	2022		110		110
3.60%	2024		400		400
5.75% (c)(d)	2034		100		100
5.40% (c)(d)	2035		175		175
6.50% (a)(c)	2037		500		500
7.90%	2038		250		250
4.15%	2043		450		250
4.95%	2043		150		150
ACE:
7.68% (e)	2015 - 2016		2		17
7.75%	2018		250		250
6.80% (d)(f)	2021		39		39
4.35%	2021		200		200
3.375%	2024		150		150
3.50%	2025		150		—
4.875% (a)(f)	2029		23		23
5.80% (d)(g)	2034		120		120
5.80% (d)(g)	2036		105		105
DPL:
5.22% (h)	2016		100		100
3.50%	2023		500		500
4.00%	2042		250		250
4.15%	2045		200		—
Total First Mortgage Bonds			4,424		3,889
Unsecured Tax-Exempt Bonds
DPL:
5.40%	2031		78		78
Total Unsecured Tax-Exempt Bonds			78		78

NOTE: Schedule is continued on next page.

		At December 31,
Interest Rate	Maturity	2015			2014
		(millions of dollars)
Medium-Term Notes (unsecured)
DPL:
7.56% - 7.58%	2017	$	14		$	14
6.81%	2018		4			4
7.61%	2019		12			12
7.72%	2027		10			10
Total Medium-Term Notes (unsecured)			40			40
Notes (secured)
Pepco Energy Services:
6.70% - 7.46%	2015-2018		3			4
Notes (unsecured)
PHI:
2.70%	2015		—			250
5.90%	2016		190			190
6.125%	2017		81			81
7.45%	2032		185			185
DPL:
5.00%	2015		—			100
Total Notes (unsecured)			456			806
Total Long-Term Debt			5,001			4,817
Net unamortized discount			(2	)		(10	)
Unamortized debt issuance costs			(49	)		(44	)
Current portion of long-term debt			(294	)		(366	)
Total Net Long-Term Debt		$	4,656		$	4,397

(a) Represents a series of Collateral First Mortgage Bonds which must be cancelled and released as security for the issuer’s obligations under the corresponding series of issuer notes or tax-exempt bonds, at such time as the issuer does not have any first mortgage bonds outstanding (other than its Collateral First Mortgage Bonds), except that the issuer may not permit such release of collateral unless the issuer substitutes comparable obligations for such collateral.

(b) Represents a series of Collateral First Mortgage Bonds securing a series of senior notes issued by Pepco, which in turn secures a series of tax-exempt bonds issued for the benefit of Pepco.

(c) Represents a series of Collateral First Mortgage Bonds (as defined herein) securing a series of senior notes issued by Pepco.

(d) Represents a series of Collateral First Mortgage Bonds which must be cancelled and released as security for the issuer’s obligations under the corresponding series of issuer notes (as defined herein) or tax-exempt bonds, at such time as the issuer does not have any first mortgage bonds outstanding (other than its Collateral First Mortgage Bonds).

(e) Represents a series of Collateral First Mortgage Bonds securing a series of medium-term notes issued by ACE.

(f) Represents a series of Collateral First Mortgage Bonds securing a series of tax-exempt bonds issued for the benefit of ACE.

(g) Represents a series of Collateral First Mortgage Bonds securing a series of senior notes issued by ACE.

(h) Represents a series of Collateral First Mortgage Bonds securing a series of debt securities issued by DPL.

The outstanding first mortgage bonds issued by each of Pepco, DPL and ACE are issued under a mortgage and deed of trust and are secured by a first lien on substantially all of the issuing company’s property, plant and equipment, except for certain property excluded from the lien of the respective mortgage.

PHI’s long-term debt is subject to certain covenants. As of December 31, 2015, PHI and its subsidiaries were in compliance with all such covenants.

The table above does not separately identify $885 million, $100 million and $227 million in aggregate principal amount of senior notes, medium term notes and other debt securities (issuer notes) issued by each of Pepco, DPL and ACE, respectively, and $110 million and $62 million in aggregate principal amount of tax-exempt bonds issued for the benefit of Pepco and ACE, respectively. These issuer notes are secured by a like amount of first mortgage bonds (Collateral First Mortgage Bonds) of each respective issuer. In addition, these tax-exempt bonds are secured by a like amount of Collateral First Mortgage Bonds issued by the utility subsidiary for whose benefit the tax-exempt bonds were issued. The principal terms of each such series of issuer notes, or the issuer’s obligations in respect of each such series of tax-exempt bonds, are identical to the same terms of the corresponding series of Collateral First Mortgage Bonds. Payments of principal and interest made on a series of such issuer notes, or the satisfaction of the issuer’s obligations in respect of a series of such tax-exempt bonds, satisfy the corresponding obligations on the related series of Collateral First Mortgage Bonds. For these reasons, each such series of Collateral First Mortgage Bonds and the corresponding issuer notes and/or tax-exempt bonds together effectively represent a single financial obligation and are not identified in the table above separately.

Bond Issuances

During 2015, Pepco issued $200 million of 4.15% first mortgage bonds due March 15, 2043, with a 3.9% yield to maturity. Net proceeds from the issuance of the bonds, which included a premium of $8 million, were used by Pepco to repay outstanding commercial paper and for general corporate purposes.

During 2015, DPL issued $200 million of 4.15% first mortgage bonds due May 15, 2045. Net proceeds from the issuance of the bonds were used by DPL to repay outstanding commercial paper and for general corporate purposes.

During 2015, ACE issued $150 million of 3.50% first mortgage bonds due December 1, 2025 in a private placement. The net proceeds from the issuance of the bonds were used by ACE to repay outstanding commercial paper and for general corporate purposes.

Note Retirements

During 2015, ACE retired, at maturity, $15 million of its secured medium-term notes series C. The medium-term notes were secured by a like principal amount of its 7.68% first mortgage bonds due August 24, 2015, which under the mortgage and deed of trust were deemed to be satisfied when the medium-term notes were repaid.

During 2015, DPL retired, at maturity, $100 million of its 5.00% unsecured notes due June 1, 2015.

During 2015, PHI retired, at maturity, $250 million of its 2.70% unsecured notes due October 1, 2015.

Transition Bonds Issued by ACE Funding

The components of transition bonds are shown in the table below:

		At December 31,
Interest Rate	Maturity	2015			2014
		(millions of dollars)
4.91%	2017	$	—		$	17
5.05%	2020		39			51
5.55%	2023		132			147
Total Transition Bonds			171			215
Unamortized debt issuance costs			(1	)		(1	)
Current portion of long-term debt			(46	)		(44	)
Total Net Long-Term Transition Bonds		$	124		$	170

For a description of the Transition Bonds, see Note (17), “Variable Interest Entities – ACE Funding.”

Maturities of PHI’s Long-term Debt and Transition Bonds

Maturities of PHI’s long-term debt and Transition Bonds outstanding at December 31, 2015 are $340 million in 2016, $131 million in 2017, $285 million in 2018, $30 million in 2019, $20 million in 2020 and $4,366 million thereafter.

Long-Term Project Funding

As of December 31, 2015 and 2014, Pepco Energy Services had total outstanding long-term project funding (including current maturities) of $5 million and $10 million, respectively, related to energy savings contracts performed by Pepco Energy Services. The aggregate amounts of maturities for the project funding debt outstanding at December 31, 2015 are $1 million in each of the years 2016 and 2017, zero in 2018, $1 million in 2019, $1 million in 2020, and $1 million thereafter.

Short-Term Debt

PHI and its regulated utility subsidiaries have traditionally used a number of sources to fulfill short-term funding needs, such as commercial paper, short-term notes, and bank lines of credit. Proceeds from short-term borrowings are used primarily to meet working capital needs, but may also be used to temporarily fund long-term capital requirements. The components of PHI’s short-term debt at December 31, 2015 and 2014 are as follows:

	2015		2014
	(millions of dollars)
Commercial paper	$	658	$	624
Variable rate demand bonds		105		105
Term loan		300		—
Total	$	1,063	$	729

Commercial Paper

PHI, Pepco, DPL and ACE maintain ongoing commercial paper programs to address short-term liquidity needs. As of December 31, 2015, the maximum capacity available under these programs was $875 million, $500 million, $500 million and $350 million, respectively, subject to available borrowing capacity under the credit facility.

PHI, Pepco, DPL and ACE had $484 million, $64 million, $105 million and $5 million, respectively, of commercial paper outstanding at December 31, 2015. The weighted average interest rate for commercial paper issued by PHI, Pepco, DPL and ACE during 2015 was 0.80%, 0.44%, 0.47% and 0.46%, respectively. The weighted average maturity of all commercial paper issued by PHI, Pepco, DPL and ACE during 2015 was ten, four, four and six days, respectively.

PHI, Pepco, DPL and ACE had $287 million, $104 million, $106 million and $127 million, respectively, of commercial paper outstanding at December 31, 2014. The weighted average interest rate for commercial paper issued by PHI, Pepco, DPL and ACE during 2014 was 0.57%, 0.28%, 0.26% and 0.27%, respectively. The weighted average maturity of all commercial paper issued by PHI, Pepco, DPL and ACE during 2014 was six, six, five and five days, respectively.

Variable Rate Demand Bonds

PHI’s utility subsidiary DPL has outstanding obligations in respect of Variable Rate Demand Bonds (VRDB). VRDBs are subject to repayment on the demand of the holders and, for this reason, are accounted for as short-term debt in accordance with GAAP. However, bonds submitted for purchase are remarketed by a remarketing agent on a best efforts basis. PHI expects that any bonds submitted for purchase will be remarketed successfully due to the creditworthiness of the issuer and, as applicable, the credit support, and because the remarketing resets the interest rate to the then-current market rate. The bonds may be converted to a fixed-rate, fixed-term option to establish a maturity which corresponds to the date of final maturity of the bonds. On this basis, PHI views VRDBs as a source of long-term financing. As of December 31, 2015, $105 million of VRDBs issued on behalf of DPL were outstanding (of which $72 million were secured by Collateral First Mortgage Bonds issued by DPL). During 2014, ACE retired, at maturity, its last remaining VRDBs in the amount of $18 million.

The VRDBs outstanding at December 31, 2015 mature as follows: 2017 ($26 million), 2024 ($33 million), 2028 ($16 million), and 2029 ($30 million). The weighted average interest rate for VRDBs outstanding on December 31, 2015 was 0.13% during 2015 and 0.19% during 2014.

PHI Term Loan Agreements

On January 13, 2016, PHI entered into a $500 million term loan agreement, pursuant to which PHI borrowed $500 million at a rate of interest equal to the prevailing Eurodollar rate, which is determined by reference to the London Interbank Offered Rate with respect to the relevant interest period, all as defined in the loan agreement, plus a margin of 0.90%. PHI used the net proceeds of the loan under the loan agreement to repay its outstanding commercial paper, and for general corporate purposes. All indebtedness incurred under the loan agreement is unsecured, and the aggregate principal amount of all loans, together with any accrued but unpaid interest due under the loan agreement, must be repaid in full on or before July 13, 2016. Pursuant to the term loan agreement, PHI may consummate the Merger and the subsequent conversion of PHI from a Delaware corporation to a Delaware limited liability company, provided that the Merger and subsequent conversion are consummated on or before October 29, 2015. PHI requested and obtained the consent of the lenders under the term loan to allow for completion of the Merger by June 30, 2016.

On July 30, 2015, PHI entered into a $300 million term loan agreement, pursuant to which PHI borrowed $300 million at a rate of interest equal to the prevailing Eurodollar rate, which is determined by reference to the LIBOR with respect to the relevant interest period, all as defined in the loan agreement, plus a margin of 0.95%. PHI used the net proceeds of the loan under the loan agreement to repay a portion of its outstanding commercial paper, and for general corporate purposes. All indebtedness incurred under the loan agreement is unsecured, and the aggregate principal amount of all loans, together with any accrued but unpaid interest due under the loan agreement, must be repaid in full on or before July 28, 2016. Pursuant to the term loan agreement, PHI may consummate the Merger and the subsequent conversion of PHI from a Delaware corporation to a Delaware limited liability company, provided that the Merger and subsequent conversion are consummated on or before October 29, 2015. PHI requested and obtained the consent of the lenders under the term loan to allow for completion of the Merger by June 30, 2016.

Credit Facility

PHI, Pepco, DPL and ACE maintain an unsecured syndicated credit facility to provide for their respective liquidity needs, including obtaining letters of credit, borrowing for general corporate purposes and supporting their commercial paper programs. On August 1, 2013, as permitted under the existing terms of the credit agreement, a request by PHI, Pepco, DPL and ACE to extend the credit facility termination date to August 1, 2018 was approved. All of the terms and conditions as well as pricing remained the same.

The aggregate borrowing limit under the amended and restated credit facility is $1.5 billion, all or any portion of which may be used to obtain loans and up to $500 million of which may be used to obtain letters of credit. The facility also includes a swingline loan sub-facility, pursuant to which each company may make same day borrowings in an aggregate amount not to exceed 10% of the total amount of the facility. Any swingline loan must be repaid by the borrower within fourteen days of receipt. The credit sublimit is $750 million for PHI and $250 million for each of Pepco, DPL and ACE. The sublimits may be increased or decreased by the individual borrower during the term of the facility, except that (i) the sum of all of the borrower sublimits following any such increase or decrease must equal the total amount of the facility and (ii) the aggregate amount of credit used at any given time by (a) PHI may not exceed $1.25 billion and (b) each of Pepco, DPL or ACE may not exceed the lesser of $500 million and the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the sublimit reallocations may not exceed eight per year during the term of the facility.

The interest rate payable by each company on utilized funds is, at the borrowing company’s election, (i) the greater of the prevailing prime rate, the federal funds effective rate plus 0.5% and the one month London Interbank Offered Rate (LIBOR) plus 1.0%, or (ii) the prevailing Eurodollar rate, plus a margin that varies according to the credit rating of the borrower.

In order for a borrower to use the facility, certain representations and warranties must be true and correct, and the borrower must be in compliance with specified financial and other covenants, including (i) the requirement that each borrowing company maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the credit agreement, which calculation excludes from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) with certain exceptions, a restriction on sales or other dispositions of assets, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than permitted liens. The credit agreement contains certain covenants and other customary agreements and requirements that, if not complied with, could result in an event of default and the acceleration of repayment obligations of one or more of the borrowers thereunder. Each of the borrowers was in compliance with all covenants under this facility at December 31, 2015.

The absence of a material adverse change in PHI’s business, property, results of operations or financial condition is not a condition to the availability of credit under the credit agreement. The credit agreement does not include any rating triggers.

As of December 31, 2015 and December 31, 2014, the amount of cash plus unused borrowing capacity under the credit facility available to meet the future liquidity needs of PHI and its utility subsidiaries on a consolidated basis totaled $851 million and $875 million, respectively. PHI’s utility subsidiaries had combined cash and unused borrowing capacity under the credit facility of $576 million and $413 million at December 31, 2015 and December 31, 2014, respectively.

Credit Facility Amendment

During 2014, PHI, Pepco, DPL and ACE entered into an amendment of and consent with respect to the credit agreement (the Consent). PHI was required to obtain the consent of certain of the lenders under the credit facility in order to permit the consummation of the Merger. Pursuant to the Consent, certain of the lenders consented to the consummation of the Merger and the subsequent conversion of PHI from a Delaware corporation to a Delaware limited liability company, provided that the Merger and subsequent conversion are consummated on or before October 29, 2015. In addition, the Consent amends the definition of “Change in Control” in the credit agreement to mean, following consummation of the Merger, an event or series of events by which Exelon no longer owns, directly or indirectly, 100% of the outstanding shares of voting stock of Pepco Holdings. PHI requested and obtained an extension of the Consent to allow for completion of the Merger by June 30, 2016.

Other Financing Activities

Sale of Receivables

During 2015, Pepco, as seller, entered into a purchase agreement with a buyer to sell receivables from an energy savings project over a period of time pursuant to a task order. The purchase price to be received by Pepco is $5 million. Pursuant to the purchase agreement, following acceptance of the energy savings project by the buyer, the buyer is entitled to receive the contract payments under the task order payable by the customer over approximately 15 years. The energy savings project will be performed by Pepco Energy Services and is expected to be completed by the end of 2017.

During 2014, Pepco, as seller, entered into a purchase agreement with a buyer to sell receivables from an energy savings project pursuant to a task order entered into under a General Services Administration area-wide agreement. The purchase price received by Pepco was $12 million, which was included in the Current portion of long-term debt and project funding at December 31, 2014. The energy savings project was performed by Pepco Energy Services and was completed in 2014. Pursuant to the purchase agreement, following acceptance of the energy savings project by the buyer, the buyer was entitled to receive the contract payments under the task order payable by the buyer over approximately 9 years. The energy savings project was accepted during the first quarter of 2015 and the amount was removed from the Current portion of long-term debt and project funding.

During 2013, Pepco Energy Services, as seller, entered into a purchase agreement with a buyer to sell receivables from an energy savings project over a period of time pursuant to a task order. The purchase price received by Pepco Energy Services was $7 million, which was included in the Current portion of long-term debt and project funding at December 31, 2014. Pursuant to the purchase agreement, following acceptance of the energy savings project by the buyer, the buyer is entitled to receive the contract payments under the task order payable by the customer over approximately 23 years. The energy savings project was accepted during the first quarter of 2015 and the amount was removed from the Current portion of long-term debt and project funding.

ACE Term Loan Agreement

On May 10, 2013, ACE entered into a $100 million term loan agreement, pursuant to which ACE borrowed $100 million at a rate of interest equal to the prevailing Eurodollar rate, which was determined by reference to the LIBOR with respect to the relevant interest period, all as defined in the loan agreement, plus a margin of 0.75%. On August 21, 2014, ACE repaid the term loan in full.

Potomac Electric Power Co [Member]

Debt

(9) DEBT

Long-Term Debt

The components of long-term debt are shown in the table below:

Type of Debt	Interest Rate			Maturity	2015			2014
					(millions of dollars)
First Mortgage Bonds
		3.05	%	2022	$	200		$	200
		6.20	%(a)(b)	2022		110			110
		3.60	%	2024		400			400
		5.75	%(c)(d)	2034		100			100
		5.40	%(c)(d)	2035		175			175
		6.50	%(a)(c)	2037		500			500
		7.90	%	2038		250			250
		4.15	%	2043		450			250
		4.95	%	2043		150			150
Total long-term debt						2,335			2,135
Net unamortized discount						(3	)		(11	)
Unamortized debt issuance costs						(31	)		(28	)
Total net long-term debt					$	2,301		$	2,096

(a) Represents a series of Collateral First Mortgage Bonds which must be cancelled and released as security for Pepco’s obligations under the corresponding series of senior notes or tax-exempt bonds, at such time as Pepco does not have any first mortgage bonds outstanding (other than its Collateral First Mortgage Bonds), except that Pepco may not permit such release of collateral unless Pepco substitutes comparable obligations for such collateral.

(b) Represents a series of Collateral First Mortgage Bonds securing a series of senior notes issued by Pepco, which in turn secures a series of tax-exempt bonds issued for the benefit of Pepco.

(c) Represents a series of Collateral First Mortgage Bonds (as defined herein) securing a series of senior notes issued by Pepco.

(d) Represents a series of Collateral First Mortgage Bonds which must be cancelled and released as security for Pepco’s obligations under the corresponding series of senior notes or tax-exempt bonds, at such time as Pepco does not have any first mortgage bonds outstanding (other than its Collateral First Mortgage Bonds).

The outstanding first mortgage bonds are issued under a mortgage and deed of trust and are secured by a first lien on substantially all of Pepco’s property, plant and equipment, except for certain property excluded from the lien of the mortgage.

Maturities of Pepco’s long-term debt outstanding at December 31, 2015, are zero in 2016 through 2020, and $2,335 million, thereafter.

Pepco’s long-term debt is subject to certain covenants. As of December 31, 2015, Pepco is in compliance with all such covenants.

The table above does not separately identify $885 million in aggregate principal amount of senior notes issued by Pepco and $110 million in aggregate principal amount of tax-exempt bonds issued for the benefit of Pepco. These senior notes are secured by a like amount of first mortgage bonds (Collateral First Mortgage Bonds) of Pepco. In addition, these tax-exempt bonds are secured by a like amount of Collateral First Mortgage Bonds issued by Pepco. The principal terms of each such series of senior notes, or Pepco’s obligations in respect of each such series of tax-exempt bonds, are identical to the same terms of the corresponding series of Collateral First Mortgage Bonds. Payments of principal and interest made on a series of such senior notes, or the satisfaction of Pepco’s obligations in respect of a series of such tax-exempt bonds, satisfy the corresponding obligations on the related series of Collateral First Mortgage Bonds. For these reasons, each such series of Collateral First Mortgage Bonds and the corresponding senior notes and/or tax-exempt bonds together effectively represent a single financial obligation and are not identified in the table above separately.

Bond Issuances

During 2015, Pepco issued $200 million of 4.15% first mortgage bonds due March 15, 2043, with a 3.9% yield to maturity. Net proceeds from the issuance of the bonds, which included a premium of $8 million, were used by Pepco to repay outstanding commercial paper and for general corporate purposes.

Short-Term Debt

Pepco has traditionally used a number of sources to fulfill short-term funding needs, such as commercial paper, short-term notes, and bank lines of credit. Proceeds from short-term borrowings are used primarily to meet working capital needs, but may also be used to temporarily fund long-term capital requirements. Pepco’s short-term debt at December 31, 2015 and 2014 consisted of the following:

	2015		2014
	(millions of dollars)
Commercial paper	$	64	$	104

Commercial Paper

Pepco maintains an ongoing commercial paper program to address its short-term liquidity needs. As of December 31, 2015, the maximum capacity available under the program was $500 million, subject to available borrowing capacity under the credit facility.

Pepco had $64 million and $104 million of commercial paper outstanding at December 31, 2015 and 2014, respectively. The weighted average interest rates for commercial paper issued by Pepco during 2015 and 2014 were 0.44% and 0.28%, respectively. The weighted average maturity of all commercial paper issued by Pepco during 2015 and 2014 was four days and six days, respectively.

Credit Facility

PHI, Pepco, DPL and ACE maintain an unsecured syndicated credit facility to provide for their respective liquidity needs, including obtaining letters of credit, borrowing for general corporate purposes and supporting their commercial paper programs. On August 1, 2013, as permitted under the existing terms of the credit agreement, a request by PHI, Pepco, DPL and ACE to extend the credit facility termination date to August 1, 2018 was approved. All of the terms and conditions as well as pricing remained the same.

The aggregate borrowing limit under the amended and restated credit facility is $1.5 billion, all or any portion of which may be used to obtain loans and up to $500 million of which may be used to obtain letters of credit. The facility also includes a swingline loan sub-facility, pursuant to which each company may make same day borrowings in an aggregate amount not to exceed 10% of the total amount of the facility. Any swingline loan must be repaid by the borrower within fourteen days of receipt. The credit sublimit is $750 million for PHI and $250 million for each of Pepco, DPL and ACE. The sublimits may be increased or decreased by the individual borrower during the term of the facility, except that (i) the sum of all of the borrower sublimits following any such increase or decrease must equal the total amount of the facility and (ii) the aggregate amount of credit used at any given time by (a) PHI may not exceed $1.25 billion and (b) each of Pepco, DPL or ACE may not exceed the lesser of $500 million and the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the sublimit reallocations may not exceed eight per year during the term of the facility.

The interest rate payable by each company on utilized funds is, at the borrowing company’s election, (i) the greater of the prevailing prime rate, the federal funds effective rate plus 0.5% and the one month London Interbank Offered Rate plus 1.0%, or (ii) the prevailing Eurodollar rate, plus a margin that varies according to the credit rating of the borrower.

In order for a borrower to use the facility, certain representations and warranties must be true and correct, and the borrower must be in compliance with specified financial and other covenants, including (i) the requirement that each borrowing company maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the credit agreement, which calculation excludes from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) with certain exceptions, a restriction on sales or other dispositions of assets, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than permitted liens. The credit agreement contains certain covenants and other customary agreements and requirements that, if not complied with, could result in an event of default and the acceleration of repayment obligations of one or more of the borrowers thereunder. Each of the borrowers was in compliance with all covenants under this facility at December 31, 2015.

The absence of a material adverse change in PHI’s business, property, results of operations or financial condition is not a condition to the availability of credit under the credit agreement. The credit agreement does not include any rating triggers.

As of December 31, 2015 and 2014, the amount of cash plus borrowing capacity under the credit facility available to meet the liquidity needs of PHI’s utility subsidiaries in the aggregate was $576 million and $413 million, respectively. Pepco’s borrowing capacity under the credit facility at any given time depends on the amount of the subsidiary borrowing capacity being utilized by DPL and ACE and the portion of the total capacity being used by PHI.

Credit Facility Amendment

During 2014, PHI, Pepco, DPL and ACE entered into an amendment of and consent with respect to the credit agreement (the Consent). PHI was required to obtain the consent of certain of the lenders under the credit facility in order to permit the consummation of the Merger. Pursuant to the Consent, certain of the lenders consented to the consummation of the Merger and the subsequent conversion of PHI from a Delaware corporation to a Delaware limited liability company, provided that the Merger and subsequent conversion are consummated on or before October 29, 2015. In addition, the Consent amends the definition of “Change in Control” in the credit agreement to mean, following consummation of the Merger, an event or series of events by which Exelon no longer owns, directly or indirectly, 100% of the outstanding shares of voting stock of Pepco Holdings. PHI requested and obtained an extension of the Consent to allow for completion of the Merger by June 30, 2016.

Other Financing Activities

Sale of Receivables

During 2015, Pepco, as seller, entered into a purchase agreement with a buyer to sell receivables from an energy savings project over a period of time pursuant to a task order. The purchase price to be received by Pepco is $5 million. Pursuant to the purchase agreement, following acceptance of the energy savings project by the buyer, the buyer is entitled to receive the contract payments under the task order payable by the customer over approximately 15 years. The energy savings project will be performed by Pepco Energy Services, Inc. and its subsidiaries (Pepco Energy Services) and is expected to be completed by the end of 2017.

During 2014, Pepco, as seller, entered into a purchase agreement with a buyer to sell receivables from an energy savings project pursuant to a task order entered into under a General Services Administration area-wide agreement. The purchase price received by Pepco was $12 million, which was included in the Current portion of long-term debt and project funding at December 31, 2014. The energy savings project was performed by Pepco Energy Services and was completed in 2014. Pursuant to the purchase agreement, following acceptance of the energy savings project by the buyer, the buyer was entitled to receive the contract payments under the task order payable by the buyer over approximately 9 years. The energy savings project was accepted during the first quarter of 2015 and the amount was removed from the Current portion of long-term debt and project funding.

Delmarva Power & Light Co/De [Member]

Debt

(10) DEBT

Long-Term Debt

The components of long-term debt are shown in the table below:

Type of Debt	Interest Rate	Maturity	2015			2014
			(millions of dollars)
First Mortgage Bonds
	5.22%(a)	2016	$	100		$	100
	3.50%	2023		500			500
	4.00%	2042		250			250
	4.15%	2045		200			—
				1,050			850
Unsecured Tax-Exempt Bonds
	5.40%	2031		78			78
				78			78
Medium-Term Notes (unsecured)
	7.56%-7.58%	2017		14			14
	6.81%	2018		4			4
	7.61%	2019		12			12
	7.72%	2027		10			10
				40			40
Notes (unsecured)
	5.00%	2015		—			100
				—			100
Total long-term debt				1,168			1,068
Net unamortized premium				2			3
Unamortized debt issuance costs				(9	)		(8	)
Current portion of long-term debt				(100	)		(100	)
Total net long-term debt			$	1,061		$	963

(a) Represents a series of Collateral First Mortgage Bonds securing a series of debt securities issued by DPL.

The outstanding first mortgage bonds issued by DPL are issued under a Mortgage and Deed of Trust and are secured by a first lien on substantially all of DPL’s property, plant and equipment, except for certain property excluded from the lien of the mortgage.

Maturities of DPL’s long-term debt outstanding at December 31, 2015 are $100 million in 2016, $14 million in 2017, $4 million in 2018, $12 million in 2019, zero in 2020 and $1,038 million thereafter.

DPL’s long-term debt is subject to certain covenants. As of December 31, 2015, DPL is in compliance with all such covenants.

The table above does not separately identify $100 million in aggregate principal amount of debt securities issued by DPL. These debt securities are secured by a like amount of first mortgage bonds (Collateral First Mortgage Bonds) of DPL. The principal terms of each such series of debt securities are identical to the same terms of the corresponding series of Collateral First Mortgage Bonds. Payments of principal and interest made on a series of such debt securities, satisfy the corresponding obligations on the related series of Collateral First Mortgage Bonds. For these reasons, each such series of Collateral First Mortgage Bonds and the corresponding debt securities together effectively represent a single financial obligation and are not identified in the table above separately.

Bond Issuance

During 2015, DPL issued $200 million of 4.15% first mortgage bonds due May 15, 2045. Net proceeds from the issuance of the bonds were used by DPL to repay outstanding commercial paper and for general corporate purposes.

Note Retirements

During 2015, DPL retired, at maturity, $100 million of its 5.00% unsecured notes due June 1, 2015.

Short-Term Debt

DPL has traditionally used a number of sources to fulfill short-term funding needs, such as commercial paper, short-term notes, and bank lines of credit. Proceeds from short-term borrowings are used primarily to meet working capital needs, but may also be used to temporarily fund long-term capital requirements. The components of DPL’s short-term debt at December 31, 2015 and 2014 are as follows:

	2015		2014
	(millions of dollars)
Commercial paper	$	105	$	106
Variable rate demand bonds		105		105
Total	$	210	$	211

Commercial Paper

DPL maintains an ongoing commercial paper program to address its short-term liquidity needs. As of December 31, 2015, the maximum capacity available under the program was $500 million, subject to available borrowing capacity under the credit facility.

DPL had $105 million and $106 million of commercial paper outstanding at December 31, 2015 and 2014, respectively. The weighted average interest rates for commercial paper issued by DPL during 2015 and 2014 were 0.47% and 0.26%, respectively. The weighted average maturity of all commercial paper issued by DPL during 2015 and 2014 was four days and five days, respectively.

Variable Rate Demand Bonds

Variable Rate Demand Bonds (VRDBs) are subject to repayment on the demand of the holders and, for this reason, are accounted for as short-term debt in accordance with accounting principles generally accepted in the United States of America. However, bonds submitted for purchase are remarketed by a remarketing agent on a best efforts basis. DPL expects that any bonds submitted for purchase will continue to be remarketed successfully due to the creditworthiness of the company and because the remarketing agent resets the interest rate to the then-current market rate. The bonds may be converted to a fixed rate, fixed term option to establish a maturity which corresponds to the date of final maturity of the bonds. On this basis, DPL views VRDBs as a source of long-term financing. The VRDBs outstanding in 2015 mature as follows: 2017 ($26 million), 2024 ($33 million), 2028 ($16 million), and 2029 ($30 million). The weighted average interest rate for VRDBs was 0.13% during 2015 and 0.19% during 2014. As of December 31, 2015, $105 million in VRDBs issued on behalf of DPL were outstanding (of which $72 million were secured by Collateral First Mortgage Bonds issued by DPL).

Credit Facility

PHI, Pepco, DPL and ACE maintain an unsecured syndicated credit facility to provide for their respective liquidity needs, including obtaining letters of credit, borrowing for general corporate purposes and supporting their commercial paper programs. On August 1, 2013, as permitted under the existing terms of the credit agreement, a request by PHI, Pepco, DPL and ACE to extend the credit facility termination date to August 1, 2018 was approved. All of the terms and conditions as well as pricing remained the same.

The aggregate borrowing limit under the amended and restated credit facility is $1.5 billion, all or any portion of which may be used to obtain loans and up to $500 million of which may be used to obtain letters of credit. The facility also includes a swingline loan sub-facility, pursuant to which each company may make same day borrowings in an aggregate amount not to exceed 10% of the total amount of the facility. Any swingline loan must be repaid by the borrower within fourteen days of receipt. The credit sublimit is $750 million for PHI and $250 million for each of Pepco, DPL and ACE. The sublimits may be increased or decreased by the individual borrower during the term of the facility, except that (i) the sum of all of the borrower sublimits following any such increase or decrease must equal the total amount of the facility, and (ii) the aggregate amount of credit used at any given time by (a) PHI may not exceed $1.25 billion, and (b) each of Pepco, DPL or ACE may not exceed the lesser of $500 million or the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the sublimit reallocations may not exceed eight per year during the term of the facility.

The interest rate payable by each company on utilized funds is, at the borrowing company’s election, (i) the greater of the prevailing prime rate, the federal funds effective rate plus 0.5% and the one month London Interbank Offered Rate plus 1.0%, or (ii) the prevailing Eurodollar rate, plus a margin that varies according to the credit rating of the borrower.

In order for a borrower to use the facility, certain representations and warranties must be true and correct, and the borrower must be in compliance with specified financial and other covenants, including (i) the requirement that each borrowing company maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the credit agreement, which calculation excludes from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) with certain exceptions, a restriction on sales or other dispositions of assets, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than permitted liens. The credit agreement contains certain covenants and other customary agreements and requirements that, if not complied with, could result in an event of default and the acceleration of repayment obligations of one or more of the borrowers thereunder. Each of the borrowers was in compliance with all covenants under this facility at December 31, 2015.

The absence of a material adverse change in PHI’s business, property, results of operations or financial condition is not a condition to the availability of credit under the credit agreement. The credit agreement does not include any rating triggers.

As of December 31, 2015 and 2014, the amount of cash plus borrowing capacity under the credit facility available to meet the liquidity needs of PHI’s utility subsidiaries in the aggregate was $576 million and $413 million, respectively. DPL’s borrowing capacity under the credit facility at any given time depends on the amount of the subsidiary borrowing capacity being utilized by Pepco and ACE and the portion of the total capacity being used by PHI.

Credit Facility Amendment

During 2014, PHI, Pepco, DPL and ACE entered into an amendment of and consent with respect to the credit agreement (the Consent). PHI was required to obtain the consent of certain of the lenders under the credit facility in order to permit the consummation of the Merger. Pursuant to the Consent, certain of the lenders consented to the consummation of the Merger and the subsequent conversion of PHI from a Delaware corporation to a Delaware limited liability company, provided that the Merger and subsequent conversion are consummated on or before October 29, 2015. In addition, the Consent amends the definition of “Change in Control” in the credit agreement to mean, following consummation of the Merger, an event or series of events by which Exelon no longer owns, directly or indirectly, 100% of the outstanding shares of voting stock of Pepco Holdings. PHI requested and obtained an extension of the Consent to allow for completion of the Merger by June 30, 2016.

Atlantic City Electric Co [Member]

Debt

(9) DEBT

Long-Term Debt

The components of long-term debt are shown in the table below:

Type of Debt	Interest Rate			Maturity	2015			2014
					(millions of dollars)
First Mortgage Bonds
		7.68	% (a)	2015-2016	$	2		$	17
		7.75	%	2018		250			250
		6.80	% (b)(c)	2021		39			39
		4.35	%	2021		200			200
		3.375	%	2024		150			150
		3.50	%	2025		150			—
		4.875	%(c)(d)	2029		23			23
		5.80	% (b)(e)	2034		120			120
		5.80	% (b)(e)	2036		105			105
Total long-term debt						1,039			904
Net unamortized discount						(1	)		(1	)
Unamortized debt issuance costs						(6	)		(6	)
Current portion of long-term debt						(2	)		(15	)
Total net long-term debt					$	1,030		$	882

(a) Represents a series of Collateral First Mortgage Bonds (as defined herein) securing a series of medium-term notes issued by ACE.

(b) Represents a series of Collateral First Mortgage Bonds which must be cancelled and released as security for ACE’s obligations under the corresponding series of issuer notes (as defined herein) or tax-exempt bonds, at such time as ACE does not have any first mortgage bonds outstanding (other than its Collateral First Mortgage Bonds).

(c) Represents a series of Collateral First Mortgage Bonds securing a series of tax-exempt bonds issued for the benefit of ACE.

(d) Represents a series of Collateral First Mortgage Bonds which must be cancelled and released as security for ACE’s obligations under the corresponding series of issuer notes or tax-exempt bonds, at such time as ACE does not have any first mortgage bonds outstanding (other than its Collateral First Mortgage Bonds), except that ACE may not permit such release of collateral unless ACE substitutes comparable obligations for such collateral.

(e) Represents a series of Collateral First Mortgage Bonds securing a series of senior notes issued by ACE.

The outstanding first mortgage bonds issued by ACE are issued under a mortgage and deed of trust and are secured by a first lien on substantially all of ACE’s property, plant and equipment, except for certain property excluded from the lien of the mortgage.

Maturities of ACE’s long-term debt outstanding at December 31, 2015 are $2 million in 2016, zero in 2017, $250 million in 2018, zero in 2019 and 2020, and $787 million thereafter.

ACE’s long-term debt is subject to certain covenants. As of December 31, 2015, ACE was in compliance with all such covenants.

The table above does not separately identify $227 million in aggregate principal amount of senior notes and medium term notes (issuer notes) issued by ACE and $62 million in aggregate principal amount of tax-exempt bonds issued for the benefit of ACE. These issuer notes and tax-exempt bonds are secured by a like amount of first mortgage bonds (Collateral First Mortgage Bonds) of ACE. The principal terms of each such series of issuer notes, or ACE’s obligations in respect of each such series of tax-exempt bonds, are identical to the same terms of the corresponding series of Collateral First Mortgage Bonds. Payments of principal and interest made on a series of such issuer notes, or the satisfaction of ACE obligations in respect of a series of such tax-exempt bonds, satisfy the corresponding obligations on the related series of Collateral First Mortgage Bonds. For these reasons, each such series of Collateral First Mortgage Bonds and the corresponding issuer notes or tax-exempt bonds together effectively represent a single financial obligation and are not identified in the table above separately.

Bond Issuance

During 2015, ACE issued $150 million of 3.50% first mortgage bonds due December 1, 2025 in a private placement. The net proceeds from the issuance of the bonds were used by ACE to repay outstanding commercial paper and for general corporate purposes.

Bond Retirement

During 2015, ACE retired, at maturity, $15 million of its secured medium-term notes series C. The medium-term notes were secured by a like principal amount of its 7.68% first mortgage bonds due August 24, 2015, which under the mortgage and deed of trust were deemed to be satisfied when the medium-term notes were repaid.

Transition Bonds Issued by ACE Funding

The components of transition bonds are shown in the table below:

Type of Debt	Interest Rate			Maturity	2015			2014
					(millions of dollars)
Transition Bonds
		4.91	%	2017	$	—		$	17
		5.05	%	2020		39			51
		5.55	%	2023		132			147
						171			215
Unamortized debt issuance costs						(1	)		(1	)
Current portion of long-term debt						(46	)		(44	)
Total net long-term Transition Bonds					$	124		$	170

For a description of the Transition Bonds, see Note (16), “Variable Interest Entities – ACE Funding.” Maturities of ACE’s Transition Bonds outstanding at December 31, 2015 are $46 million in 2016, $35 million in 2017, $31 million in 2018, $18 million in 2019, $20 million in 2020 and $21 million thereafter.

Short-Term Debt

ACE has traditionally used a number of sources to fulfill short-term funding needs, such as commercial paper, short-term notes, and bank lines of credit. Proceeds from short-term borrowings are used primarily to meet working capital needs, but may also be used to temporarily fund long-term capital requirements. The components of ACE’s short-term debt at December 31, 2015 and 2014 are as follows:

	2015		2014
	(millions of dollars)
Commercial paper	$	5	$	127

Commercial Paper

ACE maintains an ongoing commercial paper program to address its short-term liquidity needs. As of December 31, 2015, the maximum capacity available under the program was $350 million, subject to available borrowing capacity under the credit facility.

ACE had $5 million and $127 million of commercial paper outstanding at December 31, 2015 and 2014, respectively. The weighted average interest rates for commercial paper issued by ACE during 2015 and 2014 were 0.46% and 0.27%, respectively. The weighted average maturity of all commercial paper issued by ACE during 2015 and 2014 was six days and five days, respectively.

Variable Rate Demand Bonds

During 2014, ACE retired, at maturity, its last remaining Variable Rate Demand Bonds (VRDBs) in the amount of $18 million. The weighted average interest rate for VRDBs was 0.05% during 2014.

Credit Facility

PHI, Pepco, DPL and ACE maintain an unsecured syndicated credit facility to provide for their respective liquidity needs, including obtaining letters of credit, borrowing for general corporate purposes and supporting their commercial paper programs. On August 1, 2013, as permitted under the existing terms of the credit agreement, a request by PHI, Pepco, DPL and ACE to extend the credit facility termination date to August 1, 2018 was approved. All of the terms and conditions as well as pricing remained the same.

The aggregate borrowing limit under the amended and restated credit facility is $1.5 billion, all or any portion of which may be used to obtain loans and up to $500 million of which may be used to obtain letters of credit. The facility also includes a swingline loan sub-facility, pursuant to which each company may make same day borrowings in an aggregate amount not to exceed 10% of the total amount of the facility. Any swingline loan must be repaid by the borrower within fourteen days of receipt. The credit sublimit is $750 million for PHI and $250 million for each of Pepco, DPL and ACE. The sublimits may be increased or decreased by the individual borrower during the term of the facility, except that (i) the sum of all of the borrower sublimits following any such increase or decrease must equal the total amount of the facility, and (ii) the aggregate amount of credit used at any given time by (a) PHI may not exceed $1.25 billion, and (b) each of Pepco, DPL or ACE may not exceed the lesser of $500 million or the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the sublimit reallocations may not exceed eight per year during the term of the facility.

The interest rate payable by each company on utilized funds is, at the borrowing company’s election, (i) the greater of the prevailing prime rate, the federal funds effective rate plus 0.5% and the one month London Interbank Offered Rate plus 1.0%, or (ii) the prevailing Eurodollar rate, plus a margin that varies according to the credit rating of the borrower.

In order for a borrower to use the facility, certain representations and warranties must be true and correct, and the borrower must be in compliance with specified financial and other covenants, including (i) the requirement that each borrowing company maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the credit agreement, which calculation excludes from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) with certain exceptions, a restriction on sales or other dispositions of assets, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than permitted liens. The credit agreement contains certain covenants and other customary agreements and requirements that, if not complied with, could result in an event of default and the acceleration of repayment obligations of one or more of the borrowers thereunder. Each of the borrowers was in compliance with all covenants under this facility at December 31, 2015.

The absence of a material adverse change in PHI’s business, property, results of operations or financial condition is not a condition to the availability of credit under the credit agreement. The credit agreement does not include any rating triggers.

As of December 31, 2015 and 2014, the amount of cash plus borrowing capacity under the credit facility available to meet the liquidity needs of PHI’s utility subsidiaries in the aggregate was $576 million and $413 million, respectively. ACE’s borrowing capacity under the credit facility at any given time depends on the amount of the subsidiary borrowing capacity being utilized by Pepco and DPL and the portion of the total capacity being used by PHI.

Credit Facility Amendment

During 2014, PHI, Pepco, DPL and ACE entered into an amendment of and consent with respect to the credit agreement (the Consent). PHI was required to obtain the consent of certain of the lenders under the credit facility in order to permit the consummation of the Merger. Pursuant to the Consent, certain of the lenders consented to the consummation of the Merger and the subsequent conversion of PHI from a Delaware corporation to a Delaware limited liability company, provided that the Merger and subsequent conversion are consummated on or before October 29, 2015. In addition, the Consent amends the definition of “Change in Control” in the credit agreement to mean, following consummation of the Merger, an event or series of events by which Exelon no longer owns, directly or indirectly, 100% of the outstanding shares of voting stock of Pepco Holdings. PHI requested and obtained an extension of the Consent to allow for completion of the Merger by June 30, 2016.

Term Loan Agreement

On May 10, 2013, ACE entered into a $100 million term loan agreement, pursuant to which ACE borrowed $100 million at a rate of interest equal to the prevailing Eurodollar rate, which was determined by reference to the London Interbank Offered Rate (LIBOR) with respect to the relevant interest period, all as defined in the loan agreement, plus a margin of 0.75%. On August 21, 2014, ACE repaid the term loan in full.

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Income Taxes

12 Months Ended

Dec. 31, 2015

Income Taxes

(11) INCOME TAXES

PHI and the majority of its subsidiaries file a consolidated federal income tax return. Federal income taxes are allocated among PHI and the subsidiaries included in its consolidated group pursuant to a written tax sharing agreement that was approved by the SEC in 2002 in connection with the establishment of PHI as a public utility holding company. Under this tax sharing agreement, PHI’s consolidated federal income tax liability is allocated based upon PHI’s and its subsidiaries’ separate taxable income or loss.

The provision for consolidated income taxes, reconciliation of consolidated income tax expense, and components of consolidated deferred tax liabilities (assets) are shown below.

Provision for Consolidated Income Taxes – Continuing Operations

	For the Year Ended December 31,
	2015			2014			2013
	(millions of dollars)
Current Tax (Benefit) Expense
Federal	$	(3	)	$	(137	)	$	(128	)
State and local		12			(26	)		(9	)
Total Current Tax Expense (Benefit)		9			(163	)		(137	)
Deferred Tax Expense (Benefit)
Federal		92			261			393
State and local		30			41			65
Investment tax credit amortization		(2	)		(1	)		(2	)
Total Deferred Tax Expense		120			301			456
Total Consolidated Income Tax Expense Related to Continuing Operations	$	129		$	138		$	319

Reconciliation of Consolidated Income Tax Expense – Continuing Operations

	For the Year Ended December 31,
	2015					2014					2013
	(millions of dollars)
Income tax at Federal statutory rate	$	156		35.0	%	$	133		35.0	%	$	150		35.0	%
Increases (decreases) resulting from:
State income taxes, net of federal effect		27		6.0	%		23		6.1	%		27		6.3	%
Asset removal costs		(14	)	(3.1	)%		(12	)	(3.2	)%		(14	)	(3.3	)%
Change in estimates and interest related to uncertain and effectively settled tax positions		(46	)	(10.3	)%		—		—			56		13.1	%
Deferred tax basis adjustments		7		1.6	%		—		—			—		—
Establishment of valuation allowances related to deferred tax assets		—		—			—		—			101		23.5	%
Merger related costs		4		0.9	%		7		1.8	%		—		—
Other, net		(5	)	(1.2	)%		(13	)	(3.4	)%		(1	)	(0.2	)%
Consolidated Income Tax Expense Related to Continuing Operations	$	129		28.9	%	$	138		36.3	%	$	319		74.4	%

Global Tax Settlement

On November 18, 2015, PHI entered into a settlement with the IRS and the DOJ (the Global Tax Settlement) to provide for the resolution of the tax treatment of its previously held cross-border energy lease investments involving public utility assets located outside of the United States structured as sale-in, lease-out, or SILO, transactions. The Global Tax Settlement followed the acceptance by PHI on October 29, 2015 of IRS revenue agent reports covering adjustments incorporated in the terms of the Global Tax Settlement, as well as adjustments for all other tax matters in dispute with the IRS. Also, on November 18, 2015, the DOJ accepted PHI’s offer letter for the settlement of litigation related to the SILO transactions discussed further in Note (16), “Commitments and Contingencies – PHI’s Cross-Border Energy Lease Investments.” The Global Tax Settlement and the revenue agent reports, together, effectively close all years open to examination of federal income tax liabilities for PHI through 2011, and all matters associated with the cross-border energy lease investments through 2013.

The Global Tax Settlement, which resolves tax matters related to the cross-border energy lease investments and avoids the costs associated with continued litigation, provides that all depreciation and interest deductions in excess of rental income related to the cross-border energy lease investments were disallowed. The Global Tax Settlement also required PHI to recognize original issue discount income for tax purposes associated with the recharacterization of each of the leases as a loan transaction. Pursuant to the Global Tax Settlement, interest will be assessed with respect to tax underpayments in the relevant years; however, no penalties were assessed against PHI. The Global Tax Settlement provides for the same treatment of the cross-border energy lease investments for the tax years 2012 and 2013 as described above. The last of PHI’s cross-border energy lease investments was terminated in 2013. As a result of the Global Tax Settlement, PHI and the DOJ filed stipulations of dismissal regarding the litigation in the U.S. Court of Federal Claims. The Court dismissed the complaint on November 20, 2015.

As a result of the Global Tax Settlement, PHI recorded in the fourth quarter of 2015 a tax benefit of $56 million, including $47 million associated with continuing operations and $9 million associated with discontinued operations. The $47 million benefit associated with continuing operations is included above in Change in estimates and interest related to uncertain and effectively settled tax positions. Included in the tax benefit of $47 million associated with continuing operations was a $21 million after-tax interest benefit representing the anticipated reduction in previously recorded interest expense that was allocated to PHI’s continuing operations associated with PHI’s uncertain tax positions. The remaining tax benefit recorded of $26 million primarily represents uncertain tax positions associated with PHI’s continuing operations that were settled in favor of PHI in the Global Tax Settlement.

Also during the fourth quarter of 2015, PHI completed its annual reconciliation of its deferred income tax accounts and corrected prior period errors by recording an after-tax charge of $7 million which is included above in Deferred tax basis adjustments. Management has determined that these errors, individually or in the aggregate, were not material to the current or prior periods.

Other Tax Matters

During 2015 and 2014, PHI recorded tax benefits of $6 million and $5 million, respectively, related to certain energy efficiency tax deductions associated with Pepco Energy Services’ energy savings performance contracting services. Theses tax benefits are included above in Other, net.

In connection with the proposed Merger (as further described in Note (1), “Organization”), PHI incurred certain merger-related costs in 2015 and 2014 which are not tax-deductible.

During 2013, PHI recorded a $56 million charge for a change in estimates and interest related to uncertain and effectively settled tax positions, primarily representing the anticipated additional interest expense on estimated federal and state income tax obligations that was allocated to PHI’s continuing operations resulting from a change in assessment of tax benefits associated with the former cross-border energy lease investments of PCI in the first quarter of 2013.

Also, in 2013, PHI established valuation allowances of $101 million related to deferred tax assets. Between 1990 and 1999, PCI, through various subsidiaries, entered into certain transactions involving investments in aircraft and aircraft equipment, railcars and other assets. In connection with these transactions, PCI recorded deferred tax assets in prior years of $101 million in the aggregate. Following events that took place during the first quarter of 2013, which included (i) court decisions in favor of the IRS with respect to other taxpayers’ cross-border lease and other structured transactions (as discussed in Note (20), “Discontinued Operations – Cross-Border Energy Lease Investments”), (ii) the change in PHI’s tax position with respect to the tax benefits associated with its cross-border energy leases, and (iii) PHI’s decision in March 2013 to begin to pursue the early termination of its remaining cross-border energy lease investments (which represented a substantial portion of the remaining assets within PCI) without the intent to reinvest these proceeds in income-producing assets, management evaluated the likelihood that PCI would be able to realize the $101 million of deferred tax assets in the future. Based on this evaluation, PCI established valuation allowances against these deferred tax assets totaling $101 million in the first quarter of 2013. Further, during the fourth quarter of 2013, in light of additional court decisions in favor of the IRS involving other taxpayers, and after consideration of all relevant factors, management determined that it would abandon the further pursuit of these deferred tax assets, and these assets totaling $101 million were charged off against the previously established valuation allowances.

Components of Consolidated Deferred Tax Liabilities (Assets)

	At December 31,
	2015			2014
	(millions of dollars)
Deferred Tax Liabilities (Assets)
Depreciation and other basis differences related to plant and equipment	$	3,273		$	2,962
Deferred electric service and electric restructuring liabilities		43			67
Federal and state net operating losses		(446	)		(400	)
Valuation allowances on state net operating losses		63			61
Pension and other postretirement benefits		92			116
Deferred taxes on amounts to be collected through future rates		86			94
Other		267			325
Total Deferred Tax Liabilities, net		3,378			3,225
Deferred tax assets included in Other Assets		15			17
Total Consolidated Deferred Tax Liabilities, net	$	3,393		$	3,242

The net deferred tax liability represents the tax effect, at presently enacted tax rates, of temporary differences between the financial statement basis and tax basis of assets and liabilities. The portion of the net deferred tax liability applicable to PHI’s utility operations, which has not been reflected in current service rates, represents income taxes recoverable through future rates, net, and is recorded as a Regulatory asset on the balance sheet. Federal and state net operating losses generally expire over 20 years from 2029 to 2034.

The Tax Reform Act of 1986 repealed the investment tax credit for property placed in service after December 31, 1985, except for certain transition property. Investment tax credits previously earned on Pepco’s, DPL’s and ACE’s property continue to be amortized to income over the useful lives of the related property.

Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits

	2015			2014			2013
	(millions of dollars)
Balance as of January 1,	$	850		$	831		$	200
Tax positions related to current year:
Additions		—			4			3
Reductions		—			(2	)		—
Tax positions related to prior years:
Additions		13			27			646	(b)
Reductions		(201	)(a)		(10	)		(12	)
Settlements		(628	)(a)		—			(6	)
Balance as of December 31,	$	34		$	850		$	831

(a) Reductions and settlements in 2015 resulted from the Global Tax Settlement. Settlements represent unrecognized tax benefits that were satisfied with cash or use of net operating losses and tax credits. The majority of the settlements were associated with the treatment of the former cross-border energy lease investments of PCI.

(b) These additions of unrecognized tax benefits in 2013 primarily relate to the former cross-border energy lease investments of PCI.

Unrecognized Benefits That, If Recognized, Would Affect the Effective Tax Rate

Unrecognized tax benefits are related to tax positions that have been taken or are expected to be taken in tax returns that are not recognized in the financial statements because management has either measured the tax benefit at an amount less than the benefit claimed or expected to be claimed, or has concluded that it is not more likely than not that the tax position will be ultimately sustained. For the majority of these tax positions, the ultimate deductibility is highly certain, but there is uncertainty about the timing of such deductibility. Unrecognized tax benefits at December 31, 2015 included $22 million that, if recognized, would lower the effective tax rate.

Interest and Penalties

PHI recognizes interest and penalties relating to its uncertain tax positions as an element of income tax expense. For the years ended December 31, 2015, 2014 and 2013, PHI recognized $35 million of pre-tax interest income ($21 million after-tax), less than $1 million of pre-tax interest expense, and $125 million of pre-tax interest expense ($75 million after-tax), respectively, as a component of income tax expense related to continuing and discontinued operations. As of December 31, 2015, 2014 and 2013, PHI had accrued interest payable of $2 million, accrued interest receivable of $2 million and accrued interest receivable of $2 million, respectively, related to effectively settled and uncertain tax positions.

Possible Changes to Unrecognized Tax Benefits

It is reasonably possible that the amount of unrecognized tax benefits with respect to PHI’s uncertain tax positions will significantly increase or decrease within the next 12 months. At this time, it is estimated that there will be a $6 million to $10 million decrease in unrecognized tax benefits within the next 12 months.

Tax Years Open to Examination

As a result of the Global Tax Settlement, PHI’s federal income tax liabilities for PHI and Pepco legacy companies for all years through 2011, and for all matters associated with the cross-border energy lease investments for all years through 2013, have been determined by the IRS, subject to adjustment to the extent of any net operating loss or other loss or credit carrybacks from subsequent years. The open tax years for the significant states where PHI files state income tax returns (District of Columbia, Maryland, Delaware, New Jersey, Pennsylvania and Virginia) are the same as for the Federal returns.

Changes to the District of Columbia Tax Law

On February 26, 2015, the District of Columbia Fiscal Year 2015 Budget Support Act of 2014 became law, effective January 1, 2015. The law revised the apportionment methodology for corporate tax and included a phase-down of the corporate tax rate from 9.975% to 8.25% by fiscal year 2019. The change in law required PHI and Pepco to remeasure their net deferred tax liabilities in the first and fourth quarters of 2015. This remeasurement resulted in Pepco reducing its deferred tax liabilities by $23 million in the first quarter of 2015 to reflect the initial reduction in the tax rate from 9.975% to 9.4% on January 1, 2015 and $2 million in the fourth quarter of 2015 to reflect the subsequent reduction in the tax rate from 9.4% to 9.2% on January 1, 2016. These reductions to the deferred tax liabilities were offset by corresponding decreases to Pepco’s regulatory assets. Further reductions to the corporate tax rate in future years will depend upon the achievement of future revenue projections for the District of Columbia.

Final IRS Regulations on Repair of Tangible Property

In August 2011, the IRS issued Revenue Procedure 2011-43 providing a safe harbor method of tax accounting for repair costs associated with electric transmission and distribution property. In September 2012, with the filing of its 2011 tax return, PHI adopted the safe harbor for the 2011 tax year. In September 2013, the IRS published final regulations regarding the tax treatment of costs incurred to acquire, produce or improve tangible property. In February 2014, the IRS issued revenue procedures that describe how taxpayers should implement the final regulations. The final repair regulations and the related revenue procedures did not modify the guidance set forth in Revenue Procedure 2011-43 that the Unit of Property for electric transmission and distribution network assets is determined by the taxpayer’s particular facts and circumstances. The final regulations did not have a material impact on PHI’s consolidated financial statements.

Other Taxes

Other taxes for continuing operations are shown below. The annual amounts include $421 million, $407 million and $422 million for the years ended December 31, 2015, 2014 and 2013, respectively, related to Power Delivery, which are recoverable through rates.

	2015		2014		2013
	(millions of dollars)
Gross Receipts/Delivery	$	124	$	123	$	133
Property		92		84		77
County Fuel and Energy		143		143		153
Environmental, Use and Other		68		63		65
Total	$	427	$	413	$	428

Potomac Electric Power Co [Member]

Income Taxes

(10) INCOME TAXES

Pepco, as a direct subsidiary of PHI, is included in the consolidated federal income tax return of PHI. Federal income taxes are allocated to Pepco pursuant to a written tax sharing agreement that was approved by the Securities and Exchange Commission in connection with the establishment of PHI as a holding company. Under this tax sharing agreement, PHI’s consolidated federal income tax liability is allocated based upon PHI’s and its subsidiaries’ separate taxable income or loss.

The provision for income taxes, reconciliation of income tax expense, and components of deferred income tax liabilities (assets) are shown below.

Provision for Income Taxes

	For the Year Ended December 31,
	2015			2014			2013
	(millions of dollars)
Current Tax Benefit
Federal	$	(57	)	$	(79	)	$	(39	)
State and local		6			(3	)		(1	)
Total Current Tax Benefit		(51	)		(82	)		(40	)
Deferred Tax Expense (Benefit)
Federal		125			150			96
State and local		24			24			24
Investment tax credit amortization		—			—			(1	)
Total Deferred Tax Expense		149			174			119
Total Income Tax Expense	$	98		$	92		$	79

Reconciliation of Income Tax Expense

	For the Year Ended December 31,
	2015					2014					2013
	(millions of dollars)
Income tax at Federal statutory rate	$	100		35.0	%	$	92		35.0	%	$	80		35.0	%
Increases (decreases) resulting from:
State income taxes, net of federal effect		15		5.3	%		15		5.7	%		13		5.7	%
Asset removal costs		(14	)	(4.9	)%		(12	)	(4.6	)%		(14	)	(6.1	)%
Change in estimates and interest related to uncertain and effectively settled tax positions		(6	)	(2.1	)%		(1	)	(0.4	)%		(3	)	(1.3	)%
Deferred tax basis adjustments		6		2.1	%		—		—			—		—
Other, net		(3	)	(1.0	)%		(2	)	(0.7	)%		3		1.2	%
Income Tax Expense	$	98		34.4	%	$	92		35.0	%	$	79		34.5	%

Global Tax Settlement

On November 18, 2015, PHI entered into a settlement with the Internal Revenue Service (IRS) and the Department of Justice (DOJ) (the Global Tax Settlement) to provide for the resolution of the tax treatment of its previously held cross-border energy lease investments involving public utility assets located outside of the United States structured as sale-in, lease-out, or SILO, transactions. The Global Tax Settlement followed the acceptance by PHI on October 29, 2015 of IRS revenue agent reports covering adjustments incorporated in the terms of the Global Tax Settlement, as well as adjustments for all other tax matters in dispute with the IRS. The Global Tax Settlement and the revenue agent reports, together, effectively close all years open to examination of federal income tax liabilities for PHI and Pepco through 2011, and all matters associated with the cross-border energy lease investments through 2013.

As a result of the Global Tax Settlement, Pepco recorded in the fourth quarter of 2015 a tax benefit of $9 million, which is included above in Change in estimates and interest related to uncertain and effectively settled tax positions. Included in the tax benefit of $9 million was a $3 million after-tax interest benefit associated with Pepco’s uncertain tax positions. The interest benefit represented Pepco’s allocated share of an overall net interest benefit for PHI’s consolidated group of $21 million resulting from the Global Tax Settlement assuming Pepco was a separate taxpayer. The remaining tax benefit recorded of $6 million primarily represents uncertain tax positions associated with Pepco’s operations that were settled in favor of Pepco in the Global Tax Settlement. Also in the fourth quarter of 2015, Pepco recorded a charge of $3 million for an uncertain tax position not related to the Global Tax Settlement, which was also included above in Change in estimates and interest related to uncertain and effectively settled tax positions.

Also during the fourth quarter of 2015, Pepco completed its annual reconciliation of its deferred income tax accounts and corrected prior period errors by recording an after-tax charge of $6 million which is included above in Deferred tax basis adjustments. Management has determined that these errors, individually or in the aggregate were not material to the current or prior periods.

Other Tax Matter

On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States (to which Pepco is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. As a result of the court’s ruling in this case, PHI determined in the first quarter of 2013 that it could no longer support its current assessment with respect to the likely outcome of tax positions associated with its cross-border energy lease investments held by its wholly owned subsidiary Potomac Capital Investment Corporation, and PHI recorded an after-tax charge of $377 million in the first quarter of 2013. Included in the $377 million charge was an after-tax interest charge of $54 million and this amount was allocated to each member of PHI’s consolidated group as if each member was a separate taxpayer, resulting in Pepco recording a $5 million (after-tax) interest benefit in the first quarter of 2013, which is included above in Change in estimates and interest related to uncertain and effectively settled tax positions.

Components of Deferred Income Tax Liabilities (Assets)

	At December 31,
	2015			2014
	(millions of dollars)
Deferred Tax Liabilities (Assets)
Depreciation and other basis differences related to plant and equipment	$	1,541		$	1,423
Pension and other postretirement benefits		95			103
Deferred taxes on amounts to be collected through future rates		55			59
Federal and state net operating losses		(141	)		(186	)
Other		171			180
Total Deferred Tax Liabilities, net	$	1,721		$	1,579

The net deferred tax liability represents the tax effect, at presently enacted tax rates, of temporary differences between the financial statement basis and tax basis of assets and liabilities. The portion of the net deferred tax liability applicable to Pepco’s operations, which has not been reflected in current service rates, represents income taxes recoverable through future rates, net, and is recorded as a regulatory asset on the balance sheet. No valuation allowance for deferred tax assets was required or recorded at December 31, 2015 and 2014. Federal and state net operating losses generally expire over 20 years from 2029 to 2034.

The Tax Reform Act of 1986 repealed the investment tax credit for property placed in service after December 31, 1985, except for certain transition property. Investment tax credits previously earned on Pepco’s property continue to be amortized to income over the useful lives of the related property.

Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits

	2015			2014			2013
	(millions of dollars)
Balance as of January 1	$	97		$	101		$	91
Tax positions related to current year:
Additions		—			1			1
Reductions		—			(2	)		—
Tax positions related to prior years:
Additions		10			1			12
Reductions		(55	)(a)		(4	)		(3	)
Settlements		(40	)(a)		—			—
Balance as of December 31	$	12		$	97		$	101

(a) Reductions and settlements in 2015 resulted from the Global Tax Settlement. Settlements represent unrecognized tax benefits that were satisfied with cash or use of net operating losses and tax credits.

Unrecognized Benefits That, If Recognized, Would Affect the Effective Tax Rate

Unrecognized tax benefits are related to tax positions that have been taken or are expected to be taken in tax returns that are not recognized in the financial statements because management has either measured the tax benefit at an amount less than the benefit claimed, or expected to be claimed, or has concluded that it is not more likely than not that the tax position will be ultimately sustained. For the majority of these tax positions, the ultimate deductibility is highly certain, but there is uncertainty about the timing of such deductibility. At December 31, 2015, Pepco had $8 million of unrecognized tax benefits that, if recognized, would lower the effective tax rate.

Interest and Penalties

Pepco recognizes interest and penalties relating to its uncertain tax positions as an element of income tax expense. For the years ended December 31, 2015, 2014 and 2013, Pepco recognized $5 million of pre-tax interest income ($3 million after-tax), $2 million of pre-tax interest income ($1 million after-tax), and $5 million of pre-tax interest income ($3 million after-tax), respectively, as a component of income tax expense. As of December 31, 2015, 2014 and 2013, Pepco had accrued interest receivable of zero, $9 million and $9 million, respectively, related to effectively settled and uncertain tax positions.

Possible Changes to Unrecognized Tax Benefits

It is reasonably possible that the amount of the unrecognized tax benefit with respect to some of Pepco’s uncertain tax positions will significantly increase or decrease within the next 12 months. At this time, it is estimated that there will be a $3 million to $5 million decrease in unrecognized tax benefits within the next 12 months.

Tax Years Open to Examination

Pepco, as a direct subsidiary of PHI, is included on PHI’s consolidated Federal income tax return. As a result of the Global Tax Settlement described above, Pepco’s federal income tax liabilities for all years through 2011 have been determined, subject to adjustment to the extent of any net operating loss or other loss or credit carrybacks from subsequent years. The open tax years for the significant states where Pepco files state income tax returns (District of Columbia and Maryland) are the same as for the Federal returns. As a result of the final determination of these years, Pepco has filed or intends to file amended state returns requesting refunds which are subject to review by the various states.

Changes to the District of Columbia Tax Law

On February 26, 2015, the District of Columbia Fiscal Year 2015 Budget Support Act of 2014 became law, effective January 1, 2015. The law revised the apportionment methodology for corporate tax and included a phase-down of the corporate tax rate from 9.975% to 8.25% by fiscal year 2019. The change in law required PHI and Pepco to remeasure their net deferred tax liabilities in the first and fourth quarters of 2015. This remeasurement resulted in Pepco reducing its deferred tax liabilities by $23 million in the first quarter of 2015 to reflect the initial reduction in the tax rate from 9.975% to 9.4% on January 1, 2015 and $2 million in the fourth quarter of 2015 to reflect the subsequent reduction in the tax rate from 9.4% to 9.2% on January 1, 2016. These reductions to the deferred tax liabilities were offset by corresponding decreases to Pepco’s regulatory assets. Further reductions to the corporate tax rate in future years will depend upon the achievement of future revenue projections for the District of Columbia.

Final IRS Regulations on Repair of Tangible Property

In August 2011, the IRS issued Revenue Procedure 2011-43 providing a safe harbor method of tax accounting for repair costs associated with electric transmission and distribution property. In September 2012, with the filing of its 2011 tax return, PHI adopted the safe harbor for the 2011 tax year. In September 2013, the IRS published final regulations regarding the tax treatment of costs incurred to acquire, produce or improve tangible property. In February 2014, the IRS issued revenue procedures that describe how taxpayers should implement the final regulations. The final repair regulations and the related revenue procedures did not modify the guidance set forth in Revenue Procedure 2011-43 that the Unit of Property for electric transmission and distribution network assets is determined by the taxpayer’s particular facts and circumstances. The final regulations did not have a material impact on Pepco’s financial statements.

Other Taxes

Taxes other than income taxes for each year are shown below. These amounts are recoverable through rates.

	2015		2014		2013
	(millions of dollars)
Gross Receipts/Delivery	$	107	$	107	$	108
Property		55		51		45
County Fuel and Energy		143		143		153
Environmental, Use and Other		64		62		62
Total	$	369	$	363	$	368

Delmarva Power & Light Co/De [Member]

Income Taxes

(11) INCOME TAXES

DPL, as an indirect subsidiary of PHI, is included in the consolidated federal income tax return of PHI. Federal income taxes are allocated to DPL pursuant to a written tax sharing agreement that was approved by the Securities and Exchange Commission in connection with the establishment of PHI as a holding company. Under this tax sharing agreement, PHI’s consolidated federal income tax liability is allocated based upon PHI’s and its subsidiaries’ separate taxable income or loss.

The provision for income taxes, reconciliation of income tax expense, and components of deferred income tax liabilities (assets) are shown below.

Provision for Income Taxes

	For the Year Ended December 31,
	2015			2014			2013
	(millions of dollars)
Current Tax (Benefit) Expense
Federal	$	(26	)	$	(45	)	$	(8	)
State and local		2			—			—
Total Current Tax Benefit		(24	)		(45	)		(8	)
Deferred Tax Expense (Benefit)
Federal		73			99			53
State and local		1			12			12
Investment tax credit amortization		(1	)		(1	)		(1	)
Total Deferred Tax Expense		73			110			64
Total Income Tax Expense	$	49		$	65		$	56

Reconciliation of Income Tax Expense

	For the Year Ended December 31,
	2015					2014					2013
	(millions of dollars)
Income tax at Federal statutory rate	$	44		35.0	%	$	59		35.0	%	$	51		35.0	%
Increases (decreases) resulting from:
State income taxes, net of federal effect		7		5.6	%		9		5.3	%		8		5.5	%
Change in estimates and interest related to uncertain and effectively settled tax positions		3		2.4	%		—		—			(1	)	(0.7	)%
Other, net		(5	)	(3.8	)%		(3	)	(1.8	)%		(2	)	(1.2	)%
Income Tax Expense	$	49		39.2	%	$	65		38.5	%	$	56		38.6	%

Global Tax Settlement

On November 18, 2015, PHI entered into a settlement with the Internal Revenue Service (IRS) and the Department of Justice (DOJ) (the Global Tax Settlement) to provide for the resolution of the tax treatment of its previously held cross-border energy lease investments involving public utility assets located outside of the United States structured as sale-in, lease-out, or SILO, transactions. The Global Tax Settlement followed the acceptance by PHI on October 29, 2015 of IRS revenue agent reports covering adjustments incorporated in the terms of the Global Tax Settlement, as well as adjustments for all other tax matters in dispute with the IRS. The Global Tax Settlement and the revenue agent reports, together, effectively close all years open to examination of federal income tax liabilities for PHI and DPL through 2011, and all matters associated with the cross-border energy lease investments through 2013.

As a result of the Global Tax Settlement, DPL recorded in the fourth quarter of 2015 tax expense of $3 million which is included above in Change in estimates and interest related to uncertain and effectively settled tax positions. The tax charge recorded of $3 million primarily represents uncertain tax positions that were settled in favor of the IRS in the Global Tax Settlement. Included in the tax expense of $3 million was an after-tax interest benefit of less than $1 million associated with DPL’s uncertain tax positions. The interest benefit represented DPL’s allocated share of an overall net interest benefit for PHI’s consolidated group of $21 million resulting from the Global Tax Settlement assuming DPL was a separate taxpayer.

Other Tax Matter

On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States (to which DPL is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. As a result of the court’s ruling in this case, PHI determined in the first quarter of 2013 that it could no longer support its current assessment with respect to the likely outcome of tax positions associated with its cross-border energy lease investments held by its wholly owned subsidiary Potomac Capital Investment Corporation, and PHI recorded an after-tax charge of $377 million in the first quarter of 2013. Included in the $377 million charge was an after-tax interest charge of $54 million and this amount was allocated to each member of PHI’s consolidated group as if each member was a separate taxpayer, resulting in DPL recording a $1 million (after-tax) interest benefit in the first quarter of 2013, which is included above in Change in estimates and interest related to uncertain and effectively settled tax positions.

Components of Deferred Income Tax Liabilities (Assets)

	As of December 31,
	2015			2014
	(millions of dollars)
Deferred Tax Liabilities (Assets)
Depreciation and other basis differences related to plant and equipment	$	899		$	797
Deferred taxes on amounts to be collected through future rates		15			19
Federal and state net operating losses		(122	)		(115	)
Pension and other postretirement benefits		75			80
Electric restructuring liabilities		(4	)		(4	)
Other		78			101
Total Deferred Tax Liabilities, net	$	941		$	878

The net deferred tax liability represents the tax effect, at presently enacted tax rates, of temporary differences between the financial statement basis and tax basis of assets and liabilities. The portion of the net deferred tax liability applicable to DPL’s operations, which has not been reflected in current service rates, represents income taxes recoverable through future rates, net, and is recorded as a regulatory asset on the balance sheet. No valuation allowance for deferred tax assets was required or recorded at December 31, 2015 and 2014. Federal and state net operating losses generally expire over 20 years from 2029 to 2034.

The Tax Reform Act of 1986 repealed the investment tax credit for property placed in service after December 31, 1985, except for certain transition property. Investment tax credits previously earned on DPL’s property continue to be amortized to income over the useful lives of the related property.

Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits

	2015			2014			2013
	(millions of dollars)
Balance as of January 1	$	22		$	9		$	9
Tax positions related to current year:
Additions		—			1			—
Reductions		—			—			—
Tax positions related to prior years:
Additions		3			13			—
Reductions		(13	)(a)		(1	)		—
Settlements		(9	)(a)		—			—
Balance as of December 31	$	3		$	22		$	9

(a) Reductions and settlements in 2015 resulted from the Global Tax Settlement. Settlements represent unrecognized tax benefits that were satisfied with cash or use of net operating losses and tax credits.

Unrecognized Benefits That, If Recognized, Would Affect the Effective Tax Rate

Unrecognized tax benefits are related to tax positions that have been taken or are expected to be taken in tax returns that are not recognized in the financial statements because management has either measured the tax benefit at an amount less than the benefit claimed, or expected to be claimed, or has concluded that it is not more likely than not that the tax position will be ultimately sustained. For the majority of these tax positions, the ultimate deductibility is highly certain, but there is uncertainty about the timing of such deductibility. At December 31, 2015, DPL had $3 million of unrecognized tax benefits that, if recognized, would lower the effective tax rate.

Interest and Penalties

DPL recognizes interest and penalties relating to its uncertain tax positions as an element of income tax expense. For each of the years ended December 31, 2015, 2014 and 2013, DPL recognized less than $1 million of pre-tax interest income as a component of income tax expense. As of December 31, 2015, 2014 and 2013, DPL had accrued interest receivable of zero, $2 million and $2 million, respectively, related to effectively settled and uncertain tax positions.

Possible Changes to Unrecognized Tax Benefits

It is reasonably possible that the amount of the unrecognized tax benefit with respect to some of DPL’s uncertain tax positions will significantly increase or decrease within the next 12 months. At this time, it is estimated that there will be no decrease in unrecognized tax benefits within the next 12 months.

Tax Years Open to Examination

DPL, as an indirect subsidiary of PHI, is included on PHI’s consolidated Federal tax return. As a result of the Global Tax Settlement described above, DPL’s federal income tax liabilities for all years through 2011 have been determined, subject to adjustment to the extent of any net operating loss or other loss or credit carrybacks from subsequent years. The open tax years for the significant states where DPL files state income tax returns (Maryland and Delaware) are the same as for the Federal returns.

Final IRS Regulations on Repair of Tangible Property

In August 2011, the IRS issued Revenue Procedure 2011-43 providing a safe harbor method of tax accounting for repair costs associated with electric transmission and distribution property. In September 2012, with the filing of its 2011 tax return, PHI adopted the safe harbor for the 2011 tax year. In September 2013, the IRS published final regulations regarding the tax treatment of costs incurred to acquire, produce or improve tangible property. In February 2014, the IRS issued revenue procedures that describe how taxpayers should implement the final regulations. The final repair regulations and the related revenue procedures did not modify the guidance set forth in Revenue Procedure 2011-43 that the Unit of Property for electric transmission and distribution network assets is determined by the taxpayer’s particular facts and circumstances. The final regulations did not have a material impact on DPL’s financial statements.

Other Taxes

Taxes other than income taxes for each year are shown below. These amounts are recoverable through rates.

	2015		2014		2013
	(millions of dollars)
Gross Receipts/Delivery	$	17	$	16	$	15
Property		28		24		24
Environmental, Use and Other		2		2		1
Total	$	47	$	42	$	40

Atlantic City Electric Co [Member]

Income Taxes

(10) INCOME TAXES

ACE, as an indirect subsidiary of PHI, is included in the consolidated federal income tax return of PHI. Federal income taxes are allocated to ACE pursuant to a written tax sharing agreement that was approved by the Securities and Exchange Commission in connection with the establishment of PHI as a holding company. Under this tax sharing agreement, PHI’s consolidated federal income tax liability is allocated based upon PHI’s and its subsidiaries’ separate taxable income or loss.

The provision for consolidated income taxes, reconciliation of consolidated income tax expense, and components of consolidated deferred income tax liabilities (assets) are shown below.

Provision for Consolidated Income Taxes

	For the Year Ended December 31,
	2015			2014			2013
	(millions of dollars)
Current Tax (Benefit) Expense
Federal	$	(2	)	$	(7	)	$	(23	)
State and local		3			(2	)		(10	)
Total Current Tax Benefit		1			(9	)		(33	)
Deferred Tax Expense (Benefit)
Federal		25			30			28
State and local		5			7			25
Investment tax credit amortization		—			—			(1	)
Total Deferred Tax Expense		30			37			52
Total Consolidated Income Tax Expense	$	31		$	28		$	19

Reconciliation of Consolidated Income Tax Expense

	For the Year Ended December 31,
	2015					2014					2013
	(millions of dollars)
Income tax at Federal statutory rate	$	24		35.0	%	$	26		35.0	%	$	24		35.0	%
Increases (decreases) resulting from:
State income taxes, net of federal effect		4		5.8	%		4		5.5	%		5		7.2	%
Change in estimates and interest related to uncertain and effectively settled tax positions		3		4.3	%		(1	)	(1.4	)%		(9	)	(13.0	)%
Deferred tax basis adjustments		2		2.9	%		—		—			(2	)	(2.9	)%
Investment tax credit amortization		—		—			—		—			(1	)	(1.4	)%
Other, net		(2	)	(3.1	)%		(1	)	(0.7	)%		2		2.6	%
Consolidated Income Tax Expense	$	31		44.9	%	$	28		38.4	%	$	19		27.5	%

Global Tax Settlement

On November 18, 2015, PHI entered into a settlement with the IRS and the Department of Justice (DOJ) (the Global Tax Settlement) to provide for the resolution of the tax treatment of its previously held cross-border energy lease investments involving public utility assets located outside of the United States structured as sale-in, lease-out, or SILO, transactions. The Global Tax Settlement followed the acceptance by PHI on October 29, 2015 of IRS revenue agent reports covering adjustments incorporated in the terms of the Global Tax Settlement, as well as adjustments for all other tax matters in dispute with the IRS. The Global Tax Settlement and the revenue agent reports, together, effectively close all years open to examination of federal income tax liabilities for PHI and ACE through 2011, and all matters associated with the cross-border energy lease investments through 2013.

As a result of the Global Tax Settlement, ACE recorded in the fourth quarter of 2015 tax expense of $3 million which is included above in Change in estimates and interest related to uncertain and effectively settled tax positions. The tax charge recorded of $3 million primarily represents uncertain tax positions that were settled in favor of the IRS in the Global Tax Settlement. Included in the tax expense of $3 million was after-tax interest expense of less than $1 million associated with ACE’s uncertain tax positions. The interest expense represented ACE’s allocated share of an overall net interest benefit for PHI’s consolidated group of $21 million resulting from the Global Tax Settlement assuming ACE was a separate taxpayer.

Also during the fourth quarter of 2015, ACE completed its annual reconciliation of its deferred income tax accounts and corrected prior period errors by recording an after-tax charge of $2 million which is included above in Deferred tax basis adjustments. Management has determined that these errors, individually or in the aggregate, were not material to the current or prior periods.

Other Tax Matter

On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States (to which ACE is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. As a result of the court’s ruling in this case, PHI determined in the first quarter of 2013 that it could no longer support its current assessment with respect to the likely outcome of tax positions associated with its cross-border energy lease investments held by its wholly owned subsidiary Potomac Capital Investment Corporation, and PHI recorded an after-tax charge of $377 million in the first quarter of 2013. Included in the $377 million charge was an after-tax interest charge of $54 million and this amount was allocated to each member of PHI’s consolidated group as if each member was a separate taxpayer, resulting in ACE recording a $6 million (after-tax) interest benefit in the first quarter of 2013, which is included above in Change in estimates and interest related to uncertain and effectively settled tax positions.

Components of Consolidated Deferred Income Tax Liabilities (Assets)

	As of December 31,
	2015			2014
	(millions of dollars)
Deferred Tax Liabilities (Assets)
Depreciation and other basis differences related to plant and equipment	$	773		$	691
Deferred taxes on amounts to be collected through future rates		17			16
Payment for termination of purchased power contracts with NUGs		34			38
Deferred electric service and electric restructuring liabilities		47			71
Pension and other postretirement benefits		20			25
Federal and state net operating losses		(9	)		(26	)
Other		6			40
Total Consolidated Deferred Tax Liabilities, net	$	888		$	855

The net deferred tax liability represents the tax effect, at presently enacted tax rates, of temporary differences between the financial statement basis and tax basis of assets and liabilities. The portion of the net deferred tax liability applicable to ACE’s operations, which has not been reflected in current service rates, represents income taxes recoverable through future rates, net, and is recorded as a regulatory asset on the balance sheet. No valuation allowance for deferred tax assets was required or recorded at December 31, 2015 and 2014. Federal and State net operating losses generally expire over 20 years from 2029 to 2032.

The Tax Reform Act of 1986 repealed the investment tax credit for property placed in service after December 31, 1985, except for certain transition property. Investment tax credits previously earned on ACE’s property continue to be amortized to income over the useful lives of the related property.

Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits

	2015			2014			2013
	(millions of dollars)
Balance as of January 1	$	13		$	9		$	17
Tax positions related to current year:
Additions		—			1			2
Reductions		—			—			—
Tax positions related to prior years:
Additions		—			5			1
Reductions		(10	)(a)		(2	)		(5	)
Settlements		(3	)(a)		—			(6	)
Balance as of December 31	$	—		$	13		$	9

(a) Reductions and settlements in 2015 resulted from the Global Tax Settlement. Settlements represent unrecognized tax benefits that were satisfied with cash or use of net operating losses and tax credits.

Unrecognized Benefits That, If Recognized, Would Affect the Effective Tax Rate

Unrecognized tax benefits are related to tax positions that have been taken or are expected to be taken in tax returns that are not recognized in the financial statements because management has either measured the tax benefit at an amount less than the benefit claimed, or expected to be claimed, or has concluded that it is not more likely than not that the tax position will be ultimately sustained. For the majority of these tax positions, the ultimate deductibility is highly certain, but there is uncertainty about the timing of such deductibility. At December 31, 2015, ACE had no unrecognized tax benefits that, if recognized, would lower the effective tax rate.

Interest and Penalties

ACE recognizes interest and penalties relating to its uncertain tax positions as an element of income tax expense. For the years ended December 31, 2015, 2014 and 2013, ACE recognized less than $1 million of pre-tax interest income (less than $1 million after-tax), $1 million of pre-tax interest income (less than $1 million after-tax), and $12 million of pre-tax interest income ($7 million after-tax), respectively, as a component of income tax expense. As of December 31, 2015, 2014 and 2013, ACE had accrued interest receivable of zero, $14 million and $14 million, respectively, related to effectively settled and uncertain tax positions.

Possible Changes to Unrecognized Tax Benefits

It is reasonably possible that the amount of the unrecognized tax benefit with respect to some of ACE’s uncertain tax positions will significantly increase or decrease within the next 12 months. At this time, it is estimated that there will no decrease in unrecognized tax benefits within the next 12 months.

Tax Years Open to Examination

ACE, as an indirect subsidiary of PHI, is included on PHI’s consolidated Federal tax return. As a result of the Global Tax Settlement described above, ACE’s federal income tax liabilities for all years through 2011 have been determined, subject to adjustment to the extent of any net operating loss or other loss or credit carrybacks from subsequent years. The open tax years for the significant states where ACE files state income tax returns (New Jersey and Pennsylvania) are the same as for the Federal returns.

Final IRS Regulations on Repair of Tangible Property

In August 2011, the IRS issued Revenue Procedure 2011-43 providing a safe harbor method of tax accounting for repair costs associated with electric transmission and distribution property. In September 2012, with the filing of its 2011 tax return, PHI adopted the safe harbor for the 2011 tax year. In September 2013, the IRS published final regulations regarding the tax treatment of costs incurred to acquire, produce or improve tangible property. In February 2014, the IRS issued revenue procedures that describe how taxpayers should implement the final regulations. The final repair regulations and the related revenue procedures did not modify the guidance set forth in Revenue Procedure 2011-43 that the Unit of Property for electric transmission and distribution network assets is determined by the taxpayer’s particular facts and circumstances. The final regulations did not have a material impact on ACE’s consolidated financial statements.

Other Taxes

Taxes other than income taxes for each year are shown below. These amounts are recoverable through rates.

	2015		2014			2013
	(millions of dollars)
Gross Receipts/Delivery	$	—	$	—		$	10
Property		4		3			3
Environmental, Use and Other		1		(1	)		1
Total	$	5	$	2		$	14

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Stock-Based Compensation, Dividend Restrictions, and Calculations of Earnings Per Share of Common Stock

12 Months Ended

Dec. 31, 2015

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Stock-Based Compensation, Dividend Restrictions, and Calculations of Earnings Per Share of Common Stock

(12) STOCK-BASED COMPENSATION, DIVIDEND RESTRICTIONS, AND CALCULATIONS OF EARNINGS PER SHARE OF COMMON STOCK

Stock-Based Compensation

Pepco Holdings maintains the 2012 Long-Term Incentive Plan (2012 LTIP), the successor plan to the Long-Term Incentive Plan (LTIP), the objective of which is to increase shareholder value by providing long-term and equity incentives to reward officers, key employees and non-employee directors of Pepco Holdings and its subsidiaries and to increase the ownership of Pepco Holdings common stock by such individuals. Any officer, key employee or non-employee director of Pepco Holdings or its subsidiaries may be designated as a participant. Under these plans, awards to officers, key employees and non-employee directors may be in the form of restricted stock, restricted stock units, stock options, performance shares and/or units, stock appreciation rights, unrestricted stock and dividend equivalents. At inception, 10 million and 8 million shares of common stock were authorized for issuance under the LTIP and the 2012 LTIP, respectively. The LTIP expired in accordance with its terms in 2012 and no new awards may be granted thereunder.

Total stock-based compensation expense recorded in the consolidated statements of income (loss) for the years ended December 31, 2015, 2014 and 2013 was $13 million, $18 million and $12 million, respectively, all of which was associated with restricted stock and restricted stock unit awards.

No material amount of stock compensation expense was capitalized for the years ended December 31, 2015, 2014 and 2013.

Restricted Stock and Restricted Stock Unit Awards

Description of Awards

A number of programs have been established under the LTIP and the 2012 LTIP involving the issuance of restricted stock and restricted stock unit awards, including awards of performance-based restricted stock and restricted stock units, and time-based restricted stock and restricted stock units. A summary of each of these programs is as follows:

• Under the performance-based program, performance criteria are selected and measured over the specified performance period. Depending on the extent to which the performance criteria are satisfied, the participants are eligible to earn shares of common stock at the end of the performance period, ranging from 25% to 200% of the target award, and dividend equivalents accrued thereon.

• Generally, time-based restricted stock and restricted stock unit award opportunities have a requisite service period of up to three years and, with respect to restricted stock awards, participants have the right to receive dividends on the shares during the vesting period. Under restricted stock unit awards, dividends are credited quarterly in the form of additional restricted stock units, which are paid when vested at the end of the service period.

• PHI granted a total of 22,901 and 21,138 time-based restricted stock units in 2015 and 2014, respectively, to its non-employee directors under the 2012 LTIP. These time-based restricted stock units vest over a service period which ends upon the first to occur of (i) one year after the date of grant or (ii) the date of the next annual meeting of stockholders. These awards represent the equity portion of the annual retainer paid to non-employee directors for their service as a director of PHI.

Activity for the year

The 2015 activity for restricted stock, performance-based restricted stock, time-based restricted stock unit and performance-based restricted stock unit awards is summarized in the table below. For performance-based restricted stock and restricted stock unit awards, the table reflects awards projected, for purposes of computing the weighted average grant date fair value, to achieve 100% of targeted performance criteria for each outstanding award cycle.

	Number of Shares			Weighted Average Grant Date Fair Value
Balance as of January 1, 2015
Restricted stock		54,165		$	26.80
Performance-based restricted stock		70,276			27.01
Time-based restricted stock units		468,958			19.61
Performance-based restricted stock units		827,981			17.73
Total		1,421,380
Granted during 2015
Performance-based restricted stock		48,347			26.10
Time-based restricted stock units		450,203			27.40
Performance-based restricted stock units		6,188			26.08
Total		504,738
Vested during 2015
Performance-based restricted stock		(93,906	)		26.78
Time-based restricted stock units		(288,429	)		20.61
Performance-based restricted stock units		(424,705	)		17.05
Total		(807,040	)
Forfeited during 2015
Time-based restricted stock units		(2,218	)		27.00
Performance-based restricted stock units		(826	)		19.33
Total		(3,044	)
Balance as of December 31, 2015 (a)
Restricted stock		54,165			26.80
Performance-based restricted stock		24,717			26.10
Time-based restricted stock units		628,514			24.71
Performance-based restricted stock units		408,638			18.56
Total		1,116,034

(a) The balance as of December 31, 2015 does not include 36,110 shares of restricted stock, 113,385 time-based restricted stock units and 104,628 performance-based restricted stock units that were vested for executives and 30,784 time-based restricted stock units that were vested for directors but had not yet settled.

Grants included in the table above reflect 2015 grants of restricted stock, performance-based restricted stock, time-based restricted stock unit and performance-based restricted stock unit awards. PHI recognizes compensation expense related to restricted stock, performance-based restricted stock, time-based restricted stock unit and performance-based restricted stock unit awards based on the fair value of the awards at date of grant. The fair value is based on the market value of PHI common stock at the date the award opportunity is granted. The estimated fair value of the performance-based awards is also a function of PHI’s projected future performance relative to established performance criteria and the resulting payout of shares based on the achieved performance levels. PHI employed a Monte Carlo simulation to forecast PHI’s performance relative to the performance criteria and to estimate the potential payout of shares under the performance-based awards.

The following table provides the weighted average grant date fair value per share of those awards granted during each of the years ended December 31, 2015, 2014 and 2013:

	2015		2014		2013
Weighted average grant-date fair value of each restricted stock award granted during the year	$	—	$	26.80	$	—
Weighted average grant-date fair value of each performance-based restricted stock award granted during the year	$	26.10	$	27.01	$	—
Weighted average grant-date fair value of each time-based restricted stock unit award granted during the year	$	27.40	$	19.77	$	19.70
Weighted average grant-date fair value of each performance-based restricted stock unit award granted during the year	$	26.08	$	18.53	$	17.03

As of December 31, 2015, there was approximately $12 million of future compensation cost (net of estimated forfeitures) related to restricted stock unit awards granted under the LTIP and the 2012 LTIP that PHI expects to recognize over a weighted-average period of approximately two years.

Stock Options

Stock options to purchase shares of PHI’s common stock granted under the LTIP and the 2012 LTIP must have an exercise price at least equal to the fair market value of the underlying stock on the grant date. Stock options generally become exercisable on a specified vesting date or dates. All stock options must have an expiration date of no greater than ten years from the date of grant. No options have been granted under the LTIP or the 2012 LTIP since 2002.

Directors’ Deferred Compensation

Under the Pepco Holdings’ Executive and Director Deferred Compensation Plan, Pepco Holdings non-employee directors may elect to defer all or part of their cash retainer and meeting fees. Deferred retainer or meeting fees, at the election of the director, can be credited with interest at the prime rate or the return on selected investment funds or can be deemed invested in phantom shares of Pepco Holdings common stock on which dividend equivalent accruals are credited when dividends are paid on the common stock (or a combination of these options). All deferrals are settled in cash. The amount deferred by directors for the year ended December 31, 2015 was zero and was not material for each of the years ended December 31, 2014 and 2013.

Compensation expense recognized in respect of dividends and the increase in fair value was not material for each of the years ended December 31, 2015 and 2013, and $1 million for the year ended December 31, 2014. The deferred compensation balances under this program were approximately $2 million at December 31, 2015 and 2014.

A separate deferral option under the 2012 LTIP gives non-employee directors the right to elect to defer the receipt of common stock upon vesting of restricted stock unit awards.

Dividend Restrictions

PHI, on a stand-alone basis, generates no operating income of its own. Accordingly, its ability to pay dividends to its stockholders depends on dividends received from its subsidiaries. In addition to their future financial performance, the ability of PHI’s direct and indirect subsidiaries to pay dividends is subject to limits imposed by: (i) state corporate laws, which impose limitations on the funds that can be used to pay dividends and, in the case of ACE, the regulatory requirement that it obtain the prior approval of the NJBPU before dividends can be paid if its equity as a percent of its total capitalization, excluding securitization debt, falls below 30%; (ii) the prior rights of holders of mortgage bonds and other long-term debt issued by the subsidiaries, and any other restrictions imposed in connection with the incurrence of liabilities; and (iii) certain provisions of ACE’s charter that impose restrictions on payment of common stock dividends for the benefit of preferred stockholders. Pepco, DPL and ACE have no shares of preferred stock outstanding at December 31, 2015. Currently, the capitalization ratio limitation to which ACE is subject and the restriction in the ACE charter do not limit ACE’s ability to pay common stock dividends. As further described in Note (10), “Debt,” PHI, Pepco, DPL and ACE have restrictions on total indebtedness in relation to total capitalization under the credit facility.

PHI had approximately $617 million and $565 million of retained earnings free of restrictions at December 31, 2015 and 2014, respectively. These amounts represent the total retained earnings balances at those dates. The amount of restricted net assets for PHI’s consolidated subsidiaries at December 31, 2015 is $2,633 million.

For the years ended December 31, 2015, 2014 and 2013, dividends paid by PHI’s subsidiaries were as follows:

Subsidiary	2015		2014		2013
	(millions of dollars)
Pepco (paid to PHI)	$	146	$	86	$	46
DPL (paid to Conectiv)		92		100		30
ACE (paid to Conectiv)		12		26		60
Total	$	250	$	212	$	136

Equity Forward Transaction

During 2012, PHI entered into an equity forward transaction in connection with a public offering of PHI common stock. Pursuant to the terms of this transaction, a forward counterparty borrowed 17,922,077 shares of PHI’s common stock from third parties and sold them to a group of underwriters for $19.25 per share, less an underwriting discount equal to $0.67375 per share. Under the terms of the equity forward transaction, upon physical settlement thereof, PHI was required to issue and deliver shares of PHI common stock to the forward counterparty at the then applicable forward sale price. The forward sale price was initially determined to be $18.57625 per share at the time the equity forward transaction was entered into and was subject to reduction from time to time in accordance with the terms of the equity forward transaction. PHI believed that the equity forward transaction substantially eliminated future equity price risk because the forward sale price was determinable as of the date that PHI entered into the equity forward transaction and was only reduced pursuant to the contractual terms of the equity forward transaction through the settlement date, which reductions were not affected by a future change in the market price of the PHI common stock. On February 27, 2013, PHI physically settled the equity forward at the then applicable forward sale price of $17.39 per share. The proceeds of approximately $312 million were used to repay outstanding commercial paper, a portion of which had been issued in order to make capital contributions to the utilities, and for general corporate purposes.

Calculations of Earnings per Share of Common Stock

The numerator and denominator for basic and diluted earnings per share of common stock calculations are shown below.

	For the Year Ended December 31,
	2015		2014		2013
	(millions of dollars, except per share data)
Income (Numerator):
Net income from continuing operations	$	318	$	242	$	110
Net income (loss) from discontinued operations		9		—		(322	)
Net income (loss)	$	327	$	242	$	(212	)
Shares (Denominator) (in millions):
Weighted average shares outstanding for basic computation:
Average shares outstanding		253		251		246
Adjustment to shares outstanding		—		—		—
Weighted Average Shares Outstanding for Computation of Basic Earnings Per Share of Common Stock		253		251		246
Net effect of potentially dilutive shares (a)		1		1		—
Weighted Average Shares Outstanding for Computation of Diluted Earnings Per Share of Common Stock		254		252		246
Basic earnings per share of common stock from continuing operations	$	1.25	$	0.96	$	0.45
Basic earnings (loss) per share of common stock from discontinued operations		0.04		—		(1.31	)
Basic earnings (loss) per share	$	1.29	$	0.96	$	(0.86	)
Diluted earnings per share of common stock from continuing operations	$	1.25	$	0.96	$	0.45
Diluted earnings (loss) per share of common stock from discontinued operations		0.04		—		(1.31	)
Diluted earnings (loss) per share	$	1.29	$	0.96	$	(0.86	)

(a) There were no options to purchase shares of common stock that were excluded from the calculation of diluted earnings per share for the years ended December 31, 2015, 2014 and 2013.

Direct Stock Purchase and Dividend Reinvestment Plan

PHI maintains a DRP through which participants may reinvest cash dividends. In addition, participants can make purchases of shares of PHI common stock through the investment of not less than $25 per purchase nor more than $300,000 each calendar year. Shares of common stock purchased through the DRP may be new shares, treasury shares held by PHI, or, at the election of PHI, shares purchased in the open market. Less than 1 million, approximately 1 million and 2 million new shares were issued and sold under the DRP in 2015, 2014 and 2013, respectively.

Pepco Holdings Common Stock Reserved and Unissued

The following table presents Pepco Holdings’ common stock reserved and unissued at December 31, 2015:

Name of Plan	Number of Shares
DRP		4,584,077
Pepco Holdings Long-Term Incentive Plan (a)		6,946,614
Pepco Holdings 2012 Long-Term Incentive Plan		7,136,961
Pepco Holdings Retirement Savings Plan		3,456,261
Total		22,123,913

(a) No further awards will be made under this plan.

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Preferred Stock

12 Months Ended

Dec. 31, 2015

Equity [Abstract]

Preferred Stock

(13) PREFERRED STOCK

In connection with entering into the Merger Agreement (as further described in Note (1), “Organization”), PHI entered into a Subscription Agreement with Exelon, dated April 29, 2014, pursuant to which PHI issued to Exelon 9,000 originally issued shares of Preferred Stock for a purchase price of $90 million on April 30, 2014. In connection with these agreements, Exelon also committed to purchase 1,800 originally issued shares of Preferred Stock for a purchase price of $18 million at the end of each 90-day period following April 29, 2014, up to a maximum of 18,000 shares of Preferred Stock for a maximum aggregate consideration of $180 million. In accordance with the Subscription Agreement, on each of July 29, 2014, October 27, 2014, January 26, 2015, April 27, 2015 and July 24, 2015, an additional 1,800 shares of Preferred Stock were issued by PHI to Exelon for an aggregate purchase price of $90 million. If the Merger closes or terminates for any reason, no additional shares of Preferred Stock will be issued pursuant to the Subscription Agreement. The holders of the Preferred Stock will be entitled to receive a cumulative, non-participating cash dividend of 0.1% per annum, payable quarterly, when, as and if declared by PHI’s board of directors. The proceeds from the issuance of the Preferred Stock are not subject to restrictions and are intended to serve as a prepayment of any applicable reverse termination fee payable from Exelon to PHI. The Preferred Stock will be redeemable on the terms and in the circumstances set forth in the Merger Agreement and the Subscription Agreement.

If the Merger Agreement is terminated due to a Regulatory Termination, PHI will be able to redeem any issued and outstanding Preferred Stock at par value ($0.01 per share). If the Merger Agreement is terminated for any other reason, PHI will be required to redeem all issued and outstanding Preferred Stock at the purchase price of $10,000 per share, plus any unpaid accrued and accumulated dividends thereupon.

PHI has excluded the Preferred Stock from equity at December 31, 2015 and 2014, since the Preferred Stock contains conditions for redemption that are not solely within the control of PHI. Management determined that the Preferred Stock contains embedded features requiring separate accounting consideration to reflect the potential value to PHI that any issued and outstanding Preferred Stock could be called and redeemed at a nominal par value upon a Regulatory Termination. The embedded call and redemption features on the shares of the Preferred Stock in the event of a Regulatory Termination are separately accounted for as derivatives. These Preferred Stock derivatives are valued at each reporting date using quantitative and qualitative factors, including management’s assessment of the likelihood of a Regulatory Termination. As of December 31, 2015, the fair value of the remaining derivative related to the Preferred Stock was estimated to be $18 million based on management’s updated assessment. The estimated fair value of the derivatives related to the Preferred Stock at December 31, 2014 was $3 million and has been included in current assets (Prepaid expenses and other) with a corresponding increase in Preferred Stock on the consolidated balance sheet at December 31, 2014. The $15 million increase in the fair value of the derivative has been included in Other income for the year ended December 31, 2015.

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Derivative Instruments and Hedging Activities

12 Months Ended

Dec. 31, 2015

Derivative Instruments and Hedging Activities

(14) DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Derivative Instruments

DPL uses derivative instruments in the form of futures primarily to reduce natural gas commodity price volatility and to limit its customers’ exposure to increases in the market price of natural gas under a hedging program approved by the DPSC. DPL uses these derivatives to manage the commodity price risk associated with its physical natural gas purchase contracts. The natural gas purchase contracts qualify as normal purchases, which are not required to be recorded in the financial statements until settled. All premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all gains and losses related to hedging activities, are deferred under FASB guidance on regulated operations (ASC 980) until recovered from its customers through a fuel adjustment clause approved by the DPSC. In addition, included in derivative assets are PHI Preferred Stock derivatives which are further described in Note (13), “Preferred Stock.”

ACE was ordered to enter into the SOCAs by the NJBPU, and under the SOCAs, ACE would have received payments from or made payments to electric generation facilities based on (i) the difference between the fixed price in the SOCAs and the price for capacity that clears PJM and (ii) ACE’s annual proportion of the total New Jersey load relative to the other EDCs in New Jersey. ACE began applying derivative accounting to two of its SOCAs as of June 30, 2012 because these generators cleared the 2015-2016 PJM capacity auction in May 2012. The fair value of the derivatives embedded in these SOCAs were deferred as Regulatory assets or Regulatory liabilities because the NJBPU allowed full recovery from ACE’s distribution customers for any payments made by ACE, and ACE’s distribution customers would be entitled to payments received by ACE.

As further discussed in Note (7), “Regulatory Matters,” in light of a Federal district court order, which ruled that the SOCAs are void, invalid and unenforceable, and ACE’s subsequent termination of the SOCAs in the fourth quarter of 2013, ACE derecognized the derivative assets and derivative liabilities related to the SOCAs.

The tables below identify the balance sheet location and fair values of derivative instruments as of December 31, 2015 and 2014:

	As of December 31, 2015
Balance Sheet Caption	Derivatives Designated as Hedging Instruments		Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting		Net Derivative Instruments
						(millions of dollars)
Derivative assets (current assets)	$	—	$	18		$	18		$	—	$	18
Derivative liabilities (current liabilities)		—		(2	)		(2	)		2		—
Net derivative asset	$	—	$	16		$	16		$	2	$	18

	As of December 31, 2014
Balance Sheet Caption	Derivatives Designated as Hedging Instruments		Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting		Net Derivative Instruments
						(millions of dollars)
Derivative assets (current assets)	$	—	$	3		$	3		$	—	$	3
Derivative liabilities (current liabilities)		—		(4	)		(4	)		4		—
Net derivative (liability) asset	$	—	$	(1	)	$	(1	)	$	4	$	3

All derivative assets and liabilities available to be offset under master netting arrangements were netted as of December 31, 2015 and 2014. The amount of cash collateral that was offset against these derivative positions is as follows:

	December 31, 2015		December 31, 2014
	(millions of dollars)
Cash collateral pledged to counterparties with the right to reclaim (a)	$	2	$	4

(a) Includes cash deposits on commodity brokerage accounts.

As of December 31, 2015 and 2014, all PHI cash collateral pledged related to derivative instruments accounted for at fair value was entitled to be offset under master netting agreements.

Derivatives Designated as Hedging Instruments

Cash Flow Hedges Included in Accumulated Other Comprehensive Loss

PHI also may use derivative instruments from time to time to mitigate the effects of fluctuating interest rates on debt issued in connection with the operation of its businesses. In June 2002, PHI entered into several treasury rate lock transactions in anticipation of the issuance of several series of fixed-rate debt commencing in August 2002. Upon issuance of the fixed-rate debt in August 2002, the treasury rate locks were terminated at a loss. The loss has been deferred in AOCL and is being recognized in interest expense over the life of the debt issued as interest payments are made.

The tables below provide details regarding terminated cash flow hedges included in PHI’s consolidated balance sheets as of December 31, 2015 and 2014. The data in the following tables indicate the cumulative net loss after-tax related to terminated cash flow hedges by contract type included in AOCL, the portion of AOCL expected to be reclassified to income during the next 12 months, and the maximum hedge or deferral term:

Contracts	As of December 31, 2015				Maximum Term
	Accumulated Other Comprehensive Loss After-tax		Portion Expected to be Reclassified to Income during the Next 12 Months
	(millions of dollars)
Interest rate	$	8	$	1		200 months

Contracts	As of December 31, 2014				Maximum Term
	Accumulated Other Comprehensive Loss After-tax		Portion Expected to be Reclassified to Income during the Next 12 Months
	(millions of dollars)
Interest rate	$	9	$	1		212 months

Other Derivative Activity

DPL has certain derivatives that are not in hedge accounting relationships and are not designated as normal purchases or normal sales. These derivatives are recorded at fair value on the consolidated balance sheets with the gain or loss for changes in fair value recorded in income. In addition, in accordance with FASB guidance on regulated operations (ASC 980), regulatory liabilities or regulatory assets of the same amount are recorded on the consolidated balance sheets and the recognition of the derivative gain or loss is deferred because of the DPSC-approved fuel adjustment clause for DPL’s derivatives and the NJBPU order pertaining to the ACE SOCA derivatives. During 2012, ACE had recognized derivative assets and derivative liabilities in connection with the SOCAs referred to in Note (7), “Regulatory Matters.” In 2013, the Federal district court issued an order as described in Note (7), “Regulatory Matters” which caused ACE to derecognize the derivative assets and derivatives liabilities related to the SOCAs in the fourth quarter of 2013. The following table shows the net unrealized and net realized derivative gains and losses arising during the period associated with these derivatives that were recognized in the consolidated statements of income (loss) (through Fuel and purchased energy expense) and that were also deferred as regulatory liabilities and regulatory assets, respectively, for the years ended December 31, 2015, 2014 and 2013:

	For the Year Ended December 31,
	2015			2014			2013
	(millions of dollars)
Net unrealized (loss) gain arising during the period	$	(3	)	$	(3	)	$	4
Net realized (loss) gain recognized during the period		(5	)		2			(4	)

As of December 31, 2015 and 2014, the quantities and positions of DPL’s net outstanding natural gas commodity forward contracts that did not qualify for hedge accounting were:

	December 31, 2015			December 31, 2014
Commodity	Quantity		Net Position	Quantity		Net Position
DPL – Natural gas (one Million British Thermal Units)		4,190,000	Long		3,892,500	Long

In addition, PHI recorded derivative assets for the embedded call and redemption features on the shares of Preferred Stock as further described in Note (13), “Preferred Stock.” The net unrealized gain arising during 2015 related to these derivative assets was $15 million and has been included in Other income.

Delmarva Power & Light Co/De [Member]

Derivative Instruments and Hedging Activities

(12) DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

DPL uses derivative instruments in the form of futures primarily to reduce natural gas commodity price volatility and to limit its customers’ exposure to increases in the market price of natural gas under a hedging program approved by the DPSC. DPL uses these derivatives to manage the commodity price risk associated with its physical natural gas purchase contracts. The natural gas purchase contracts qualify as normal purchases, which are not required to be recorded in the financial statements until settled. All premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all gains and losses related to hedging activities, are deferred under FASB guidance on regulated operations (ASC 980) until recovered from its customers through a fuel adjustment clause approved by the DPSC.

The tables below identify the balance sheet location and fair values of derivative instruments as of December 31, 2015 and 2014:

	As of December 31, 2015
Balance Sheet Caption	Derivatives Designated as Hedging Instruments		Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting		Net Derivative Instruments
	(millions of dollars)
Derivative liabilities (current liabilities)	$	—	$	(2	)	$	(2	)	$	2	$	—

	As of December 31, 2014
Balance Sheet Caption	Derivatives Designated as Hedging Instruments		Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting		Net Derivative Instruments
	(millions of dollars)
Derivative liabilities (current liabilities)	$	—	$	(4	)	$	(4	)	$	4	$	—

All derivative liabilities available to be offset under master netting arrangements were netted as of December 31, 2015 and 2014. The amount of cash collateral that was offset against these derivative positions is as follows:

	December 31, 2015		December 31, 2014
	(millions of dollars)
Cash collateral pledged to counterparties with the right reclaim (a)	$	2	$	4

(a) Includes cash deposits on commodity brokerage accounts.

As of December 31, 2015 and 2014, all DPL cash collateral pledged related to derivative instruments accounted for at fair value was entitled to be offset under master netting agreements.

Other Derivative Activity

DPL has certain derivatives that are not in hedge accounting relationships and are not designated as normal purchases or normal sales. These derivatives are recorded at fair value on the balance sheets with the gain or loss for changes in the fair value recorded in income. In addition, in accordance with FASB guidance on regulated operations, regulatory liabilities or regulatory assets of the same amount are recorded on the balance sheets and the recognition of the derivative gain or loss is deferred because of the DPSC-approved fuel adjustment clause. The following table shows the net unrealized and net realized derivative gains and losses arising during the period associated with these derivatives that were recognized in the statements of income (through Purchased energy and Gas purchased expense) and that were also deferred as regulatory liabilities and regulatory assets, respectively, for the years ended December 31, 2015, 2014 and 2013:

	For the Year Ended December 31,
	2015			2014			2013
	(millions of dollars)
Net unrealized (loss) gain arising during the period	$	(3	)	$	(3	)	$	1
Net realized (loss) gain recognized during the period		(5	)		2			(4	)

As of December 31, 2015 and 2014, the quantities and positions of DPL’s net outstanding natural gas commodity forward contracts that did not qualify for hedge accounting were:

	December 31, 2015			December 31, 2014
Commodity	Quantity		Net Position	Quantity		Net Position
Natural Gas (One Million British Thermal Units)		4,190,000	Long		3,892,500	Long

Atlantic City Electric Co [Member]

Derivative Instruments and Hedging Activities

(11) DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

ACE was ordered to enter into the SOCAs by the NJBPU, and under the SOCAs, ACE would have received payments from or made payments to electric generation facilities based on (i) the difference between the fixed price in the SOCAs and the price for capacity that clears PJM Interconnection, LLC (PJM) and (ii) ACE’s annual proportion of the total New Jersey load relative to the other EDCs in New Jersey. ACE began applying derivative accounting to two of its SOCAs as of June 30, 2012 because these generators cleared the 2015-2016 PJM capacity auction in May 2012. The fair value of the derivatives embedded in the SOCAs were deferred as Regulatory assets or Regulatory liabilities because the NJBPU allowed full recovery from ACE’s distribution customers for any payments made by ACE, and ACE’s distribution customers would be entitled to any payments received by ACE.

As further discussed in Note (6), “Regulatory Matters,” in light of a Federal district court order, which ruled that the SOCAs are void, invalid and unenforceable, and ACE’s subsequent termination of the SOCAs in the fourth quarter of 2013, ACE derecognized the derivative assets and derivative liabilities related to the SOCAs.

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Fair Value Disclosures

12 Months Ended

Dec. 31, 2015

Fair Value Disclosures

(15) FAIR VALUE DISCLOSURES

Financial Instruments Measured at Fair Value on a Recurring Basis

PHI applies FASB guidance on fair value measurement (ASC 820) that established a framework for measuring fair value and expanded disclosures about fair value measurements. As defined in the guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). PHI utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. Accordingly, PHI utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1) and the lowest priority to unobservable inputs (level 3).

The following tables set forth, by level within the fair value hierarchy, PHI’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2015 and 2014. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. PHI’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Fair Value Measurements at December 31, 2015
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1) (a)		Significant Other Observable Inputs (Level 2) (a)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Derivative instruments
Preferred stock	$	18	$	—	$	—	$	18
Cash equivalents and restricted cash equivalents
Treasury fund		42		42		—		—
Executive deferred compensation plan assets
Money market funds and short-term investments		27		12		15		—
Life insurance contracts		46		—		27		19
Total	$	133	$	54	$	42	$	37
LIABILITIES
Derivative instruments (b)
Natural gas (c)	$	2	$	2	$	—	$	—
Executive deferred compensation plan liabilities
Life insurance contracts		30		—		30		—
Total	$	32	$	2	$	30	$	—

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2015.

(b) The fair values of derivative liabilities reflect netting by counterparty before the impact of collateral.

(c) Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.

	Fair Value Measurements at December 31, 2014
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1) (a)		Significant Other Observable Inputs (Level 2) (a)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Derivative instruments
Preferred stock	$	3	$	—	$	—	$	3
Restricted cash equivalents
Treasury fund		38		38		—		—
Executive deferred compensation plan assets
Money market funds and short-term investments		35		14		21		—
Life insurance contracts		46		—		27		19
Total	$	122	$	52	$	48	$	22
LIABILITIES
Derivative instruments (b)
Natural gas (c)	$	4	$	4	$	—	$	—
Executive deferred compensation plan liabilities
Life insurance contracts		30		—		30		—
Total	$	34	$	4	$	30	$	—

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2014.

(b) The fair values of derivative liabilities reflect netting by counterparty before the impact of collateral.

(c) Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.

PHI classifies its fair value balances in the fair value hierarchy based on the observability of the inputs used in the fair value calculation as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis, such as the Intercontinental Exchange.

Level 2 – Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using broker quotes in liquid markets and other observable data. Level 2 also includes those financial instruments that are valued using methodologies that have been corroborated by observable market data through correlation or by other means. Significant assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

Executive deferred compensation plan assets and liabilities categorized as level 2 consist of life insurance policies and certain employment agreement obligations. The life insurance policies are categorized as level 2 assets because they are valued based on the assets underlying the policies, which consist of short-term cash equivalents and fixed income securities that are priced using observable market data and can be liquidated for the value of the underlying assets as of December 31, 2015. The level 2 liability associated with the life insurance policies represents a deferred compensation obligation, the value of which is tracked via underlying insurance sub-accounts. The sub-accounts are designed to mirror existing mutual funds and money market funds that are observable and actively traded.

The value of certain employment agreement obligations (which are included with life insurance contracts in the tables above) is derived using a discounted cash flow valuation technique. The discounted cash flow calculations are based on a known and certain stream of payments to be made over time that are discounted to determine their net present value. The primary variable input, the discount rate, is based on market-corroborated and observable published rates. These obligations have been classified as level 2 within the fair value hierarchy because the payment streams represent contractually known and certain amounts and the discount rate is based on published, observable data.

Level 3 – Pricing inputs that are significant and generally less observable than those from objective sources. Level 3 includes those financial instruments that are valued using models or other valuation methodologies.

Derivative instruments classified as level 3 include embedded call and redemption features on the Preferred Stock as further discussed in Note (13), “Preferred Stock.”

Executive deferred compensation plan assets include certain life insurance policies that are valued using the cash surrender value of the policies, net of loans against those policies. The cash surrender values do not represent a quoted price in an active market; therefore, those inputs are unobservable and the policies are categorized as level 3. Cash surrender values are provided by third parties and reviewed by PHI for reasonableness.

Reconciliations of the beginning and ending balances of PHI’s fair value measurements using significant unobservable inputs (Level 3) for the years ended December 31, 2015 and 2014 are shown below:

	Year Ended December 31,
	2015					2014
	Preferred Stock		Life Insurance Contracts			Preferred Stock		Life Insurance Contracts
	(millions of dollars)
Balance as of January 1	$	3	$	19		$	—	$	19
Total gains (losses) (realized and unrealized):
Included in income		15		5			—		3
Included in accumulated other comprehensive loss		—		—			—		—
Included in regulatory liabilities		—		—			—		—
Purchases		—		—			—		—
Issuances		—		(3	)		3		(3	)
Settlements		—		(2	)		—		—
Transfers in (out) of level 3		—		—			—		—
Balance as of December 31	$	18	$	19		$	3	$	19

The breakdown of realized and unrealized gains on level 3 instruments included in income as a component of Other income or Other operation and maintenance expense for the periods below were as follows:

	Year Ended December 31,
	2015		2014
	(millions of dollars)
Total net gains included in income for the period	$	20	$	3
Change in unrealized gains relating to assets still held at reporting date	$	18	$	3

Other Financial Instruments

The estimated fair values of PHI’s Long-term debt instruments that are measured at amortized cost in PHI’s consolidated financial statements and the associated levels of the estimates within the fair value hierarchy as of December 31, 2015 and 2014 are shown in the tables below. As required by the fair value measurement guidance, debt instruments are classified in their entirety within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. PHI’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, which may affect the valuation of fair value debt instruments and their placement within the fair value hierarchy levels.

The fair values of Long-term debt and Transition bonds categorized as level 2 are based on a blend of quoted prices for the debt and quoted prices for similar debt on the measurement date. The blend places more weight on current pricing information when determining the final fair value measurement. The fair value information is provided by brokers, and PHI reviews the methodologies and results.

The fair value of Long-term debt categorized as level 3 is based on a discounted cash flow methodology using observable inputs, such as the U.S. Treasury yield, and unobservable inputs, such as credit spreads, because quoted prices for the debt or similar debt in active markets were insufficient. The Long-term project funding represents debt instruments issued by Pepco and Pepco Energy Services related to its energy savings and construction contracts. Long-term project funding is categorized as level 3 because PHI concluded that the amortized cost carrying amounts for these instruments approximate fair value, which does not represent a quoted price in an active market.

	Fair Value Measurements at December 31, 2015
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	5,523	$	—	$	4,941	$	582
Transition Bonds (b)		185		—		185		—
Long-term project funding		5		—		—		5
Total	$	5,713	$	—	$	5,126	$	587

(a) The carrying amount for Long-term debt, net of unamortized discount, was $4,999 million as of December 31, 2015.

(b) The carrying amount for Transition Bonds, including amounts due within one year, was $171 million as of December 31, 2015.

	Fair Value Measurements at December 31, 2014
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	5,583	$	—	$	5,136	$	447
Transition Bonds (b)		235		—		235		—
Long-term project funding		28		—		—		28
Total	$	5,846	$	—	$	5,371	$	475

(a) The carrying amount for Long-term debt, net of unamortized discount, was $4,807 million as of December 31, 2014.

(b) The carrying amount for Transition Bonds, including amounts due within one year, was $215 million as of December 31, 2014.

The carrying amounts of all other financial instruments in the accompanying consolidated financial statements approximate fair value.

Potomac Electric Power Co [Member]

Fair Value Disclosures

(11) FAIR VALUE DISCLOSURES

Financial Instruments Measured at Fair Value on a Recurring Basis

Pepco applies FASB guidance on fair value measurement (ASC 820) that established a framework for measuring fair value and expanded disclosures about fair value measurements. As defined in the guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Pepco utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. Accordingly, Pepco utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1) and the lowest priority to unobservable inputs (level 3).

The following tables set forth, by level within the fair value hierarchy, Pepco’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2015 and 2014. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Pepco’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Fair Value Measurements at December 31, 2015
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1) (a)		Significant Other Observable Inputs (Level 2) (a)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Cash equivalents and restricted cash equivalents
Treasury funds	$	2	$	2	$	—	$	—
Executive deferred compensation plan assets
Money market funds and short-term investments		26		11		15		—
Life insurance contracts		42		—		23		19
Total	$	70	$	13	$	38	$	19
LIABILITIES
Executive deferred compensation plan liabilities
Life insurance contracts	$	6	$	—	$	6	$	—
Total	$	6	$	—	$	6	$	—

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2015.

	Fair Value Measurements at December 31, 2014
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1) (a)		Significant Other Observable Inputs (Level 2) (a)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Restricted cash equivalents
Treasury fund	$	5	$	5	$	—	$	—
Executive deferred compensation plan assets
Money market funds and short-term investments		34		13		21		—
Life insurance contracts		41		—		23		18
Total	$	80	$	18	$	44	$	18
LIABILITIES
Executive deferred compensation plan liabilities
Life insurance contracts	$	7	$	—	$	7	$	—
Total	$	7	$	—	$	7	$	—

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2014.

Pepco classifies its fair value balances in the fair value hierarchy based on the observability of the inputs used in the fair value calculation as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 – Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using broker quotes in liquid markets and other observable data. Level 2 also includes those financial instruments that are valued using methodologies that have been corroborated by observable market data through correlation or by other means. Significant assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

Executive deferred compensation plan assets and liabilities categorized as level 2 consist of life insurance policies and certain employment agreement obligations. The life insurance policies are categorized as level 2 assets because they are valued based on the assets underlying the policies, which consist of short-term cash equivalents and fixed income securities that are priced using observable market data and can be liquidated for the value of the underlying assets as of December 31, 2015. The level 2 liability associated with the life insurance policies represents a deferred compensation obligation, the value of which is tracked via underlying insurance sub-accounts. The sub-accounts are designed to mirror existing mutual funds and money market funds that are observable and actively traded.

The value of certain employment agreement obligations (which are included with life insurance contracts in the tables above) is derived using a discounted cash flow valuation technique. The discounted cash flow calculations are based on a known and certain stream of payments to be made over time that are discounted to determine their net present value. The primary variable input, the discount rate, is based on market-corroborated and observable published rates. These obligations have been classified as level 2 within the fair value hierarchy because the payment streams represent contractually known and certain amounts and the discount rate is based on published, observable data.

Level 3 – Pricing inputs that are significant and generally less observable than those from objective sources. Level 3 includes those financial instruments that are valued using models or other valuation methodologies.

Executive deferred compensation plan assets include certain life insurance policies that are valued using the cash surrender value of the policies, net of loans against those policies. The cash surrender values do not represent a quoted price in an active market; therefore, those inputs are unobservable and the policies are categorized as level 3. Cash surrender values are provided by third parties and reviewed by Pepco for reasonableness.

Reconciliations of the beginning and ending balances of Pepco’s fair value measurements using significant unobservable inputs (Level 3) for the years ended December 31, 2015 and 2014 are shown below.

	2015			2014
	Life Insurance Contracts			Life Insurance Contracts
	(millions of dollars)
Balance as of January 1	$	18		$	18
Total gains (losses) (realized and unrealized):
Included in income		5			3
Included in accumulated other comprehensive loss		—			—
Purchases		—			—
Issuances		(3	)		(3	)
Settlements		(1	)		—
Transfers in (out) of level 3		—			—
Balance as of December 31	$	19		$	18

The breakdown of realized and unrealized gains on level 3 instruments included in income as a component of Other income or Other operation and maintenance expense for the periods below were as follows:

	Year Ended December 31,
	2015		2014
	(millions of dollars)
Total gains included in income for the period	$	5	$	3
Change in unrealized gains relating to assets still held at reporting date	$	3	$	3

Other Financial Instruments

The estimated fair values of Pepco’s Long-term debt instruments that are measured at amortized cost in Pepco’s financial statements and the associated levels of the estimates within the fair value hierarchy as of December 31, 2015 and 2014 are shown in the tables below. As required by the fair value measurement guidance, debt instruments are classified in their entirety within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. Pepco’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, which may affect the valuation of fair value debt instruments and their placement within the fair value hierarchy levels.

The fair value of Long-term debt categorized as level 2 is based on a blend of quoted prices for the debt and quoted prices for similar debt on the measurement date. The blend places more weight on current pricing information when determining the final fair value measurement. The fair value information is provided by brokers, and Pepco reviews the methodologies and results.

The Project funding represents debt instruments issued by Pepco related to its construction contracts. Project funding is categorized as level 3 because Pepco concluded that the amortized cost carrying amounts for these instruments approximate fair value, which does not represent a quoted price in an active market.

	Fair Value Measurements at December 31, 2015
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	2,673	$	—	$	2,673	$	—

(a) The carrying amount for Long-term debt, net of unamortized discount, was $2,332 million as of December 31, 2015.

	Fair Value Measurements at December 31, 2014
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	2,624	$	—	$	2,624	$	—
Project funding		12		—		—		12
Total	$	2,636	$	—	$	2,624	$	12

(a) The carrying amount for Long-term debt, net of unamortized discount, was $2,124 million as of December 31, 2014.

The carrying amount of all other financial instruments in the accompanying financial statements approximate fair value.

Delmarva Power & Light Co/De [Member]

Fair Value Disclosures

(13) FAIR VALUE DISCLOSURES

Financial Instruments Measured at Fair Value on a Recurring Basis

DPL applies FASB guidance on fair value measurement (ASC 820) that established a framework for measuring fair value and expanded disclosures about fair value measurements. As defined in the guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). DPL utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. Accordingly, DPL utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1) and the lowest priority to unobservable inputs (level 3).

The following tables set forth, by level within the fair value hierarchy, DPL’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2015 and 2014. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. DPL’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Fair Value Measurements at December 31, 2015
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1) (a)		Significant Other Observable Inputs (Level 2) (a)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Derivative instruments (b)
Natural gas (c)	$	2	$	2	$	—	$	—
Executive deferred compensation plan liabilities
Life insurance contracts		1		—		1		—
Total	$	3	$	2	$	1	$	—

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2015.

(b) The fair value of derivative liabilities reflect netting by counterparty before the impact of collateral.

(c) Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.

	Fair Value Measurements at December 31, 2014
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1) (a)		Significant Other Observable Inputs (Level 2) (a)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Restricted cash equivalents
Treasury funds	$	5	$	5	$	—	$	—
Executive deferred compensation plan assets
Money market funds		1		1		—		—
Life insurance contracts		1		—		—		1
Total	$	7	$	6	$	—	$	1
LIABILITIES
Derivative instruments (b)
Natural gas (c)	$	4	$	4	$	—	$	—
Executive deferred compensation plan liabilities
Life insurance contracts		1		—		1		—
Total	$	5	$	4	$	1	$	—

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2014.

(b) The fair value of derivative liabilities reflect netting by counterparty before the impact of collateral.

(c) Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.

DPL classifies its fair value balances in the fair value hierarchy based on the observability of the inputs used in the fair value calculation as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis, such as the Intercontinental Exchange.

Level 2 – Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using broker quotes in liquid markets and other observable data. Level 2 also includes those financial instruments that are valued using methodologies that have been corroborated by observable market data through correlation or by other means. Significant assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

Level 2 executive deferred compensation plan liabilities associated with the life insurance policies represent a deferred compensation obligation, the value of which is tracked via underlying insurance sub-accounts. The sub-accounts are designed to mirror existing mutual funds and money market funds that are observable and actively traded.

Level 3 – Pricing inputs that are significant and generally less observable than those from objective sources. Level 3 includes those financial instruments that are valued using models or other valuation methodologies.

Executive deferred compensation plan assets include certain life insurance policies that are valued using the cash surrender value of the policies, net of loans against those policies. The cash surrender values do not represent a quoted price in an active market; therefore, those inputs are unobservable and the policies are categorized as level 3. Cash surrender values are provided by third parties and reviewed by DPL for reasonableness.

Reconciliations of the beginning and ending balances of DPL’s fair value measurements using significant unobservable inputs (Level 3) for the years ended December 31, 2015 and 2014 are shown below:

	Year Ended December 31, 2015			Year Ended December 31, 2014
	Life Insurance Contracts			Life Insurance Contracts
	(millions of dollars)
Balance as of January 1	$	1		$	1
Total gains (losses) (realized and unrealized):
Included in income		—			—
Included in accumulated other comprehensive loss		—			—
Included in regulatory liabilities		—			—
Purchases		—			—
Issuances		—			—
Settlements		(1	)		—
Transfers in (out) of Level 3		—			—
Balance as of December 31	$	—		$	1

Other Financial Instruments

The estimated fair values of DPL’s Long-term debt instruments that are measured at amortized cost in DPL’s financial statements and the associated levels of the estimates within the fair value hierarchy as of December 31, 2015 and 2014 are shown in the tables below. As required by the fair value measurement guidance, debt instruments are classified in their entirety within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. DPL’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, which may affect the valuation of fair value debt instruments and their placement within the fair value hierarchy levels.

The fair value of Long-term debt categorized as level 2 is based on a blend of quoted prices for the debt and quoted prices for similar debt on the measurement date. The blend places more weight on current pricing information when determining the final fair value measurement. The fair value information is provided by brokers, and DPL reviews the methodologies and results.

The fair value of Long-term debt categorized as level 3 is based on a discounted cash flow methodology using observable inputs, such as the U.S. Treasury yield, and unobservable inputs, such as credit spreads, because quoted prices for the debt or similar debt in active markets were insufficient.

	Fair Value Measurements at December 31, 2015
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	1,183	$	—	$	1,080	$	103

(a) The carrying amount for Long-term debt, including unamortized premium, was $1,170 million as of December 31, 2015.

	Fair Value Measurements at December 31, 2014
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	1,123	$	—	$	1,016	$	107

(a) The carrying amount for Long-term debt, including unamortized premium, was $1,071 million as of December 31, 2014.

The carrying amounts of all other financial instruments in the accompanying financial statements approximate fair value.

Atlantic City Electric Co [Member]

Fair Value Disclosures

(12) FAIR VALUE DISCLOSURES

Financial Instruments Measured at Fair Value on a Recurring Basis

ACE applies FASB guidance on fair value measurement (ASC 820) that established a framework for measuring fair value and expanded disclosures about fair value measurements. As defined in the guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). ACE utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. Accordingly, ACE utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1) and the lowest priority to unobservable inputs (level 3).

The following tables set forth by level within the fair value hierarchy ACE’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2015 and 2014. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. ACE’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Fair Value Measurements at December 31, 2015
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1) (a)		Significant Other Observable Inputs (Level 2) (a)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Cash equivalents and restricted cash equivalents
Treasury funds	$	30	$	30	$	—	$	—

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2015.

	Fair Value Measurements at December 31, 2014
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1) (a)		Significant Other Observable Inputs (Level 2) (a)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Cash equivalents and restricted cash equivalents
Treasury funds	$	24	$	24	$	—	$	—

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2014.

ACE classifies its fair value balances in the fair value hierarchy based on the observability of the inputs used in the fair value calculation as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 – Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using broker quotes in liquid markets and other observable data. Level 2 also includes those financial instruments that are valued using methodologies that have been corroborated by observable market data through correlation or by other means. Significant assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

Level 3 – Pricing inputs that are significant and generally less observable than those from objective sources. Level 3 includes those financial instruments that are valued using models or other valuation methodologies.

Other Financial Instruments

The estimated fair values of ACE’s Long-term debt instruments that are measured at amortized cost in ACE’s consolidated financial statements and the associated levels of the estimates within the fair value hierarchy as of December 31, 2015 and 2014 are shown in the tables below. As required by the fair value measurement guidance, debt instruments are classified in their entirety within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. ACE’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, which may affect the valuation of fair value debt instruments and their placement within the fair value hierarchy levels.

The fair values of Long-term debt and Transition bonds categorized as level 2 are based on a blend of quoted prices for the debt and quoted prices for similar debt on the measurement date. The blend places more weight on current pricing information when determining the final fair value measurement. The fair value information is provided by brokers, and ACE reviews the methodologies and results.

The fair value of Long-term debt categorized as level 3 is based on a discounted cash flow methodology using observable inputs, such as the U.S. Treasury yield, and unobservable inputs, such as credit spreads, because quoted prices for the debt or similar debt in active markets were insufficient.

	Fair Value Measurements at December 31, 2015
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	1,140	$	—	$	860	$	280
Transition Bonds (b)		185		—		185		—
Total	$	1,325	$	—	$	1,045	$	280

(a) The carrying amount for Long-term debt, net of unamortized discount, was $1,038 million as of December 31, 2015.

(b) The carrying amount for Transition Bonds, including amounts due within one year, was $171 million as of December 31, 2015.

	Fair Value Measurements at December 31, 2014
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	1,035	$	—	$	903	$	132
Transition Bonds (b)		235		—		235		—
Total	$	1,270	$	—	$	1,138	$	132

(a) The carrying amount for Long-term debt, net of unamortized discount, was $903 million as of December 31, 2014.

(b) The carrying amount for Transition Bonds, including amounts due within one year, was $215 million as of December 31, 2014.

The carrying amounts of all other financial instruments in the accompanying consolidated financial statements approximate fair value.

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2015

Commitments and Contingencies

(16) COMMITMENTS AND CONTINGENCIES

General Litigation

From time to time, PHI and its subsidiaries are named as defendants in litigation, usually relating to general liability or auto liability claims that resulted in personal injury or property damage to third parties. PHI and each of its subsidiaries are self-insured against such claims up to a certain self-insured retention amount and maintain insurance coverage against such claims at higher levels, to the extent deemed prudent by management. In addition, PHI’s contracts with its vendors generally require the vendors to name PHI and/or its subsidiaries as additional insureds for the amounts at least equal to PHI’s self-insured retention. Further, PHI’s contracts with its vendors require the vendors to indemnify PHI for various acts and activities that may give rise to claims against PHI. Loss contingency liabilities for both asserted and unasserted claims are recognized if it is probable that a loss will result from such a claim and if the amounts of the losses can be reasonably estimated. Although the outcome of the claims and proceedings cannot be predicted with any certainty, management believes that there are no existing claims or proceedings that are likely to have a material adverse effect on PHI’s or its subsidiaries’ financial condition, results of operations or cash flows. At December 31, 2015, PHI had recorded estimated loss contingency liabilities for general litigation totaling approximately $12 million.

Environmental Matters

PHI, through its subsidiaries, is subject to regulation by various federal, regional, state and local authorities with respect to the environmental effects of its operations, including air and water quality control, solid and hazardous waste disposal and limitations on land use. Although penalties assessed for violations of environmental laws and regulations are not recoverable from customers of PHI’s utility subsidiaries, environmental clean-up costs incurred by Pepco, DPL and ACE generally are included by each company in its respective cost of service for ratemaking purposes. The total accrued liabilities for the environmental contingencies described below of PHI and its subsidiaries at December 31, 2015 are summarized as follows:

				Legacy Generation
	Transmission and Distribution			Regulated			Non-Regulated		Total
				(millions of dollars)
Balance as of January 1	$	17		$	6		$	5	$	28
Accruals		7			3			—		10
Payments		(4	)		(1	)		—		(5	)
Balance as of December 31		20			8			5		33
Less amounts in Other Current Liabilities		3			1			—		4
Amounts in Other Deferred Credits	$	17		$	7		$	5	$	29

Conectiv Energy Wholesale Power Generation Sites

In July 2010, PHI sold the wholesale power generation business of Conectiv Energy Holdings, Inc. and substantially all of its subsidiaries (Conectiv Energy) to Calpine Corporation (Calpine). Under New Jersey’s Industrial Site Recovery Act (ISRA), the transfer of ownership triggered an obligation on the part of Conectiv Energy to remediate any environmental contamination at each of the nine Conectiv Energy generating facility sites located in New Jersey. Under the terms of the sale, Calpine has assumed responsibility for performing the ISRA-required remediation and for the payment of all related ISRA compliance costs up to $10 million. PHI is obligated to indemnify Calpine for any ISRA compliance remediation costs in excess of $10 million. According to PHI’s estimates, the costs of ISRA-required remediation activities at the nine generating facility sites located in New Jersey are in the range of approximately $7 million to $18 million. The amount accrued by PHI for the ISRA-required remediation activities at the nine generating facility sites is included in the table above in the column entitled “Legacy Generation – Non-Regulated.”

In September 2011, PHI received a request for data from the U.S. Environmental Protection Agency (EPA) regarding operations at the Deepwater generating facility in New Jersey (which was included in the sale to Calpine) between February 2004 and July 1, 2010, to demonstrate compliance with the Clean Air Act’s new source review permitting program. PHI responded to the data request. Under the terms of the Calpine sale, PHI is obligated to indemnify Calpine for any failure of PHI, on or prior to the closing date of the sale, to comply with environmental laws attributable to the construction of new, or modification of existing, sources of air emissions. At this time, PHI does not expect that any financial consequences that could arise from this inquiry would have a material adverse effect on its consolidated financial condition, results of operations or cash flows.

Franklin Slag Pile Site

In November 2008, ACE received a general notice letter from EPA concerning the Franklin Slag Pile site in Philadelphia, Pennsylvania, asserting that ACE is a potentially responsible party (PRP) that may have liability for clean-up costs with respect to the site and for the costs of implementing an EPA-mandated remedy. EPA’s claims are based on ACE’s sale of boiler slag from the B.L. England generating facility, then owned by ACE, to MDC Industries, Inc. (MDC) during the period from June 1978 to May 1983. EPA claims that the boiler slag ACE sold to MDC contained copper and lead, which are hazardous substances under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA), and that the sales transactions may have constituted an arrangement for the disposal or treatment of hazardous substances at the site, which could be a basis for liability under CERCLA. The EPA letter also states that, as of the date of the letter, EPA’s expenditures for response measures at the site have exceeded $6 million. EPA’s feasibility study (FS) for this site conducted in 2007 identified a range of alternatives for permanent remedial measures with varying cost estimates, and the estimated cost of EPA’s preferred alternative is approximately $6 million.

ACE believes that the B.L. England boiler slag sold to MDC was a valuable material with various industrial applications and, therefore, the sale was not an arrangement for the disposal or treatment of any hazardous substances as would be necessary to constitute a basis for liability under CERCLA. ACE intends to contest any claims to the contrary made by EPA. In a May 2009 decision arising under CERCLA, which did not involve ACE, the U.S. Supreme Court rejected an EPA argument that the sale of a useful product constituted an arrangement for disposal or treatment of hazardous substances. While this decision supports ACE’s position, at this time ACE cannot predict how EPA will proceed with respect to the Franklin Slag Pile site, or what portion, if any, of the Franklin Slag Pile site response costs EPA would seek to recover from ACE. Costs to resolve this matter are not expected to be material and are expensed as incurred.

Peck Iron and Metal Site

EPA informed Pepco in a May 2009 letter that Pepco may be a PRP under CERCLA with respect to the cleanup of the Peck Iron and Metal site in Portsmouth, Virginia, and for costs EPA has incurred in cleaning up the site. The EPA letter states that Peck Iron and Metal purchased, processed, stored and shipped metal scrap from military bases, governmental agencies and businesses and that the Peck Iron and Metal scrap operations resulted in the improper storage and disposal of hazardous substances. EPA bases its allegation that Pepco arranged for disposal or treatment of hazardous substances sent to the site on information provided by former Peck Iron and Metal personnel, who informed EPA that Pepco was a customer at the site. Pepco has advised EPA by letter that its records show no evidence of any sale of scrap metal by Pepco to the site. Even if EPA has such records and such sales did occur, Pepco believes that any such scrap metal sales may be entitled to the recyclable material exemption from CERCLA liability. In September 2011, EPA initiated a remedial investigation/feasibility study (RI/FS) for the site using federal funds. Pepco cannot at this time estimate an amount or range of reasonably possible loss associated with this RI/FS, any remediation activities to be performed at the site or any other costs that EPA might seek to impose on Pepco.

Benning Road Site

Contamination of Lower Anacostia River

In September 2010, PHI received a letter from EPA identifying the Benning Road site as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. A portion of the site was formerly the location of a Pepco Energy Services electric generating facility. That generating facility was deactivated in June 2012 and plant structure demolition was completed in July 2015. The remaining portion of the site consists of a Pepco transmission and distribution service center that remains in operation. The principal contaminants allegedly of concern are polychlorinated biphenyls and polycyclic aromatic hydrocarbons. In December 2011, the U.S. District Court for the District of Columbia approved a consent decree entered into by Pepco and Pepco Energy Services with the District of Columbia Department of Energy and Environment (DOEE) (formerly the District of Columbia Department of the Environment), which requires Pepco and Pepco Energy Services to conduct a RI/FS for the Benning Road site and an approximately 10 to 15 acre portion of the adjacent Anacostia River. The RI/FS will form the basis for the remedial actions for the Benning Road site and for the Anacostia River sediment associated with the site. The consent decree does not obligate Pepco or Pepco Energy Services to pay for or perform any remediation work, but it is anticipated that DOEE will look to Pepco and Pepco Energy Services to assume responsibility for cleanup of any conditions in the river that are determined to be attributable to past activities at the Benning Road site.

The initial remedial investigation field work began in January 2013 and was completed in December 2014. In addition, in conjunction with the power plant demolition activities, Pepco and Pepco Energy Services collected soil samples adjacent to and beneath the concrete basins for the dismantled cooling towers for the generating facility. This sampling showed localized areas of soil contamination associated with the cooling tower basins, and, beginning in the first quarter of 2016, Pepco and Pepco Energy Services expect to implement a plan approved by DOEE to remove contaminated soil in conjunction with the demolition and removal of the concrete basins. On April 30, 2015, Pepco and Pepco Energy Services submitted a draft Remedial Investigation (RI) Report to DOEE. After review, DOEE determined that additional field investigation and data analysis is required to complete the RI process (much of which is beyond the scope of the original DOEE-approved RI work plan). In the meantime, Pepco and Pepco Energy Services will revise the draft RI Report as appropriate to address DOEE’s comments and DOEE will make the draft RI available for public review during the first quarter of 2016. The additional field investigation and data analysis will proceed later in 2016 according to a schedule to be developed by Pepco and Pepco Energy Services and approved by DOEE. Once the additional RI work has been completed, Pepco and Pepco Energy Services will issue a draft “final” RI report for review and comment by DOEE and the public. Pepco and Pepco Energy Services will then proceed with an FS to evaluate possible remedial alternatives. This effort also may include a treatability study to evaluate the effectiveness of potential remedial options. Once the FS has been completed, Pepco and Pepco Energy Services will prepare and submit a draft FS Report for review and comment by DOEE and the public. Thereafter, Pepco and Pepco Energy Services will revise the draft FS Report as appropriate to address comments received and will submit a final FS Report to DOEE.

Upon DOEE’s approval of the final RI and FS Reports, Pepco and Pepco Energy Services will have satisfied their obligations under the consent decree. At that point, DOEE will prepare a Proposed Plan regarding further response actions based on the results of the RI/FS. After considering public comment on the Proposed Plan, DOEE will issue a Record of Decision identifying any further response actions determined to be necessary.

DOEE, Pepco and Pepco Energy Services must submit their next joint status report to the court regarding progress on the RI/FS by May 24, 2016.

PHI, Pepco and Pepco Energy Services have determined that a loss associated with this matter for PHI, Pepco and Pepco Energy Services is probable and have estimated that the costs of remediation are in the range of approximately $9 million to $13 million.

The remediation costs accrued for this matter are included in the table above in the columns entitled “Transmission and Distribution,” “Legacy Generation – Regulated,” and “Legacy Generation – Non-Regulated.”

NPDES Permit Limit Exceedances

Pepco holds a National Pollutant Discharge Elimination System (NPDES) permit issued by EPA with a July 19, 2009 effective date, which authorizes discharges from the Benning Road site, including the Pepco Energy Services generating facility previously located on the site that was deactivated in 2012 and has been demolished. The 2009 permit for the first time imposed numerical limits on the allowable concentration of certain metals in storm water discharged from the site into the Anacostia River as determined by EPA to be necessary to meet the applicable District of Columbia surface water quality standards. The permit contemplated that Pepco would meet these limits over time through the use of best management practices (BMPs). As of December 2012, Pepco completed the implementation of the first two phases of BMPs identified in a plan approved by EPA (consisting principally of installing metal absorbing filters to capture contaminants at storm water inlets, removing stored equipment from areas exposed to the weather, covering and painting exposed metal pipes, and covering and cleaning dumpsters). These measures were effective in reducing metal concentrations in storm water discharges, but were not sufficient to meet all of the numerical limits for metals. Most of the quarterly monitoring results since the issuance of the permit have shown exceedances of the limits for copper and zinc, as well as occasional exceedances for iron and lead.

The NPDES permit was due to expire on June 19, 2014. Pepco submitted a permit renewal application on December 17, 2013. In November 2014, EPA advised Pepco that it will not renew the permit until the Benning Road site has come into compliance with the existing permit limits. The current permit remains in effect pending EPA’s action on the renewal application. In December 2014, Pepco submitted a plan to EPA to implement the third phase of BMPs recommended in the original permit compliance plan with the objective of achieving full compliance with the permit limits for metals by the end of 2015 and Pepco immediately began to implement the additional BMPs in accordance with the plan. On September 1, 2015, Pepco submitted a report to EPA on the status of implementation of the third phase of BMPs. As of that date, Pepco had fully implemented most of the elements of the Phase 3 plan, including installation of upgraded storm water inlet controls (filters and booms), enhanced inspection and maintenance of inlets, removal of materials and equipment from exposure to storm water, and removal of accumulated sediments from the underground storm drains. The sampling results from the third quarter of 2015 showed compliance with all of the permit limits. The sampling results from the fourth quarter of 2015 showed compliance with all but a single permit limit for metals; the concentration of copper was below the daily maximum limit but exceeded the monthly average limit. As confirmed by this latest sampling, because the permit limits are low and site conditions are subject to variation, Pepco has concluded that some form of storm water treatment prior to discharge will be necessary to ensure ongoing compliance with all permit limits and has begun the process of evaluating treatment options. The nature and scope of the necessary treatment system, and the amount of the associated capital expenditures, will not be known until Pepco has completed the evaluation and design process.

Pepco has been engaged in discussions with representatives from EPA and the DOJ regarding permit compliance. On October 30, 2015, EPA filed a Clean Water Act civil enforcement action against Pepco in federal district court. Pepco expects that this enforcement action will be resolved through a consent decree that will (i) establish further requirements to achieve compliance with the permit limits, including the design and installation of an appropriate storm water treatment system as noted above, and (ii) include civil penalties for past noncompliance. The amount of such penalties is not known or estimable at this time and Pepco does not expect the amount of such penalties to have a material adverse effect on PHI’s consolidated financial condition, results of operations or cash flows.

Pepco and EPA are currently in discussions regarding the terms of the contemplated consent decree, and it is anticipated that the parties will finalize the consent decree during the first half of 2016. In response to a joint motion by the parties, the court has extended the deadline for Pepco to answer the complaint to May 16, 2016, to give the parties time to work towards agreement on the terms of a consent decree. The parties contemplate seeking a further extension if necessary to complete their negotiations. Once executed by the parties, the consent decree will be filed with the court for review and approval following a period for public comment.

Potomac River Mineral Oil Release

In January 2011, a coupling failure on a transformer cooler pipe resulted in a release of non-toxic mineral oil at Pepco’s Potomac River substation in Alexandria, Virginia. An overflow of an underground secondary containment reservoir resulted in approximately 4,500 gallons of mineral oil flowing into the Potomac River.

In March 2014, Pepco and DOEE entered into a consent decree to resolve a threatened DOEE enforcement action, the terms of which include a combination of a civil penalty and a Supplemental Environmental Project (SEP) with a total cost to Pepco of $875,000. The consent decree was approved and entered by the District of Columbia Superior Court on April 4, 2014. Pepco has paid the $250,000 civil penalty imposed under the consent decree and, pursuant to the consent decree, has made a one-time donation in the amount of $25,000 to the Northeast Environmental Enforcement Training Fund, Inc., a non-profit organization that funds scholarships for environmental enforcement training. The consent decree confirmed that no further actions are required by Pepco to investigate, assess or remediate impacts to the river from the mineral oil release. To implement the SEP, Pepco has entered into an agreement with Living Classrooms Foundation, Inc., a non-profit educational organization, pursuant to which Pepco will provide $600,000 to fund the design, installation and operation of a trash collection system at a storm water outfall that drains to the Anacostia River. DOEE approved the design for the trash collection system and efforts to secure necessary permits are in progress. Pepco expects that this system will be constructed and placed into operation by the end of 2016, which will satisfy Pepco’s obligations under the consent decree. On September 11, 2015, Pepco and DOEE filed a joint report with the D.C. Superior Court on the status of the trash cage project and other elements of the consent decree. The court accepted that report and scheduled the next status hearing in this matter for September 23, 2016.

The consent decree did not resolve potential claims under federal law for natural resource damages resulting from the mineral oil release. Pepco has engaged in separate discussions with DOEE and the federal resource trustees regarding the settlement of a possible natural resource damages claim under federal law. In July 2013, Pepco submitted a natural resource damage assessment to DOEE and the federal trustees that proposed monetary compensation for such damages in the range of $106,000 to $161,000. By letter dated September 16, 2015, the U.S. Department of Interior, on behalf of the trustees, made a confidential counter-proposal for settlement of the natural resource damage claim. Pepco has engaged in subsequent discussions with the trustees and believes that the parties are close to reaching an agreement to settle the claims. Based on the discussions to date, PHI and Pepco do not believe that the resolution of the natural resource damages claim will have a material adverse effect on their respective financial condition, results of operations or cash flows.

As a result of the mineral oil release, Pepco implemented certain interim operational changes to the secondary containment systems at the facility, which involve pumping accumulated storm water to an above-ground holding tank for off-site disposal. Pepco is continuing to use the above-ground holding tank to manage storm water from the secondary containment system while it evaluates other technical and regulatory options.

The amount accrued for this matter is included in the table above in the column entitled “Transmission and Distribution.”

Metal Bank Site

In the first quarter of 2013, the National Oceanic and Atmospheric Administration (NOAA) contacted Pepco and DPL on behalf of itself and other federal and state trustees to request that Pepco and DPL execute a tolling agreement to facilitate settlement negotiations concerning natural resource damages allegedly caused by releases of hazardous substances, including polychlorinated biphenyls, at the Metal Bank Cottman Avenue Superfund Site located in Philadelphia, Pennsylvania. Pepco and DPL executed a tolling agreement, which has been extended to March 15, 2016, and will continue settlement discussions with the NOAA, the trustees and other PRPs.

The amount accrued for this matter is included in the table above in the column entitled “Transmission and Distribution.”

Brandywine Fly Ash Disposal Site

In February 2013, Pepco received a letter from the Maryland Department of the Environment (MDE) requesting that Pepco investigate the extent of waste on a Pepco right-of-way that traverses the Brandywine fly ash disposal site in Brandywine, Prince George’s County, Maryland, owned by NRG Energy, Inc. (as successor to GenOn MD Ash Management, LLC) (NRG). In July 2013, while reserving its rights and related defenses under a 2000 agreement covering the sale of this site, Pepco indicated its willingness to investigate the extent of, and propose an appropriate closure plan to address, ash on the right-of-way. Pepco submitted a schedule for development of a closure plan to MDE on September 30, 2013 and, by letter dated October 18, 2013, MDE approved the schedule.

PHI and Pepco have determined that a loss associated with this matter for PHI and Pepco is probable and have estimated that the costs for implementation of a closure plan and cap on the site are in the range of approximately $3 million to $6 million. PHI and Pepco believe that the costs incurred in this matter will be recoverable from NRG under the 2000 sale agreement.

The amount accrued for this matter is included in the table above in the column entitled “Transmission and Distribution.”

Virginia Department of Environmental Quality Notice of Violation

On February 3, 2015, the Virginia Department of Environmental Quality (VDEQ) issued a notice of violation (NOV) to DPL in connection with alleged violations of state water control laws and regulations associated with recent construction activities undertaken to replace certain transmission facilities. The NOV informed DPL of information on which VDEQ may rely to institute an administrative or judicial enforcement action, requested a meeting, and stated that DPL may be asked to enter into a consent order to formalize a plan and schedule of corrective action and settle any outstanding issues regarding the matter including the assessment of civil charges. At a February 20, 2015 meeting, VDEQ confirmed that the NOV would be resolved through a consent order, which will require the payment of a penalty, but did not specify the potential penalty amount. DPL will pursue recovery of the restoration costs for this matter from the contractor responsible for the vegetation management activities that gave rise to the alleged violations. PHI and DPL have substantially completed all remediation activities related to this matter and do not believe that the potential penalty to resolve this matter will have a material adverse effect on their respective financial condition, results of operations or cash flows.

Rock Creek Mineral Oil Release

In late August 2015, a Pepco underground transmission line in the District of Columbia suffered a breach, resulting in the release of non-toxic mineral oil surrounding the transmission line into the surrounding soil, and a small amount also reached Rock Creek through a storm drain. Pepco notified regulatory authorities, and Pepco and its spill response contractors placed booms in Rock Creek, blocked the storm drain to prevent the release of mineral oil into the creek and commenced remediation of soil around the transmission line and the Rock Creek shoreline. Pepco estimates that approximately 6,100 gallons of mineral oil were released and that its remediation efforts recovered approximately 80 percent of the amount released. Pepco’s remediation efforts are ongoing under the direction of the DOEE and in collaboration with the National Park Service, the Smithsonian Institution/National Zoo and EPA. Pepco’s investigation presently indicates that the damage to Pepco’s facilities occurred prior to the release of mineral oil when third-party excavators struck the Pepco underground transmission line while installing cable for another utility.

To the extent recovery is available against any party who contributed to this loss, PHI and Pepco will pursue such action. PHI and Pepco continue to investigate the cause of the incident, the parties involved, and legal responsibility under District of Columbia law, but do not believe that the remediation costs to resolve this matter will have a material adverse effect on their respective financial condition, results of operations or cash flows.

PHI’s Cross-Border Energy Lease Investments

PHI held a portfolio of cross-border energy lease investments involving public utility assets located outside of the United States. Each of these investments was comprised of multiple leases and was structured as a sale and leaseback transaction commonly referred to by the IRS as a SILO transaction. During the second and third quarters of 2013, PHI terminated early all of its remaining cross-border energy lease investments.

Since 2005, PHI’s former cross-border energy lease investments have been under examination by the IRS as part of the PHI federal income tax audits. In connection with the audit of PHI’s 2001-2002 income tax returns, the IRS disallowed the depreciation and interest deductions in excess of rental income claimed by PHI for six of the eight lease investments and, in connection with the audits of PHI’s 2003-2005 and 2006-2008 income tax returns, the IRS disallowed such deductions in excess of rental income for all eight of the lease investments. In addition, the IRS has sought to recharacterize each of the leases as a loan transaction in each of the years under audit as to which PHI would be subject to original issue discount income. PHI had disagreed with the IRS’ proposed adjustments to the 2001-2008 income tax returns and filed protests of these findings for each year with the Office of Appeals of the IRS. In November 2010, PHI entered into a settlement agreement with the IRS for the 2001 and 2002 tax years for the purpose of commencing litigation associated with this matter and subsequently filed refund claims in July 2011 for the disallowed tax deductions relating to the leases for these years. In January 2011, as part of this settlement, PHI paid $74 million of additional tax for 2001 and 2002, penalties of $1 million, and $28 million in interest associated with the disallowed deductions. Since the July 2011 refund claims were not approved by the IRS within the statutory six-month period, in January 2012 PHI filed complaints in the U.S. Court of Federal Claims seeking recovery of the tax payment, interest and penalties.

On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States (to which PHI is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. While PHI believed that its tax position with regard to its former cross-border energy lease investments was appropriate, after analyzing the recent U.S. Court of Appeals ruling, PHI determined in the first quarter of 2013 that its tax position with respect to the tax benefits associated with the cross-border energy leases no longer met the more-likely-than-not standard of recognition for accounting purposes. Accordingly, PHI recorded a non-cash after-tax charge of $377 million in the first quarter of 2013 consisting of a charge to reduce the carrying value of the cross-border energy lease investments and a charge to reflect the anticipated additional interest expense related to changes in PHI’s estimated federal and state income tax obligations for the period over which the tax benefits ultimately may be disallowed. PHI had also previously made certain business assumptions regarding foreign investment opportunities available at the end of the full lease terms. During the first quarter of 2013, management believed that its conclusions regarding these business assumptions were no longer supportable, and the tax effects of this change in conclusion were included in the charge. While the IRS could require PHI to pay a penalty of up to 20% of the amount of additional taxes due, PHI believed that it was more likely than not that no such penalty would be incurred, and therefore no amount for any potential penalty had been recorded.

Assuming that the IRS were to be successful in disallowing 100% of the tax benefits associated with these lease investments and recharacterize these lease investments as loans, PHI estimated that, as of March 31, 2013, it would have been obligated to pay approximately $192 million in additional federal taxes (net of the $74 million tax payment described above) and approximately $50 million of interest on the additional federal taxes. These amounts, totaling $242 million, were estimated after consideration of certain tax benefits arising from matters unrelated to the leases that would offset the taxes and interest due, including PHI’s best estimate of the expected resolution of other uncertain and effectively settled tax positions, the carrying back and carrying forward of any existing net operating losses, and the application of certain amounts paid in advance to the IRS. In order to mitigate PHI’s ongoing interest costs associated with the $242 million estimate of additional taxes and interest, PHI made an advanced payment to the IRS of $242 million in the first quarter of 2013. This advanced payment was funded from currently available sources of liquidity and short-term borrowings. A portion of the proceeds from lease terminations effected during the second and third quarters of 2013 was used to repay the short-term borrowings utilized to fund the advanced payment.

On November 18, 2015, PHI entered into the Global Tax Settlement with the IRS and the DOJ to provide for the resolution of the tax treatment of its previously held cross-border energy lease investments structured as SILO transactions. As a result of the Global Tax Settlement, PHI and the DOJ filed stipulations of dismissal regarding the litigation in the U.S. Court of Federal Claims. The Court dismissed the complaint on November 20, 2015. For additional discussion on the Global Tax Settlement with the IRS, see Note (11), “Income Taxes.”

Third Party Guarantees, Indemnifications, and Off-Balance Sheet Arrangements

PHI and certain of its subsidiaries have various financial and performance guarantees and indemnification obligations that they have entered into in the normal course of business to facilitate commercial transactions with third parties as discussed below.

As of December 31, 2015, PHI and its subsidiaries were parties to a variety of agreements pursuant to which they were guarantors. The commitments and obligations were as follows:

	Guarantor
	PHI		Pepco		DPL		ACE		Total
	(millions of dollars)
Guarantees associated with disposal of Conectiv Energy assets (a)	$	13	$	—	$	—	$	—	$	13
Guaranteed lease residual values (b)		3		5		6		5		19
Total	$	16	$	5	$	6	$	5	$	32

(a) Represents guarantees by PHI of Conectiv Energy’s derivative portfolio transferred in connection with the disposition of Conectiv Energy’s wholesale business. The derivative portfolio guarantee is currently $13 million and covers Conectiv Energy’s performance prior to the assignment. The guarantee was terminated in January 2016.

(b) Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $52 million, $9 million of which is a guarantee by PHI, $13 million by Pepco, $16 million by DPL and $14 million by ACE. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.

PHI and certain of its subsidiaries have entered into various indemnification agreements related to purchase and sale agreements and other types of contractual agreements with vendors and other third parties. These indemnification agreements typically cover environmental, tax, litigation and other matters, as well as breaches of representations, warranties and covenants set forth in these agreements. Typically, claims may be made by third parties under these indemnification agreements over various periods of time depending on the nature of the claim. The maximum potential exposure under these indemnification agreements can range from a specified dollar amount to an unlimited amount depending on the nature of the claim and the particular transaction. The total maximum potential amount of future payments under these indemnification agreements is not estimable due to several factors, including uncertainty as to whether or when claims may be made under these indemnities.

Energy Services Performance Contracts

Pepco Energy Services has a diverse portfolio of energy savings services performance contracts that are associated with the installation of energy savings equipment or combined heat and power facilities for federal, state and local government customers. As part of the energy savings contracts, Pepco Energy Services typically guarantees that the equipment or systems it installs will generate a specified amount of energy savings on an annual basis over a multi-year period. As of December 31, 2015 the remaining notional amount of Pepco Energy Services’ energy savings guarantees over the life of the multi-year performance contracts on: (i) completed projects was $221 million, with the longest guarantee having a remaining term of 23 years; and, (ii) projects under construction was $55 million, with the longest guarantee having a term of 19 years after completion of construction. On an annual basis, Pepco Energy Services undertakes a measurement and verification process to determine the amount of energy savings for the year and whether there is any shortfall in the annual energy savings compared to the guaranteed amount.

As of December 31, 2015, Pepco Energy Services had a performance guarantee contract associated with the production at a combined heat and power facility that is under construction totaling $15 million in notional value over 20 years.

Pepco Energy Services recognizes a liability for the value of the estimated energy savings or production shortfalls when it is probable that the guaranteed amounts will not be achieved and the amount is reasonably estimable. As of December 31, 2015, Pepco Energy Services had an accrued liability of $1 million for its energy savings contracts that it established during 2012. There was no significant change in the type of contracts issued during the year ended December 31, 2015 as compared to the year ended December 31, 2014.

Contractual Obligations

Power Purchase Contracts

As of December 31, 2015, Pepco Holdings’ contractual obligations under non-derivative power purchase contracts were $268 million in 2016, $469 million in 2017 to 2018, $472 million in 2019 to 2020 and $993 million thereafter.

Lease Commitments

Rental expense for operating leases was $60 million, $59 million and $54 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Total future minimum operating lease payments for Pepco Holdings as of December 31, 2015 are $52 million in 2016, $48 million in 2017, $47 million in 2018, $34 million in 2019, $37 million in 2020 and $304 million thereafter.

Potomac Electric Power Co [Member]

Commitments and Contingencies

(12) COMMITMENTS AND CONTINGENCIES

General Litigation

From time to time, Pepco is named as a defendant in litigation, usually relating to general liability or auto liability claims that resulted in personal injury or property damage to third parties. Pepco is self-insured against such claims up to a certain self-insured retention amount and maintains insurance coverage against such claims at higher levels, to the extent deemed prudent by management. In addition, Pepco’s contracts with its vendors generally require the vendors to name Pepco as an additional insured for the amount at least equal to Pepco’s self-insured retention. Further, Pepco’s contracts with its vendors require the vendors to indemnify Pepco for various acts and activities that may give rise to claims against Pepco. Loss contingency liabilities for both asserted and unasserted claims are recognized if it is probable that a loss will result from such a claim and if the amounts of the losses can be reasonably estimated. Although the outcome of the claims and proceedings cannot be predicted with any certainty, management believes that there are no existing claims or proceedings that are likely to have a material adverse effect on Pepco’s financial condition, results of operations or cash flows. At December 31, 2015, Pepco had recorded estimated loss contingency liabilities for general litigation totaling approximately $4 million.

Environmental Matters

Pepco is subject to regulation by various federal, regional, state and local authorities with respect to the environmental effects of its operations, including air and water quality control, solid and hazardous waste disposal and limitations on land use. Although penalties assessed for violations of environmental laws and regulations are not recoverable from customers of Pepco, environmental clean-up costs incurred by Pepco generally are included in its cost of service for ratemaking purposes. The total accrued liabilities for the environmental contingencies of Pepco described below at December 31, 2015 are summarized as follows:

	Transmission and Distribution			Legacy Generation - Regulated		Total
	(millions of dollars)
Balance as of January 1	$	16		$	3	$	19
Accruals		4			3		7
Payments		(2	)		—		(2	)
Balance as of December 31		18			6		24
Less amounts in Other Current Liabilities		2			—		2
Amounts in Other Deferred Credits	$	16		$	6	$	22

Peck Iron and Metal Site

The U.S. Environmental Protection Agency (EPA) informed Pepco in a May 2009 letter that Pepco may be a potentially responsible party (PRP) under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA) with respect to the cleanup of the Peck Iron and Metal site in Portsmouth, Virginia, and for costs EPA has incurred in cleaning up the site. The EPA letter states that Peck Iron and Metal purchased, processed, stored and shipped metal scrap from military bases, governmental agencies and businesses and that the Peck Iron and Metal scrap operations resulted in the improper storage and disposal of hazardous substances. EPA bases its allegation that Pepco arranged for disposal or treatment of hazardous substances sent to the site on information provided by former Peck Iron and Metal personnel, who informed EPA that Pepco was a customer at the site. Pepco has advised EPA by letter that its records show no evidence of any sale of scrap metal by Pepco to the site. Even if EPA has such records and such sales did occur, Pepco believes that any such scrap metal sales may be entitled to the recyclable material exemption from CERCLA liability. In September 2011, EPA initiated a remedial investigation/feasibility study (RI/FS) for the site using federal funds. Pepco cannot at this time estimate an amount or range of reasonably possible loss associated with this RI/FS, any remediation activities to be performed at the site or any other costs that EPA might seek to impose on Pepco.

Benning Road Site

Contamination of Lower Anacostia River

In September 2010, PHI received a letter from EPA identifying the Benning Road site as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. A portion of the site was formerly the location of a Pepco Energy Services electric generating facility. That generating facility was deactivated in June 2012 and plant structure demolition was completed in July 2015. The remaining portion of the site consists of a Pepco transmission and distribution service center that remains in operation. The principal contaminants allegedly of concern are polychlorinated biphenyls and polycyclic aromatic hydrocarbons. In December 2011, the U.S. District Court for the District of Columbia approved a consent decree entered into by Pepco and Pepco Energy Services with the District of Columbia Department of Energy and Environment (DOEE) (formerly the District of Columbia Department of the Environment), which requires Pepco and Pepco Energy Services to conduct a RI/FS for the Benning Road site and an approximately 10 to 15 acre portion of the adjacent Anacostia River. The RI/FS will form the basis for the remedial actions for the Benning Road site and for the Anacostia River sediment associated with the site. The consent decree does not obligate Pepco or Pepco Energy Services to pay for or perform any remediation work, but it is anticipated that DOEE will look to Pepco and Pepco Energy Services to assume responsibility for cleanup of any conditions in the river that are determined to be attributable to past activities at the Benning Road site.

The initial remedial investigation field work began in January 2013 and was completed in December 2014. In addition, in conjunction with the power plant demolition activities, Pepco and Pepco Energy Services collected soil samples adjacent to and beneath the concrete basins for the dismantled cooling towers for the generating facility. This sampling showed localized areas of soil contamination associated with the cooling tower basins, and, beginning in the first quarter of 2016, Pepco and Pepco Energy Services expect to implement a plan approved by DOEE to remove contaminated soil in conjunction with the demolition and removal of the concrete basins. On April 30, 2015, Pepco and Pepco Energy Services submitted a draft Remedial Investigation (RI) Report to DOEE. After review, DOEE determined that additional field investigation and data analysis is required to complete the RI process (much of which is beyond the scope of the original DOEE-approved RI work plan). In the meantime, Pepco and Pepco Energy Services will revise the draft RI Report as appropriate to address DOEE’s comments and DOEE will make the draft RI available for public review during the first quarter of 2016. The additional field investigation and data analysis will proceed later in 2016 according to a schedule to be developed by Pepco and Pepco Energy Services and approved by DOEE. Once the additional RI work has been completed, Pepco and Pepco Energy Services will issue a draft “final” RI report for review and comment by DOEE and the public. Pepco and Pepco Energy Services will then proceed with a feasibility study (FS) to evaluate possible remedial alternatives. This effort also may include a treatability study to evaluate the effectiveness of potential remedial options. Once the FS has been completed, Pepco and Pepco Energy Services will prepare and submit a draft FS Report for review and comment by DOEE and the public. Thereafter, Pepco and Pepco Energy Services will revise the draft FS Report as appropriate to address comments received and will submit a final FS Report to DOEE.

Upon DOEE’s approval of the final RI and FS Reports, Pepco and Pepco Energy Services will have satisfied their obligations under the consent decree. At that point, DOEE will prepare a Proposed Plan regarding further response actions based on the results of the RI/FS. After considering public comment on the Proposed Plan, DOEE will issue a Record of Decision identifying any further response actions determined to be necessary.

DOEE, Pepco and Pepco Energy Services must submit their next joint status report to the court regarding progress on the RI/FS by May 24, 2016.

Pepco and Pepco Energy Services have determined that a loss associated with this matter for Pepco and Pepco Energy Services is probable and have estimated that the costs of remediation are in the range of approximately $8 million to $12 million.

The remediation costs accrued for this matter are included in the table above in the columns entitled “Transmission and Distribution” and “Legacy Generation – Regulated.”

NPDES Permit Limit Exceedances

Pepco holds a National Pollutant Discharge Elimination System (NPDES) permit issued by EPA with a July 19, 2009 effective date, which authorizes discharges from the Benning Road site, including the Pepco Energy Services generating facility previously located on the site that was deactivated in 2012 and has been demolished. The 2009 permit for the first time imposed numerical limits on the allowable concentration of certain metals in storm water discharged from the site into the Anacostia River as determined by EPA to be necessary to meet the applicable District of Columbia surface water quality standards. The permit contemplated that Pepco would meet these limits over time through the use of best management practices (BMPs). As of December 2012, Pepco completed the implementation of the first two phases of BMPs identified in a plan approved by EPA (consisting principally of installing metal absorbing filters to capture contaminants at storm water inlets, removing stored equipment from areas exposed to the weather, covering and painting exposed metal pipes, and covering and cleaning dumpsters). These measures were effective in reducing metal concentrations in storm water discharges, but were not sufficient to meet all of the numerical limits for metals. Most of the quarterly monitoring results since the issuance of the permit have shown exceedances of the limits for copper and zinc, as well as occasional exceedances for iron and lead.

The NPDES permit was due to expire on June 19, 2014. Pepco submitted a permit renewal application on December 17, 2013. In November 2014, EPA advised Pepco that it will not renew the permit until the Benning Road site has come into compliance with the existing permit limits. The current permit remains in effect pending EPA’s action on the renewal application. In December 2014, Pepco submitted a plan to EPA to implement the third phase of BMPs recommended in the original permit compliance plan with the objective of achieving full compliance with the permit limits for metals by the end of 2015 and Pepco immediately began to implement the additional BMPs in accordance with the plan. On September 1, 2015, Pepco submitted a report to EPA on the status of implementation of the third phase of BMPs. As of that date, Pepco had fully implemented most of the elements of the Phase 3 plan, including installation of upgraded storm water inlet controls (filters and booms), enhanced inspection and maintenance of inlets, removal of materials and equipment from exposure to storm water, and removal of accumulated sediments from the underground storm drains. The sampling results from the third quarter of 2015 showed compliance with all of the permit limits. The sampling results from the fourth quarter of 2015 showed compliance with all but a single permit limit for metals; the concentration of copper was below the daily maximum limit but exceeded the monthly average limit. As confirmed by this latest sampling, because the permit limits are low and site conditions are subject to variation, Pepco has concluded that some form of storm water treatment prior to discharge will be necessary to ensure ongoing compliance with all permit limits and has begun the process of evaluating treatment options. The nature and scope of the necessary treatment system, and the amount of the associated capital expenditures, will not be known until Pepco has completed the evaluation and design process.

Pepco has been engaged in discussions with representatives from EPA and the DOJ regarding permit compliance. On October 30, 2015, EPA filed a Clean Water Act civil enforcement action against Pepco in federal district court. Pepco expects that this enforcement action will be resolved through a consent decree that will (i) establish further requirements to achieve compliance with the permit limits, including the design and installation of an appropriate storm water treatment system as noted above, and (ii) include civil penalties for past noncompliance. The amount of such penalties is not known or estimable at this time and Pepco does not expect the amount of such penalties to have a material adverse effect on PHI’s consolidated financial condition, results of operations or cash flows.

Pepco and EPA are currently in discussions regarding the terms of the contemplated consent decree, and it is anticipated that the parties will finalize the consent decree during the first half of 2016. In response to a joint motion by the parties, the court has extended the deadline for Pepco to answer the complaint to May 16, 2016, to give the parties time to work towards agreement on the terms of a consent decree. The parties contemplate seeking a further extension if necessary to complete their negotiations. Once executed by the parties, the consent decree will be filed with the court for review and approval following a period for public comment.

Potomac River Mineral Oil Release

In January 2011, a coupling failure on a transformer cooler pipe resulted in a release of non-toxic mineral oil at Pepco’s Potomac River substation in Alexandria, Virginia. An overflow of an underground secondary containment reservoir resulted in approximately 4,500 gallons of mineral oil flowing into the Potomac River.

In March 2014, Pepco and DOEE entered into a consent decree to resolve a threatened DOEE enforcement action, the terms of which include a combination of a civil penalty and a Supplemental Environmental Project (SEP) with a total cost to Pepco of $875,000. The consent decree was approved and entered by the District of Columbia Superior Court on April 4, 2014. Pepco has paid the $250,000 civil penalty imposed under the consent decree and, pursuant to the consent decree, has made a one-time donation in the amount of $25,000 to the Northeast Environmental Enforcement Training Fund, Inc., a non-profit organization that funds scholarships for environmental enforcement training. The consent decree confirmed that no further actions are required by Pepco to investigate, assess or remediate impacts to the river from the mineral oil release. To implement the SEP, Pepco has entered into an agreement with Living Classrooms Foundation, Inc., a non-profit educational organization, pursuant to which Pepco will provide $600,000 to fund the design, installation and operation of a trash collection system at a storm water outfall that drains to the Anacostia River. DOEE approved the design for the trash collection system and efforts to secure necessary permits are in progress. Pepco expects that this system will be constructed and placed into operation by the end of 2016, which will satisfy Pepco’s obligations under the consent decree. On September 11, 2015, Pepco and DOEE filed a joint report with the D.C. Superior Court on the status of the trash cage project and other elements of the consent decree. The court accepted that report and scheduled the next status hearing in this matter for September 23, 2016.

The consent decree did not resolve potential claims under federal law for natural resource damages resulting from the mineral oil release. Pepco has engaged in separate discussions with DOEE and the federal resource trustees regarding the settlement of a possible natural resource damages claim under federal law. In July 2013, Pepco submitted a natural resource damage assessment to DOEE and the federal trustees that proposed monetary compensation for such damages in the range of $106,000 to $161,000. By letter dated September 16, 2015, the U.S. Department of Interior, on behalf of the trustees, made a confidential counter-proposal for settlement of the natural resource damage claim. Pepco has engaged in subsequent discussions with the trustees and believes that the parties are close to reaching an agreement to settle the claims. Based on the discussions to date, PHI and Pepco do not believe that the resolution of the natural resource damages claim will have a material adverse effect on their respective financial condition, results of operations or cash flows.

As a result of the mineral oil release, Pepco implemented certain interim operational changes to the secondary containment systems at the facility, which involve pumping accumulated storm water to an above-ground holding tank for off-site disposal. Pepco is continuing to use the above-ground holding tank to manage storm water from the secondary containment system while it evaluates other technical and regulatory options.

The amount accrued for this matter is included in the table above in the column entitled “Transmission and Distribution.”

Metal Bank Site

In the first quarter of 2013, the National Oceanic and Atmospheric Administration (NOAA) contacted Pepco on behalf of itself and other federal and state trustees to request that Pepco execute a tolling agreement to facilitate settlement negotiations concerning natural resource damages allegedly caused by releases of hazardous substances, including polychlorinated biphenyls, at the Metal Bank Cottman Avenue Superfund Site located in Philadelphia, Pennsylvania. Pepco executed a tolling agreement, which has been extended to March 15, 2016, and will continue settlement discussions with the NOAA, the trustees and other PRPs.

The amount accrued for this matter is included in the table above in the column entitled “Transmission and Distribution.”

Brandywine Fly Ash Disposal Site

In February 2013, Pepco received a letter from the Maryland Department of the Environment (MDE) requesting that Pepco investigate the extent of waste on a Pepco right-of-way that traverses the Brandywine fly ash disposal site in Brandywine, Prince George’s County, Maryland, owned by NRG Energy, Inc. (as successor to GenOn MD Ash Management, LLC) (NRG). In July 2013, while reserving its rights and related defenses under a 2000 agreement covering the sale of this site, Pepco indicated its willingness to investigate the extent of, and propose an appropriate closure plan to address, ash on the right-of-way. Pepco submitted a schedule for development of a closure plan to MDE on September 30, 2013 and, by letter dated October 18, 2013, MDE approved the schedule.

Pepco has determined that a loss associated with this matter for Pepco is probable and has estimated that the costs for implementation of a closure plan and cap on the site are in the range of approximately $3 million to $6 million. Pepco believes that the costs incurred in this matter will be recoverable from NRG under the 2000 sale agreement.

The amount accrued for this matter is included in the table above in the column entitled “Transmission and Distribution.”

Rock Creek Mineral Oil Release

In late August 2015, a Pepco underground transmission line in the District of Columbia suffered a breach, resulting in the release of non-toxic mineral oil surrounding the transmission line into the surrounding soil, and a small amount also reached Rock Creek through a storm drain. Pepco notified regulatory authorities, and Pepco and its spill response contractors placed booms in Rock Creek, blocked the storm drain to prevent the release of mineral oil into the creek and commenced remediation of soil around the transmission line and the Rock Creek shoreline. Pepco estimates that approximately 6,100 gallons of mineral oil were released and that its remediation efforts recovered approximately 80 percent of the amount released. Pepco’s remediation efforts are ongoing under the direction of the DOEE and in collaboration with the National Park Service, the Smithsonian Institution/National Zoo and EPA. Pepco’s investigation presently indicates that the damage to Pepco’s facilities occurred prior to the release of mineral oil when third-party excavators struck the Pepco underground transmission line while installing cable for another utility. To the extent recovery is available against any party who contributed to this loss, Pepco will pursue such action. Pepco continues to investigate the cause of the incident, the parties involved, and legal responsibility under District of Columbia law, but does not believe that the remediation costs to resolve this matter will have a material adverse effect on its financial condition, results of operations or cash flows.

Contractual Obligations

Power Purchase Contracts

As of December 31, 2015, Pepco had no contractual obligations under non-derivative power purchase contracts.

Lease Commitments

Rental expense for operating leases was $7 million, $8 million and $7 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Total future minimum operating lease payments for Pepco as of December 31, 2015 are $7 million in 2016, $6 million in 2017, $5 million in 2018, $4 million in 2019, $3 million in 2020 and $7 million thereafter.

Delmarva Power & Light Co/De [Member]

Commitments and Contingencies

(14) COMMITMENTS AND CONTINGENCIES

General Litigation

From time to time, DPL is named as a defendant in litigation, usually relating to general liability or auto liability claims that resulted in personal injury or property damage to third parties. DPL is self-insured against such claims up to a certain self-insured retention amount and maintains insurance coverage against such claims at higher levels, to the extent deemed prudent by management. In addition, DPL’s contracts with its vendors generally require the vendors to name DPL as an additional insured for the amount at least equal to DPL’s self-insured retention. Further, DPL’s contracts with its vendors require the vendors to indemnify DPL for various acts and activities that may give rise to claims against DPL. Loss contingency liabilities for both asserted and unasserted claims are recognized if it is probable that a loss will result from such a claim and if the amounts of the losses can be reasonably estimated. Although the outcome of the claims and proceedings cannot be predicted with any certainty, management believes that there are no existing claims or proceedings that are likely to have a material adverse effect on DPL’s financial condition, results of operations or cash flows. At December 31, 2015, DPL had recorded estimated loss contingency liabilities for general litigation totaling approximately $3 million.

Environmental Matters

DPL is subject to regulation by various federal, regional, state, and local authorities with respect to the environmental effects of its operations, including air and water quality control, solid and hazardous waste disposal and limitations on land use. Although penalties assessed for violations of environmental laws and regulations are not recoverable from DPL’s customers, environmental clean-up costs incurred by DPL generally are included in its cost of service for ratemaking purposes. The total accrued liabilities for the environmental contingencies of DPL described below at December 31, 2015 are summarized as follows:

	Transmission and Distribution			Legacy Generation - Regulated			Total
	(millions of dollars)
Balance as of January 1	$	1		$	2		$	3
Accruals		3			—			3
Payments		(2	)		(1	)		(3	)
Balance as of December 31		2			1			3
Less amounts in Other Current Liabilities		1			1			2
Amounts in Other Deferred Credits	$	1		$	—		$	1

Metal Bank Site

In the first quarter of 2013, the National Oceanic and Atmospheric Administration (NOAA) contacted DPL on behalf of itself and other federal and state trustees to request that DPL execute a tolling agreement to facilitate settlement negotiations concerning natural resource damages allegedly caused by releases of hazardous substances, including polychlorinated biphenyls, at the Metal Bank Cottman Avenue Superfund Site located in Philadelphia, Pennsylvania. DPL executed a tolling agreement, which has been extended to March 15, 2016, and will continue settlement discussions with the NOAA, the trustees and other potentially responsible parties.

The amount accrued for this matter is included in the table above in the column entitled “Transmission and Distribution.”

Virginia Department of Environmental Quality Notice of Violation

On February 3, 2015, the Virginia Department of Environmental Quality (VDEQ) issued a notice of violation (NOV) to DPL in connection with alleged violations of state water control laws and regulations associated with recent construction activities undertaken to replace certain transmission facilities. The NOV informed DPL of information on which VDEQ may rely to institute an administrative or judicial enforcement action, requested a meeting, and stated that DPL may be asked to enter into a consent order to formalize a plan and schedule of corrective action and settle any outstanding issues regarding the matter including the assessment of civil charges. At a February 20, 2015 meeting, VDEQ confirmed that the NOV would be resolved through a consent order, which will require the payment of a penalty, but did not specify the potential penalty amount. DPL will pursue recovery of the restoration costs for this matter from the contractor responsible for the vegetation management activities that gave rise to the alleged violations. DPL has substantially completed all remediation activities related to this matter and does not believe that the potential penalty to resolve this matter will have a material adverse effect on its financial condition, results of operations or cash flows.

Contractual Obligations

Power Purchase Contracts

As of December 31, 2015, DPL’s contractual obligations under non-derivative power purchase contracts were $64 million in 2016, $127 million in 2017 to 2018, $128 million in 2019 to 2020 and $296 million thereafter.

Lease Commitments

DPL leases an 11.9% interest in the Merrill Creek Reservoir. The lease is an operating lease and payments over the remaining lease term, which ends in 2032, are $75 million in the aggregate. DPL also has long-term leases for certain other facilities and equipment. Total future minimum operating lease payments for DPL, including the Merrill Creek Reservoir lease, as of December 31, 2015, are $13 million in 2016, $12 million in 2017, $16 million in 2018, $6 million in 2019, $9 million in 2020 and $118 million thereafter.

Rental expense for operating leases, including the Merrill Creek Reservoir lease, was $14 million, $14 million and $13 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Atlantic City Electric Co [Member]

Commitments and Contingencies

(13) COMMITMENTS AND CONTINGENCIES

General Litigation

From time to time, ACE is named as a defendant in litigation, usually relating to general liability or auto liability claims that resulted in personal injury or property damage to third parties. ACE is self-insured against such claims up to a certain self-insured retention amount and maintains insurance coverage against such claims at higher levels, to the extent deemed prudent by management. In addition, ACE’s contracts with its vendors generally require the vendors to name ACE as an additional insured for the amount at least equal to ACE’s self-insured retention. Further, ACE’s contracts with its vendors require the vendors to indemnify ACE for various acts and activities that may give rise to claims against ACE. Loss contingency liabilities for both asserted and unasserted claims are recognized if it is probable that a loss will result from such a claim and if the amounts of the losses can be reasonably estimated. Although the outcome of the claims and proceedings cannot be predicted with any certainty, management believes that there are no existing claims or proceedings that are likely to have a material adverse effect on ACE’s financial condition, results of operations or cash flows. At December 31, 2015, ACE had recorded estimated loss contingency liabilities for general litigation totaling approximately $5 million.

Environmental Matters

ACE is subject to regulation by various federal, regional, state and local authorities with respect to the environmental effects of its operations, including air and water quality control, solid and hazardous waste disposal and limitations on land use. Although penalties assessed for violations of environmental laws and regulations are not recoverable from customers of ACE, environmental clean-up costs incurred by ACE generally are included in its cost of service for ratemaking purposes. The total accrued liabilities for the environmental contingencies of ACE described below at December 31, 2015 are summarized as follows:

	Legacy Generation - Regulated
	(millions of dollars)
Balance as of January 1	$	1
Accruals		—
Payments		—
Balance as of December 31		1
Less amounts in Other Current Liabilities		—
Amounts in Other Deferred Credits	$	1

Franklin Slag Pile Site

In November 2008, ACE received a general notice letter from the U.S. Environmental Protection Agency (EPA) concerning the Franklin Slag Pile site in Philadelphia, Pennsylvania, asserting that ACE is a potentially responsible party that may have liability for clean-up costs with respect to the site and for the costs of implementing an EPA-mandated remedy. EPA’s claims are based on ACE’s sale of boiler slag from the B.L. England generating facility, then owned by ACE, to MDC Industries, Inc. (MDC) during the period from June 1978 to May 1983. EPA claims that the boiler slag ACE sold to MDC contained copper and lead, which are hazardous substances under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA), and that the sales transactions may have constituted an arrangement for the disposal or treatment of hazardous substances at the site, which could be a basis for liability under CERCLA. The EPA letter also states that, as of the date of the letter, EPA’s expenditures for response measures at the site have exceeded $6 million. EPA’s feasibility study (FS) for this site conducted in 2007 identified a range of alternatives for permanent remedial measures with varying cost estimates, and the estimated cost of EPA’s preferred alternative is approximately $6 million.

ACE believes that the B.L. England boiler slag sold to MDC was a valuable material with various industrial applications and, therefore, the sale was not an arrangement for the disposal or treatment of any hazardous substances as would be necessary to constitute a basis for liability under CERCLA. ACE intends to contest any claims to the contrary made by EPA. In a May 2009 decision arising under CERCLA, which did not involve ACE, the U.S. Supreme Court rejected an EPA argument that the sale of a useful product constituted an arrangement for disposal or treatment of hazardous substances. While this decision supports ACE’s position, at this time ACE cannot predict how EPA will proceed with respect to the Franklin Slag Pile site, or what portion, if any, of the Franklin Slag Pile site response costs EPA would seek to recover from ACE. Costs to resolve this matter are not expected to be material and are expensed as incurred.

Contractual Obligations

Power Purchase Contracts

As of December 31, 2015, ACE’s contractual obligations under non-derivative power purchase contracts were $203 million in 2016, $341 million in 2017 to 2018, $344 million in 2019 to 2020 and $697 million thereafter.

Lease Commitments

ACE leases certain types of property and equipment for use in its operations. Rental expense for operating leases was $13 million, $12 million and $12 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Total future minimum operating lease payments for ACE as of December 31, 2015 are $8 million in 2016, $8 million 2017, $7 million in 2018, $6 million in 2019, $6 million in 2020 and $30 million thereafter.

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Variable Interest Entities

12 Months Ended

Dec. 31, 2015

Variable Interest Entities

(17) VARIABLE INTEREST ENTITIES

PHI is required to consolidate a VIE in accordance with FASB ASC 810 if PHI or a subsidiary is the primary beneficiary of the VIE. The primary beneficiary of a VIE is typically the entity with both the power to direct activities most significantly impacting economic performance of the VIE and the obligation to absorb losses or receive benefits of the VIE that could potentially be significant to the VIE. PHI performs a qualitative analysis to determine whether a variable interest provides a controlling financial interest in any of the VIEs in which PHI or its subsidiaries have an interest. Set forth below are the relationships with respect to which PHI conducted a VIE analysis as of December 31, 2015:

DPL Renewable Energy Transactions

DPL is subject to Renewable Energy Portfolio Standards (RPS) in the state of Delaware that require it to obtain renewable energy credits (RECs) for energy delivered to its customers. DPL’s costs associated with obtaining RECs to fulfill its RPS obligations are recoverable from its customers by law. As of December 31, 2015, DPL is a party to three land-based wind PPAs in the aggregate amount of 128 MWs, one solar PPA with a 10 MW facility, and a PPA with the Delaware Sustainable Energy Utility (DSEU) to purchase solar renewable energy credits (SRECs). Each of the facilities associated with these PPAs is operational, except for the facilities associated with the PPA with the DSEU, which are expected to be operational within one year. DPL is obligated to purchase energy and RECs in amounts generated and delivered by the wind facilities and SRECs from the solar facility and the DSEU, up to certain amounts (as set forth below) at rates that are primarily fixed under the respective agreements. PHI and DPL have concluded that while VIEs exist under these contracts, consolidation is not required under FASB ASC 810 as DPL is not the primary beneficiary. DPL has not provided financial or other support under these arrangements that it was not previously contractually required to provide during the periods presented, and DPL does not have any intention to provide such additional support.

Because DPL has no equity or debt interest in these renewable energy transactions, the maximum exposure to loss relates primarily to any above-market costs incurred for power, RECs or SRECs. Due to unpredictability in the amount of MWs ultimately purchased under the agreements for purchased renewable energy, RECs and SRECs, PHI and DPL are unable to quantify the maximum exposure to loss, however, the power purchase, REC and SREC costs are recoverable from DPL’s customers through regulated rates.

Wind PPAs

DPL is obligated to purchase energy and RECs from one of the wind facilities through 2024 in amounts not to exceed 50 MWs, from the second wind facility through 2031 in amounts not to exceed 40 MWs, and from the third wind facility through 2031 in amounts not to exceed 38 MWs. DPL’s aggregate purchases under the three wind PPAs totaled $29 million, $31 million and $30 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Solar PPAs

The term of the PPA with the solar facility is through 2030 and DPL is obligated to purchase SRECs in an amount up to 70 percent of the energy output at a fixed price. The DSEU may enter into 20-year contracts with solar facilities to purchase SRECs for resale to DPL. Under the PPA with the DSEU, at December 31, 2015 and 2014, DPL was obligated to purchase SRECs in amounts not to exceed 28 MWs and 19 MWs, respectively, at annually determined auction rates. DPL’s purchases under these solar PPAs totaled $6 million, $6 million and $3 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Fuel Cell Facilities

On October 18, 2011, the DPSC approved a tariff submitted by DPL in accordance with the requirements of the RPS specific to fuel cell facilities totaling 30 MWs to be constructed by a qualified fuel cell provider. The tariff and the RPS establish that DPL acts solely as an agent to collect payments in advance from its distribution customers and remit them to the qualified fuel cell provider for each megawatt hour (MWh) of energy produced by the fuel cell facilities through 2033. The RPS provides for a reduction in DPL’s REC requirements based upon the actual energy output of the facilities. PHI and DPL have concluded that while a VIE exists as a result of this relationship, consolidation is not required under FASB ASC 810 as DPL is not the primary beneficiary. For the years ended December 31, 2015 and 2014, 227,113 and 222,948 MWhs, respectively, were produced from fuel cell facilities placed in service under the tariff. DPL billed $37 million, $36 million and $23 million to distribution customers for the years ended December 31, 2015, 2014 and 2013, respectively.

ACE Power Purchase Agreements

ACE is a party to three PPAs with unaffiliated NUGs totaling 459 MWs. One of the agreements ends in 2016 and the other two end in 2024. PHI and ACE have no equity or debt invested in these entities. In performing its VIE analysis, PHI has been unable to obtain sufficient information to determine whether these three entities were variable interest entities or if ACE was the primary beneficiary. As a result, PHI has applied the scope exemption from the consolidation guidance.

Because ACE has no equity or debt invested in the NUGs, the maximum exposure to loss relates primarily to any above-market costs incurred for power. Due to unpredictability in the pricing for purchased energy under the PPAs, PHI and ACE are unable to quantify the maximum exposure to loss. The power purchase costs are recoverable from ACE’s customers through regulated rates. Purchase activities with the NUGs, including excess power purchases not covered by the PPAs, for the years ended December 31, 2015, 2014 and 2013, were approximately $208 million, $233 million and $221 million, respectively, of which approximately $198 million, $208 million and $206 million, respectively, consisted of power purchases under the PPAs.

ACE Funding

In 2001, ACE established ACE Funding solely for the purpose of securitizing authorized portions of ACE’s recoverable stranded costs through the issuance and sale of Transition Bonds. The proceeds of the sale of each series of Transition Bonds were transferred to ACE in exchange for the transfer by ACE to ACE Funding of the right to collect a non-bypassable Transition Bond Charge (representing revenue ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds and related taxes, expenses and fees) from ACE customers pursuant to bondable stranded costs rate orders issued by the NJBPU in an amount sufficient to fund the principal and interest payments on the Transition Bonds and related taxes, expenses and fees (Bondable Transition Property). The assets of ACE Funding, including the Bondable Transition Property, and the Transition Bond Charges collected from ACE’s customers, are not available to creditors of ACE. The holders of Transition Bonds have recourse only to the assets of ACE Funding. ACE owns 100 percent of the equity of ACE Funding, and PHI and ACE consolidate ACE Funding in their consolidated financial statements as ACE is the primary beneficiary of ACE Funding under the variable interest entity consolidation guidance.

Delmarva Power & Light Co/De [Member]

Variable Interest Entities

(17) VARIABLE INTEREST ENTITIES

DPL is required to consolidate a VIE in accordance with FASB ASC 810 if DPL is the primary beneficiary of the VIE. The primary beneficiary of a VIE is typically the entity with both the power to direct activities most significantly impacting economic performance of the VIE and the obligation to absorb losses or receive benefits of the VIE that could potentially be significant to the VIE. DPL performed a qualitative analysis to determine whether a variable interest provided a controlling financial interest in any of the VIEs in which DPL has an interest at December 31, 2015, as described below.

DPL is subject to Renewable Energy Portfolio Standards (RPS) in the state of Delaware that require it to obtain renewable energy credits (RECs) for energy delivered to its customers. DPL’s costs associated with obtaining RECs to fulfill its RPS obligations are recoverable from its customers by law. As of December 31, 2015, DPL is a party to three land-based wind PPAs in the aggregate amount of 128 MWs, one solar power PPA with a 10 MW facility, and a PPA with the Delaware Sustainable Energy Utility (DSEU) to purchase solar renewable energy credits (SRECs). Each of the facilities associated with these PPAs is operational, except for the facilities associated with the PPA with the DSEU, which are expected to be operational within one year. DPL is obligated to purchase energy and RECs in amounts generated and delivered by the wind facilities and SRECs from the solar facility and the DSEU, up to certain amounts (as set forth below) at rates that are primarily fixed under the respective agreements. DPL has concluded that while VIEs exist under these contracts, consolidation is not required under FASB ASC 810 as DPL is not the primary beneficiary. DPL has not provided financial or other support under these arrangements that it was not previously contractually required to provide during the periods presented, and DPL does not have any intention to provide such additional support.

Because DPL has no equity or debt interest in these renewable energy transactions, the maximum exposure to loss relates primarily to any above-market costs incurred for power, RECs or SRECs. Due to unpredictability in the amount of MWs ultimately purchased under the agreements for purchased renewable energy, RECs and SRECs, DPL is unable to quantify the maximum exposure to loss, however, the power purchase, REC and SREC costs are recoverable from DPL’s customers through regulated rates.

Wind PPAs

DPL is obligated to purchase energy and RECs from one of the wind facilities through 2024 in amounts not to exceed 50 MWs, from the second wind facility through 2031 in amounts not to exceed 40 MWs, and from the third wind facility through 2031 in amounts not to exceed 38 MWs. DPL’s aggregate purchases under the three wind PPAs totaled $29 million, $31 million and $30 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Solar PPAs

The term of the PPA with the solar facility is through 2030 and DPL is obligated to purchase SRECs in an amount up to 70 percent of the energy output at a fixed price. The DSEU may enter into 20-year contracts with solar facilities to purchase SRECs for resale to DPL. Under the PPA with DSEU, at December 31, 2015 and 2014, DPL was obligated to purchase SRECs in amounts not to exceed 28 MWs and 19 MWs, respectively, at annually determined auction rates. DPL’s purchases under these solar agreements totaled $6 million, $6 million and $3 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Fuel Cell Facilities

On October 18, 2011, the DPSC approved a tariff submitted by DPL in accordance with the requirements of the RPS specific to fuel cell facilities totaling 30 MWs to be constructed by a qualified fuel cell provider. The tariff and the RPS establish that DPL acts solely as an agent to collect payments in advance from its distribution customers and remit them to the qualified fuel cell provider for each megawatt hour (MWh) of energy produced by the fuel cell facilities through 2033. The RPS provides for a reduction in DPL’s REC requirements based upon the actual energy output of the facilities. DPL has concluded that while a VIE exists as a result of this relationship, consolidation is not required under FASB ASC 810 as DPL is not the primary beneficiary. For the years ended December 31, 2015 and 2014, 227,113 and 222,948 MWhs, respectively, were produced from fuel cell facilities placed in service under the tariff. DPL billed $37 million, $36 million and $23 million to distribution customers for the years ended December 31, 2015, 2014 and 2013, respectively.

ACE

Management’s Report on Internal Control Over Financial Reporting

The management of Atlantic City Electric Company (ACE) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management of ACE assessed ACE’s internal control over financial reporting as of December 31, 2015 based on criteria established in the Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its assessment, the management of ACE concluded that ACE’s internal control over financial reporting was effective as of December 31, 2015.

Report of Independent Registered Public Accounting Firm

To the Shareholder and Board of Directors of

Atlantic City Electric Company

In our opinion, the consolidated financial statements of Atlantic City Electric Company (a wholly owned subsidiary of Pepco Holdings, Inc.) listed in the accompanying index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Atlantic City Electric Company and its subsidiary at December 31, 2015 and December 31, 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule of Atlantic City Electric Company listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

Atlantic City Electric Co [Member]

Variable Interest Entities

(16) VARIABLE INTEREST ENTITIES

ACE is required to consolidate a VIE in accordance with FASB ASC 810 if ACE or a subsidiary is the primary beneficiary of the VIE. The primary beneficiary of a VIE is typically the entity with both the power to direct activities most significantly impacting economic performance of the VIE and the obligation to absorb losses or receive benefits of the VIE that could potentially be significant to the VIE. ACE performed a qualitative analysis to determine whether a variable interest provided a controlling financial interest in any of the VIE’s in which ACE has an interest at December 31, 2015, as described below.

Power Purchase Agreements

ACE is a party to three PPAs with unaffiliated NUGs totaling 459 megawatts. One of the agreements ends in 2016 and the other two end in 2024. ACE has no equity or debt invested in these entities. In performing its VIE analysis, ACE has been unable to obtain sufficient information to determine whether these three entities were variable interest entities or if ACE was the primary beneficiary. As a result, ACE has applied the scope exemption from the consolidation guidance.

Because ACE has no equity or debt invested in the NUGs, the maximum exposure to loss relates primarily to any above-market costs incurred for power. Due to unpredictability in the pricing for purchased energy under the PPAs, ACE is unable to quantify the maximum exposure to loss. The power purchase costs are recoverable from ACE’s customers through regulated rates. Purchase activities with the NUGs, including excess power purchases not covered by the PPAs, for the years ended December 31, 2015, 2014 and 2013, were approximately $208 million, $233 million and $221 million, respectively, of which approximately $198 million, $208 million and $206 million, respectively, consisted of power purchases under the PPAs.

ACE Funding

In 2001, ACE established ACE Funding solely for the purpose of securitizing authorized portions of ACE’s recoverable stranded costs through the issuance and sale of Transition Bonds. The proceeds of the sale of each series of Transition Bonds were transferred to ACE in exchange for the transfer by ACE to ACE Funding of the right to collect a non-bypassable Transition Bond Charge (which is revenue ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds and related taxes, expenses and fees) from ACE customers pursuant to bondable stranded costs rate orders issued by the NJBPU in an amount sufficient to fund the principal and interest payments on the Transition Bonds and related taxes, expenses and fees (Bondable Transition Property). The assets of ACE Funding, including the Bondable Transition Property, and the Transition Bond Charges collected from ACE’s customers, are not available to creditors of ACE. The holders of Transition Bonds have recourse only to the assets of ACE Funding. ACE owns 100 percent of the equity of ACE Funding, and PHI and ACE consolidate ACE Funding in their consolidated financial statements as ACE is the primary beneficiary of ACE Funding under the variable interest entity consolidation guidance.

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Accumulated Other Comprehensive Loss

12 Months Ended

Dec. 31, 2015

Equity [Abstract]

Accumulated Other Comprehensive Loss

(18) ACCUMULATED OTHER COMPREHENSIVE LOSS

The components of Pepco Holdings’ AOCL relating to continuing and discontinued operations are as follows. For additional information, see the consolidated statements of comprehensive income.

	Year Ended December 31,
	2015			2014			2013
	(millions of dollars)
Balance as of January 1	$	(46	)	$	(34	)	$	(48	)
Treasury Lock
Balance as of January 1		(9	)		(9	)		(10	)
Amount of pre-tax loss reclassified to Interest expense		1			1			1
Income tax expense		—			1			—
Balance as of December 31		(8	)		(9	)		(9	)
Pension and Other Postretirement Benefits
Balance as of January 1		(37	)		(25	)		(32	)
Amount of amortization of net prior service cost and actuarial loss reclassified to Other operation and maintenance expense		6			5			5
Amount of net prior service cost and actuarial gain (loss) arising during the year		9			(25	)		8
Income tax (benefit) expense		6			(8	)		6
Balance as of December 31		(28	)		(37	)		(25	)
Commodity Derivatives
Balance as of January 1		—			—			(6	)
Amount of net pre-tax loss reclassified to Income (loss) from discontinued operations before income tax		—			—			10
Income tax expense		—			—			4
Balance as of December 31		—			—			—
Balance as of December 31	$	(36	)	$	(46	)	$	(34	)

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Quarterly Financial Information

12 Months Ended

Dec. 31, 2015

Quarterly Financial Information

(19) QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

The quarterly data presented below reflect all adjustments necessary in the opinion of management for a fair presentation of the interim results. Quarterly data normally vary seasonally because of temperature variations and differences between summer and winter rates. The totals of the four quarterly basic and diluted earnings per common share amounts may not equal the basic and diluted earnings per common share for the year due to changes in the number of shares of common stock outstanding during the year.

	2015
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(millions of dollars, except per share amounts)
Total Operating Revenue	$	1,371		$	1,140		$	1,362		$	1,150		$	5,023
Total Operating Expenses		1,229			1,001			1,179			941	(b)		4,350
Operating Income		142			139			183			209			673
Other Expenses		(59	)		(59	)		(43	)(a)		(65)			(226)
Income from Continuing Operations Before Income Tax Expense		83			80			140			144			447
Income Tax Expense Related to Continuing Operations		30			27			49			23	(c)		129
Net Income From Continuing Operations		53			53			91			121			318
Income from Discontinued Operations, net of taxes		—			—			—			9	(d)		9
Net Income	$	53		$	53		$	91		$	130		$	327
Basic and Diluted Earnings Per Share of Common Stock:
Earnings Per Share of Common Stock from Continuing Operations	$	0.21		$	0.21		$	0.36		$	0.48		$	1.25
Earnings Per Share of Common Stock from Discontinued Operations	$	—		$	—		$	—		$	0.03		$	0.04
Earnings Per Share of Common Stock	$	0.21		$	0.21		$	0.36		$	0.51		$	1.29
Cash Dividends Per Share of Common Stock	$	0.27		$	0.27		$	0.27		$	0.27		$	1.08

(a) Includes $15 million ($10 million after-tax) increase in fair value of preferred stock derivative.

(b) Includes gains of $46 million ($27 million after-tax) associated with the sale of Pepco non-utility land.

(c) Includes income tax benefit of $47 million associated with the Global Tax Settlement and a tax charge of $7 million to correct prior period errors.

(d) Includes income tax benefit of $9 million associated with the Global Tax Settlement.

	2014
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(millions of dollars, except per share amounts)
Total Operating Revenue (a)	$	1,330		$	1,117		$	1,313		$	1,118		$	4,878
Total Operating Expenses (b)		1,157			966			1,147			1,004	(c)		4,274
Operating Income		173			151			166			114			604
Other Expenses		(52	)		(53	)		(53	)		(66	)		(224	)
Income from Continuing Operations Before Income Tax Expense		121			98			113			48			380
Income Tax Expense Related to Continuing Operations		46			45			34			13			138
Net Income	$	75		$	53		$	79		$	35		$	242
Basic and Diluted Earnings Per Share of Common Stock	$	0.30		$	0.21		$	0.31		$	0.14		$	0.96
Cash Dividends Per Share of Common Stock	$	0.27		$	0.27		$	0.27		$	0.27		$	1.08

(a) During the fourth quarter of 2014, ACE reversed unbilled revenue of $3 million ($2 million after-tax) to correct an error that had overstated operating revenue in the third quarter of 2014.

(b) Includes pre-tax impairment losses of $53 million ($32 million after-tax) and $28 million ($16 million after-tax) in the third and fourth quarters of 2014, respectively, at Pepco Energy Services associated with its combined heat and power thermal generating facilities and operations in Atlantic City.

(c) Includes a charge of $3 million ($2 million after-tax) to correct a prior period error related to the recoverability of certain regulatory assets at ACE.

Potomac Electric Power Co [Member]

Quarterly Financial Information

(14) QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

The quarterly data presented below reflect all adjustments necessary, in the opinion of management, for a fair presentation of the interim results. Quarterly data normally vary seasonally because of temperature variations and differences between summer and winter rates. Therefore, comparisons by quarter within a year are not meaningful.

	2015
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(millions of dollars)
Total Operating Revenue	$	556		$	518		$	612		$	503		$	2,189
Total Operating Expenses		493			435			497			379	(a)		1,804
Operating Income		63			83			115			124			385
Other Expenses		(25	)		(23	)		(23	)		(29	)		(100	)
Income Before Income Tax Expense		38			60			92			95			285
Income Tax Expense		12			18			32			36	(b)		98
Net Income	$	26		$	42		$	60		$	59		$	187

(a) Includes gains of $46 million ($27 million after-tax) associated with the sale of non-utility land.

(b) Includes net income tax benefit of $9 million associated with the Global Tax Settlement, a tax charge of $3 million for an uncertain tax position not related to the Global Tax Settlement and a tax charge of $6 million to correct prior period errors.

	2014
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(millions of dollars)
Total Operating Revenue	$	535		$	508		$	587		$	471		$	2,101
Total Operating Expenses		469			414			462			408			1,753
Operating Income		66			94			125			63			348
Other Expenses		(18	)		(20	)		(20	)		(27	)		(85	)
Income Before Income Tax Expense		48			74			105			36			263
Income Tax Expense		16			28			38			10			92
Net Income	$	32		$	46		$	67		$	26		$	171

Delmarva Power & Light Co/De [Member]

Quarterly Financial Information

(16) QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

The quarterly data presented below reflect all adjustments necessary, in the opinion of management, for a fair presentation of the interim results. Quarterly data normally vary seasonally because of temperature variations and differences between summer and winter rates. Therefore, comparisons by quarter within a year are not meaningful.

	2015
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(millions of dollars)
Total Operating Revenue	$	423		$	275		$	317		$	303		$	1,318
Total Operating Expenses		361			251			285			256			1,153
Operating Income		62			24			32			47			165
Other Expenses		(9	)		(11	)		(8	)		(12	)		(40	)
Income Before Income Tax Expense		53			13			24			35			125
Income Tax Expense		21			5			9			14	(a)		49
Net Income	$	32		$	8		$	15		$	21		$	76

(a) Includes income tax charge of $3 million associated with the Global Tax Settlement.

	2014
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(millions of dollars)
Total Operating Revenue	$	397		$	279		$	309		$	308		$	1,293
Total Operating Expenses		326			239			264			257			1,086
Operating Income		71			40			45			51			207
Other Expenses		(9	)		(8	)		(9	)		(12	)		(38	)
Income Before Income Tax Expense		62			32			36			39			169
Income Tax Expense		25			13			13			14			65
Net Income	$	37		$	19		$	23		$	25		$	104

Atlantic City Electric Co [Member]

Quarterly Financial Information

(15) QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

The quarterly data presented below reflect all adjustments necessary, in the opinion of management, for a fair presentation of the interim results. Quarterly data normally vary seasonally because of temperature variations and differences between summer and winter rates. Therefore, comparisons by quarter within a year are not meaningful.

	2015
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(millions of dollars)
Total Operating Revenue	$	333		$	286		$	387		$	292		$	1,298
Total Operating Expenses		313			254			349			252			1,168
Operating Income		20			32			38			40			130
Other Expenses		(14	)		(15	)		(17	)		(15	)		(61	)
Income Before Income Tax Expense		6			17			21			25			69
Income Tax Expense		2			7			7			15	(a)		31
Net Income	$	4		$	10		$	14		$	10		$	38

(a) Includes income tax charge of $3 million associated with the Global Tax Settlement and a tax charge of $2 million to correct prior period errors.

	2014
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(millions of dollars)
Total Operating Revenue (a)	$	340		$	253		$	347		$	273		$	1,213
Total Operating Expenses		309			228			295			246	(b)		1,078
Operating Income		31			25			52			27			135
Other Expenses		(15	)		(15	)		(15	)		(17	)		(62	)
Income Before Income Tax Expense		16			10			37			10			73
Income Tax Expense		6			4			14			4			28
Net Income	$	10		$	6		$	23		$	6		$	45

(a) During the fourth quarter of 2014, ACE reversed unbilled revenue of $3 million ($2 million after-tax) to correct an error that had overstated operating revenue in the third quarter of 2014.

(b) Includes a charge of $3 million ($2 million after-tax) to correct a prior period error related to the recoverability of certain regulatory assets.

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Discontinued Operations

12 Months Ended

Dec. 31, 2015

Discontinued Operations and Disposal Groups [Abstract]

Discontinued Operations

(20) DISCONTINUED OPERATIONS

PHI’s income (loss) from discontinued operations, net of income taxes, is comprised of the following:

	For the Year Ended December 31,
	2015		2014		2013
	(millions of dollars)
Cross-border energy lease investments	$	9	$	—	$	(327	)
Pepco Energy Services’ retail electric and natural gas supply businesses		—		—		5
Income (loss) from discontinued operations, net of income taxes	$	9	$	—	$	(322	)

Cross-Border Energy Lease Investments

Between 1994 and 2002, PCI entered into cross-border energy lease investments consisting of hydroelectric generation facilities, coal-fired electric generation facilities and natural gas distribution networks located outside of the United States. Each of these lease investments was structured as a sale and leaseback transaction commonly referred to as a SILO transaction. During the second and third quarters of 2013, PHI terminated early all of its interests in the remaining lease investments. PHI received aggregate net cash proceeds from these early terminations of $873 million (net of aggregate termination payments of $2.0 billion used to retire the non-recourse debt associated with the terminated leases) and recorded an aggregate pre-tax loss, including transaction costs, of approximately $3 million ($2 million after-tax), representing the excess of the carrying value of the terminated leases over the net cash proceeds received. As a result, PHI has reported the results of operations of the cross-border energy lease investments as discontinued operations in all periods presented in the accompanying consolidated statements of income (loss).

Operating Results

The operating results for the cross-border energy lease investments are as follows:

	For the Year Ended December 31,
	2015		2014		2013
	(millions of dollars)
Operating revenue from PHI’s cross-border energy lease investments	$	—	$	—	$	7
Non-cash charge to reduce carrying value of PHI’s cross-border energy lease investments		—		—		(373	)
Total operating revenue	$	—	$	—	$	(366	)
Income (loss) from operations of discontinued operations, net of income taxes (a)	$	9	$	—	$	(325	)
Net losses associated with the early termination of the cross-border energy lease investments, net of income taxes		—		—		(2	)
Income (loss) from discontinued operations, net of income taxes	$	9	$	—	$	(327	)

(a) Includes income tax benefit of approximately $9 million and $44 million for the years ended December 31, 2015 and 2013, respectively.

On November 18, 2015, PHI entered into the Global Tax Settlement, as described in Note (11), “Income Taxes.” As a result of the Global Tax Settlement, PHI recorded in the fourth quarter of 2015 a tax benefit of $9 million associated with the cross-border energy lease investments. Substantially all of the tax benefit recorded represents uncertain tax positions that were settled in favor of PHI in the Global Tax Settlement.

On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States (to which PHI is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. As a result of the court’s ruling in this case, PHI determined in the first quarter of 2013 that its tax position with respect to the benefits associated with its cross-border energy leases no longer met the more-likely-than-not standard of recognition for accounting purposes, and PCI recorded after-tax non-cash charges of $323 million in the first quarter of 2013 and $6 million in the second quarter of 2013, consisting of the following components:

• A non-cash pre-tax charge of $373 million ($313 million after-tax) to reduce the carrying value of these cross-border energy lease investments under FASB guidance on leases (ASC 840). This pre-tax charge was originally recorded in the consolidated statements of income (loss) as a reduction in operating revenue and is now reflected in income (loss) from discontinued operations, net of income taxes.

• A non-cash charge of $16 million after-tax to reflect the anticipated additional net interest expense under FASB guidance for income taxes (ASC 740) related to estimated federal and state income tax obligations for the period over which the tax benefits may be disallowed. This after-tax charge was originally recorded in the consolidated statements of income (loss) as an increase in income tax expense and is now reflected in income (loss) from discontinued operations, net of income taxes. The after-tax interest charge for PHI on a consolidated basis was $70 million and this amount was allocated to each member of PHI’s consolidated group as if each member was a separate taxpayer, resulting in the recognition of a $12 million interest benefit for the Power Delivery segment, and interest expense of $16 million for PCI and $66 million for Corporate and Other, respectively.

PHI had also previously made certain business assumptions regarding foreign investment opportunities available at the end of the full lease terms. In view of the change in PHI’s tax position with respect to the tax benefits associated with the cross-border energy lease investments and PHI’s resulting decision to pursue the early termination of these investments, management concluded in the first quarter of 2013 that these business assumptions were no longer supportable and the tax effects of this conclusion were reflected in the after-tax charge of $313 million described above.

PHI accrued no penalties associated with its re-assessment of the likely outcome of tax positions associated with the cross-border energy lease investments. No penalties were incurred by PHI in connection with the Global Tax Settlement.

For additional information concerning these cross-border energy lease investments, see Note (16), “Commitments and Contingencies – PHI’s Cross-Border Energy Lease Investments.”

Retail Electric and Natural Gas Supply Businesses of Pepco Energy Services

On March 21, 2013, Pepco Energy Services entered into an agreement whereby a third party assumed all the rights and obligations of the remaining natural gas supply customer contracts, and the associated supply obligations, inventory and derivative contracts. The transaction was completed on April 1, 2013. In addition, in the second quarter of 2013, Pepco Energy Services completed the wind-down of its retail electric supply business by terminating its remaining customer supply and wholesale purchase obligations beyond June 30, 2013. As a result, PHI has reported the results of operations of Pepco Energy Services’ retail electric and natural gas supply businesses as discontinued operations in all periods presented in the accompanying consolidated statements of income (loss).

Operating Results

The operating results for the retail electric and natural gas supply businesses of Pepco Energy Services are as follows:

	For the Year Ended December 31,
	2015		2014		2013
	(millions of dollars)
Operating revenue	$	—	$	—	$	84
Income from operations of discontinued operations, net of income taxes	$	—	$	—	$	4
Net gains associated with accelerated disposition of retail electric and natural gas contracts, net of income taxes		—		—		1
Income from discontinued operations, net of income taxes (a)	$	—	$	—	$	5

(a) Includes income tax expense of approximately $3 million for the year ended December 31, 2013.

Derivative Instruments and Hedging Activities

Derivatives were used by the retail electric and natural gas supply businesses of Pepco Energy Services to hedge commodity price risk. There were no outstanding forward contracts or derivative positions for Pepco Energy Services as of December 31, 2015, 2014 and 2013.

Derivatives Designated as Hedging Instruments

At December 31, 2012, the cumulative net pre-tax loss related to effective cash flow hedges of the retail electric and natural gas supply businesses of Pepco Energy Services included in AOCL was $10 million ($6 million after-tax). With the assumption by a third party, on April 1, 2013, of all the rights and obligations of the derivative contracts associated with the retail natural gas supply business, PHI determined that the hedged forecasted purchases of supply for retail natural gas customers were probable not to occur. Accordingly, during the first quarter of 2013, PHI recognized $4 million of pre-tax unrealized derivative losses ($2 million after-tax) that were previously included in AOCL as cash flow hedges. The remaining pre-tax loss of $6 million included in AOCL was reclassified into income on completion of the wind-down of the retail electric business in the second quarter of 2013.

Other Derivative Activity

The retail electric and natural gas supply businesses of Pepco Energy Services held certain derivatives that were not in hedge accounting relationships and were not designated as normal purchases or normal sales. These derivatives were recorded at fair value on the balance sheet with the gain or loss for changes in fair value recorded through Income (loss) from discontinued operations, net of income taxes.

For the years ended December 31, 2015, 2014, and 2013, the amount of the derivative gain (loss) for the retail electric and natural gas supply businesses of Pepco Energy Services recognized in Income (loss) from discontinued operations, net of income taxes is provided in the table below:

	For the Year Ended December 31,
	2015		2014		2013
	(millions of dollars)
Reclassification of mark-to-market to realized on settlement of contracts	$	—	$	—	$	10
Unrealized mark-to-market loss		—		—		—
Total net gain	$	—	$	—	$	10

As of December 31, 2015, 2014 and 2013, the retail electric and natural gas supply businesses of Pepco Energy Services had no outstanding commodity forward contracts or derivative positions.

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Related Party Transactions

12 Months Ended

Dec. 31, 2015

Potomac Electric Power Co [Member]

Related Party Transactions

(13) RELATED PARTY TRANSACTIONS

PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries, including Pepco. The cost of these services is allocated in accordance with cost allocation methodologies set forth in the service agreement using a variety of factors, including the subsidiaries’ share of employees, operating expenses, assets and other cost methods. These intercompany transactions are eliminated by PHI in consolidation and no profit results from these transactions at PHI. PHI Service Company costs directly charged or allocated to Pepco for the years ended December 31, 2015, 2014 and 2013 were approximately $240 million, $220 million and $209 million, respectively.

Pepco Energy Services performs utility maintenance services and high voltage underground transmission cabling, including services that are treated as capital costs, for Pepco. Amounts charged to Pepco by Pepco Energy Services for the years ended December 31, 2015, 2014 and 2013 were approximately $26 million, $30 million and $20 million, respectively.

As of December 31, 2015 and 2014, Pepco had the following balances on its balance sheets due to related parties:

	2015			2014
	(millions of dollars)
Payable to Related Party (current) (a)
PHI Service Company	$	(25	)	$	(27	)
Pepco Energy Services (b)		(4	)		(2	)
Other		(1	)		(1	)
Total	$	(30	)	$	(30	)

(a) Included in Accounts payable due to associated companies.

(b) Pepco bills customers on behalf of Pepco Energy Services where Pepco Energy Services has performed work for certain government agencies under a General Services Administration area-wide agreement. Amount also includes charges for utility work performed by Pepco Energy Services on behalf of Pepco.

Delmarva Power & Light Co/De [Member]

Related Party Transactions

(15) RELATED PARTY TRANSACTIONS

PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries, including DPL. The cost of these services is allocated in accordance with cost allocation methodologies set forth in the service agreement using a variety of factors, including the subsidiaries’ share of employees, operating expenses, assets and other cost methods. These intercompany transactions are eliminated by PHI in consolidation and no profit results from these transactions at PHI. PHI Service Company costs directly charged or allocated to DPL for the years ended December 31, 2015, 2014 and 2013 were $179 million, $163 million and $154 million, respectively.

Pepco Energy Services, Inc. and its subsidiaries (Pepco Energy Services) performs high voltage underground transmission cabling, including services that are treated as capital costs, for DPL. Amounts charged to DPL by Pepco Energy Services for the years ended December 31, 2015, 2014 and 2013 were approximately $3 million, zero and zero, respectively.

In addition to the PHI Service Company charges described above, DPL’s financial statements include the following related party transactions in its statements of income:

	For the Year Ended December 31,
	2015		2014		2013
	(millions of dollars)
Intercompany lease transactions (a)	$	4	$	5	$	4

(a) Included in Electric revenue.

As of December 31, 2015 and 2014, DPL had the following balances on its balance sheets due to related parties:

	2015			2014
	(millions of dollars)
Payable to Related Party (current) (a)
PHI Service Company	$	(19	)	$	(18	)
Other		(1	)		1
Total	$	(20	)	$	(17	)

(a) Included in Accounts payable due to associated companies.

Atlantic City Electric Co [Member]

Related Party Transactions

(14) RELATED PARTY TRANSACTIONS

PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries, including ACE. The cost of these services is allocated in accordance with cost allocation methodologies set forth in the service agreement using a variety of factors, including the subsidiaries’ share of employees, operating expenses, assets and other cost methods. These intercompany transactions are eliminated by PHI in consolidation and no profit results from these transactions at PHI. PHI Service Company costs directly charged or allocated to ACE for the years ended December 31, 2015, 2014 and 2013 were $143 million, $124 million and $115 million, respectively.

In addition to the PHI Service Company charges described above, ACE’s consolidated financial statements include the following related party transactions in its consolidated statements of income:

	For the Year Ended December 31,
	2015			2014			2013
	(millions of dollars)
Meter reading services provided by Millennium Account Services LLC (an ACE affiliate) (a)	$	(4	)	$	(4	)	$	(4	)
Intercompany lease transactions (a)		(1	)		(1	)		(1	)
Intercompany use revenue (b)		1			2			3

(a) Included in Other operation and maintenance expense.

(b) Included in Operating revenue.

As of December 31, 2015 and 2014, ACE had the following balances on its consolidated balance sheets due to related parties:

	2015			2014
	(millions of dollars)
Payable to Related Party (current) (a)
PHI Service Company	$	(15	)	$	(14	)
Other		(1	)		(1	)
Total	$	(16	)	$	(15	)

(a) Included in Accounts payable due to associated companies.

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Schedule I

12 Months Ended

Dec. 31, 2015

Condensed Financial Information of Parent Company Only Disclosure [Abstract]

Schedule I

Schedule I, Condensed Financial Information of Parent Company is submitted below.

PEPCO HOLDINGS, INC. (Parent Company)

STATEMENTS OF INCOME (LOSS)

	For the Year Ended December 31,
	2015			2014			2013
	(millions of dollars, except share data)
Operating Revenue	$	—		$	—		$	—
Operating Expenses
Other operation and maintenance		20			31			1
Total operating expenses		20			31			1
Operating Loss		(20	)		(31	)		(1	)
Other Income (Expenses)
Interest expense		(47	)		(43	)		(42	)
Income from equity investments		312			291			204
Other income		15			—			—
Total other income		280			248			162
Income from Continuing Operations Before Income Tax		260			217			161
Income Tax (Benefit) Expense Related to Continuing Operations		(58	)		(25	)		51
Net Income from Continuing Operations		318			242			110
Income (Loss) from Discontinued Operations, net of Income Taxes		9			—			(322	)
Net Income (Loss)	$	327		$	242		$	(212	)
Comprehensive Income (Loss)	$	337		$	230		$	(198	)
Earnings Per Share
Basic earnings per share of common stock from Continuing Operations	$	1.25		$	0.96		$	0.45
Basic earnings (loss) per share of common stock from Discontinued Operations		0.04			—			(1.31	)
Basic earnings (loss) per share of common stock	$	1.29		$	0.96		$	(0.86	)
Diluted earnings per share of common stock from Continuing Operations	$	1.25		$	0.96		$	0.45
Diluted earnings (loss) per share of common stock from Discontinued Operations		0.04			—			(1.31	)
Diluted earnings (loss) per share of common stock	$	1.29		$	0.96		$	(0.86	)

The accompanying Notes are an integral part of these Financial Statements.

PEPCO HOLDINGS, INC. (Parent Company)

BALANCE SHEETS

	As of December 31,
	2015			2014
	(millions of dollars, except share data)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	—		$	65
Prepayments of income taxes		171			152
Accounts receivable and other		18			9
Total Current Assets		189			226
INVESTMENTS AND OTHER ASSETS
Goodwill		1,398			1,398
Investment in consolidated companies		4,636			4,256
Other		127			82
Total Investments and Other Assets		6,161			5,736
TOTAL ASSETS	$	6,350		$	5,962
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Short-term debt	$	784		$	287
Current portion of long-term debt		190			250
Interest and taxes accrued		10			9
Accounts payable due to associated companies		8			13
Total Current Liabilities		992			559
DEFERRED CREDITS
Notes payable due to subsidiary companies		498			494
Liabilities and accrued interest related to uncertain tax positions		—			4
Total Deferred Credits		498			498
LONG-TERM DEBT		264			454
COMMITMENTS AND CONTINGENCIES (NOTE 4)
PREFERRED STOCK
Series A preferred stock, $.01 par value – 18,000 shares authorized, 18,000 and 12,600 shares outstanding, respectively		183			129
EQUITY
Common stock, $.01 par value – 400,000,000 shares authorized, 254,289,261 and 252,728,684 shares outstanding, respectively		3			3
Premium on stock and other capital contributions		3,829			3,800
Accumulated other comprehensive loss		(36	)		(46	)
Retained earnings		617			565
Total Equity		4,413			4,322
TOTAL LIABILITIES AND EQUITY	$	6,350		$	5,962

The accompanying Notes are an integral part of these Financial Statements.

PEPCO HOLDINGS, INC. (Parent Company)

STATEMENTS OF CASH FLOWS

	For the Year Ended December 31,
	2015			2014			2013
	(millions of dollars)
OPERATING ACTIVITIES
Net income (loss)	$	327		$	242		$	(212	)
(Income) loss from discontinued operations, net of income taxes		(9	)		—			322
Adjustments to reconcile net income to net cash from operating activities:
Distributions from related parties less than earnings		(74	)		(149	)		(127	)
Deferred income taxes		(33	)		(5	)		(7	)
Increase in fair value of preferred stock derivative		(15	)		—			—
Other		13			18			—
Changes in:
Prepaid and other		6			13			2
Accounts payable		(1	)		1			6
Interest and taxes		(23	)		—			(141	)
Other assets and liabilities		(22	)		1			3
Net Cash From (Used By) Operating Activities		169			121			(154	)
FINANCING ACTIVITIES
Dividends paid on common stock		(275	)		(272	)		(270	)
Common stock issued for the Direct Stock Purchase and Dividend Reinvestment Plan and employee-related compensation		18			34			50
Issuances of common stock		—			—			324
Issuances of Series A preferred stock		54			126			—
Capital contributions to subsidiaries, net		(282	)		(210	)		(250	)
Increase in notes payable due to associated companies		4			3			491
Reacquisitions of long-term debt		(250	)		—			—
Issuances (repayments) of short-term debt, net		197			263			(240	)
Borrowings under term loans		300			—			250
Repayments of term loans		—			—			(450	)
Costs of issuances		—			—			(13	)
Net Cash Used By Financing Activities		(234	)		(56	)		(108	)
Net (Decrease) Increase In Cash and Cash Equivalents		(65	)		65			(262	)
Cash and Cash Equivalents at Beginning of Year		65			—			262
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	—		$	65		$	—

The accompanying Notes are an integral part of these Financial Statements.

NOTES TO FINANCIAL INFORMATION

(1) BASIS OF PRESENTATION

Pepco Holdings, Inc. (Pepco Holdings or PHI) is a holding company and conducts substantially all of its business operations through its subsidiaries. These condensed financial statements and related footnotes have been prepared in accordance with Rule 12-04, Schedule I of Regulation S-X. These statements should be read in conjunction with the consolidated financial statements and notes thereto of Pepco Holdings included in Part II, Item 8 of this Form 10-K.

Pepco Holdings owns 100% of the common stock of all its significant subsidiaries.

(2) NEWLY ADOPTED ACCOUNTING STANDARDS

Presentation of Debt Issuance Costs (Accounting Standards Codification (ASC) 835)

In April 2015, the Financial Accounting Standards Board issued new guidance for the presentation of debt issuance costs on the balance sheet. Debt issuance costs are currently required to be presented on the balance sheet as assets. However, under the new requirements, these debt issuance costs will be offset against the debt to which the costs relate. The new requirements are effective for PHI beginning January 1, 2016, and are required to be implemented on a retrospective basis for all periods presented; however, early adoption is permitted. PHI has elected to early adopt the new guidance in the fourth quarter of 2015. The table below illustrates the effects of the retrospective application on reported balances in PHI’s balance sheet as of December 31, 2014.

	December 31, 2014 As Filed		Reclassification ASC 835			December 31, 2014 As Adjusted
	(millions of dollars)
Other (within investments and other assets)	$	84	$	(2	)	$	82
Long-term debt		456		(2	)		454

(3) DEBT

For information concerning Pepco Holdings’ long-term debt obligations, see Note (10), “Debt,” to the consolidated financial statements of Pepco Holdings.

(4) COMMITMENTS AND CONTINGENCIES

For information concerning Pepco Holdings’ material contingencies and guarantees, see Note (16), “Commitments and Contingencies” to the consolidated financial statements of Pepco Holdings.

Pepco Holdings guarantees the obligations of its wholly owned subsidiary, Pepco Energy Services, Inc. and its subsidiaries (Pepco Energy Services), under certain contracts in its energy savings performance contracting businesses and underground transmission and distribution construction business. At December 31, 2015, Pepco Holdings’ guarantees of Pepco Energy Services’ obligations under these contracts totaled $269 million. PHI also guarantees the obligations of Pepco Energy Services under surety bonds obtained by Pepco Energy Services for construction projects in these businesses. These guarantees totaled $177 million at December 31, 2015.

In addition, Pepco Holdings guarantees certain obligations of Potomac Electric Power Company (Pepco), Delmarva Power & Light Company (DPL), and Atlantic City Electric Company (ACE) under surety bonds obtained by these subsidiaries, for construction projects and self-insured workers compensation matters. These guarantees totaled $56 million at December 31, 2015.

Pepco Holdings, pursuant to an intercompany guarantee agreement with Potomac Capital Investment Corporation (PCI), guarantees certain intercompany obligations of PCI to its subsidiaries. This guarantee totaled $725 million at December 31, 2015.

(5) INVESTMENT IN CONSOLIDATED COMPANIES

Pepco Holdings’ majority owned subsidiaries are recorded using the equity method of accounting. A breakout of the balance in Investment in consolidated companies is as follows:

	2015		2014
	(millions of dollars)
Conectiv, LLC (a)	$	2,198	$	1,984
Potomac Electric Power Company		2,240		2,087
Potomac Capital Investment Corporation		40		30
Pepco Energy Services, Inc.		155		153
PHI Service Company		3		2
Total investment in consolidated companies	$	4,636	$	4,256

(a) Conectiv LLC, is the parent company of Delmarva Power & Light Company and Atlantic City Electric Company.

(6) DISCONTINUED OPERATIONS

During 2015, the income from discontinued operations, net of income taxes, resulted from the Global Tax Settlement reached with the Internal Revenue Service which resolves tax matters related to PHI’s cross-border energy lease investments and is discussed further in Note (11), “Income Taxes” to the consolidated financial statements of Pepco Holdings.

During 2014, there was no activity related to PHI’s discontinued operations.

During 2013, PHI completed the termination of its interest in its cross-border energy lease investments and, as a result, these investments have been accounted for as discontinued operations.

In December 2009, PHI announced the wind-down of the retail energy supply component of the Pepco Energy Services business which was comprised of the retail electric and natural gas supply businesses. In 2013, Pepco Energy Services completed the wind-down and, accordingly, the operations of Pepco Energy Services’ retail electric and natural gas supply businesses have been classified as discontinued operations.

(7) RELATED PARTY TRANSACTIONS

As of December 31, 2015 and 2014, PHI had the following balances on its balance sheets due (to) from related parties:

	2015			2014
	(millions of dollars)
(Payable to) Receivable from Related Party (current) (a)
Conectiv Communications, Inc.	$	(4	)	$	(4	)
PHI Service Company		(4	)		(10	)
Other		—			1
Total	$	(8	)	$	(13	)
Payable to Related Party (non-current) (b)
Potomac Capital Investment Corporation	$	(498	)	$	(494	)
Money Pool Balance (included in cash and cash equivalents)	$	—		$	65

(a) Included in Accounts payable due to associated companies.

(b) Included in Notes payable due to subsidiary companies.

(8) DIVIDEND RESTRICTIONS

PHI, on a stand-alone basis, generates no operating income of its own. Accordingly, its ability to pay dividends to its shareholders depends on dividends received from its subsidiaries. In addition to their future financial performance, the ability of PHI’s direct and indirect subsidiaries to pay dividends is subject to limits imposed by: (i) state corporate laws, which impose limitations on the funds that can be used to pay dividends and, in the case of ACE, the regulatory requirement that it obtain the prior approval of the New Jersey Board of Public Utilities before dividends can be paid if its equity as a percent of its total capitalization, excluding securitization debt, falls below 30%; (ii) the prior rights of holders of mortgage bonds and other long-term debt issued by the subsidiaries, and any other restrictions imposed in connection with the incurrence of liabilities; and (iii) certain provisions of ACE’s charter that impose restrictions on payment of common stock dividends for the benefit of preferred stockholders. Pepco, DPL and ACE have no shares of preferred stock outstanding at December 31, 2015. Currently, the capitalization ratio limitation to which ACE is subject and the restriction in the ACE charter do not limit ACE’s ability to pay common stock dividends. As further described in Note (10), “Debt,” to the consolidated financial statements of Pepco Holdings, PHI, Pepco, DPL and ACE have restrictions on total indebtedness in relation to total capitalization under the credit facility.

PHI had approximately $617 million and $565 million of retained earnings free of restrictions at December 31, 2015 and 2014, respectively. These amounts represent the total retained earnings balances at those dates. The amount of restricted net assets for PHI’s consolidated subsidiaries at December 31, 2015 is $2,633 million.

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Schedule II

12 Months Ended

Dec. 31, 2015

Schedule II

Schedule II, Valuation and Qualifying Accounts, for each registrant is submitted below.

Pepco Holdings, Inc.

Col. A	Col. B		Col. C				Col. D			Col. E
			Additions
Description	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts (a)		Deductions(b)			Balance at End of Period
			(millions of dollars)
Year Ended December 31, 2015 Allowance for uncollectible accounts - customer and other accounts receivable	$	40	$	59	$	5	$	(48	)	$	56
Year Ended December 31, 2014 Allowance for uncollectible accounts - customer and other accounts receivable	$	38	$	46	$	9	$	(53	)	$	40
Year Ended December 31, 2013 Allowance for uncollectible accounts - customer and other accounts receivable	$	34	$	37	$	5	$	(38	)	$	38

(a) Collection of accounts previously written off.

(b) Uncollectible accounts written off.

Potomac Electric Power Co [Member]

Schedule II

Potomac Electric Power Company

Col. A	Col. B		Col. C				Col. D			Col. E
			Additions
Description	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts (a)		Deductions(b)			Balance at End of Period
			(millions of dollars)
Year Ended December 31, 2015 Allowance for uncollectible accounts - customer and other accounts receivable	$	16	$	20	$	1	$	(20	)	$	17
Year Ended December 31, 2014 Allowance for uncollectible accounts - customer and other accounts receivable	$	16	$	17	$	2	$	(19	)	$	16
Year Ended December 31, 2013 Allowance for uncollectible accounts - customer and other accounts receivable	$	13	$	15	$	1	$	(13	)	$	16

(a) Collection of accounts previously written off.

(b) Uncollectible accounts written off.

Delmarva Power & Light Co/De [Member]

Schedule II

Delmarva Power & Light Company

Col. A	Col. B		Col. C				Col. D			Col. E
			Additions
Description	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts (a)		Deductions(b)			Balance at End of Period
	(millions of dollars)
Year Ended December 31, 2015 Allowance for uncollectible accounts - customer and other accounts receivable	$	11	$	20	$	2	$	(16	)	$	17
Year Ended December 31, 2014 Allowance for uncollectible accounts - customer and other accounts receivable	$	12	$	13	$	4	$	(18	)	$	11
Year Ended December 31, 2013 Allowance for uncollectible accounts - customer and other accounts receivable	$	9	$	11	$	1	$	(9	)	$	12

(a) Collection of accounts previously written off.

(b) Uncollectible accounts written off.

Atlantic City Electric Co [Member]

Schedule II

Atlantic City Electric Company

Col. A	Col. B		Col. C				Col. D			Col. E
			Additions
Description	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts (a)		Deductions(b)			Balance at End of Period
	(millions of dollars)
Year Ended December 31, 2015 Allowance for uncollectible accounts - customer and other accounts receivable	$	9	$	18	$	2	$	(12	)	$	17
Year Ended December 31, 2014 Allowance for uncollectible accounts - customer and other accounts receivable	$	10	$	12	$	3	$	(16	)	$	9
Year Ended December 31, 2013 Allowance for uncollectible accounts - customer and other accounts receivable	$	11	$	11	$	3	$	(15	)	$	10

(a) Collection of accounts previously written off.

(b) Uncollectible accounts written off.

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Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2015

Consolidation Policy

Consolidation Policy

The accompanying consolidated financial statements include the accounts of Pepco Holdings and its wholly owned subsidiaries. All material intercompany balances and transactions between subsidiaries have been eliminated. Pepco Holdings uses the equity method to report investments, corporate joint ventures, partnerships, and affiliated companies in which it holds an interest and can exercise significant influence over the operations and policies of the entity. Certain transmission and other facilities currently held are consolidated in proportion to PHI’s percentage interest in the facility.

Consolidation of Variable Interest Entities

Consolidation of Variable Interest Entities

PHI assesses its contractual arrangements with variable interest entities (VIEs) to determine whether it is the primary beneficiary and thereby has to consolidate the entities in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 810. The guidance addresses conditions under which an entity should be consolidated based upon variable interests rather than voting interests. See Note (17), “Variable Interest Entities,” for additional information.

Use of Estimates

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the consolidated financial statements and accompanying notes. Although Pepco Holdings believes that its estimates and assumptions are reasonable, they are based upon information available to management at the time the estimates are made. Actual results may differ significantly from these estimates.

Significant matters that involve the use of estimates include the assessment of contingencies, the calculation of future cash flows and fair value amounts for use in asset and goodwill impairment calculations, fair value calculations for derivative instruments, pension and other postretirement benefit assumptions, the assessment of the adequacy of the allowance for uncollectible accounts, the assessment of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of unbilled revenue, recognition of changes in network service transmission rates for prior service year costs, accrual of loss contingency liabilities for general litigation and auto and other liability claims, accrual of interest related to income taxes, the recognition of lease income and income tax benefits for investments in finance leases held in trust associated with PHI’s former cross-border energy lease investments (see Note (20), “Discontinued Operations – Cross-Border Energy Lease Investments”), and income tax provisions and reserves. Additionally, PHI is subject to legal, regulatory and other proceedings and claims that arise in the ordinary course of its business. PHI records an estimated liability for these proceedings and claims when it is probable that a loss has been incurred and the loss is reasonably estimable.

Revenue Recognition

Revenue Recognition

Regulated Revenue

Power Delivery recognizes revenue upon distribution of electricity and natural gas to its customers, including unbilled revenue for services rendered but not yet billed. PHI’s unbilled revenue was $139 million and $172 million as of December 31, 2015 and 2014, respectively, and these amounts are included in Accounts receivable. PHI’s utility subsidiaries calculate unbilled revenue using an output-based methodology. This methodology is based on the supply of electricity or natural gas intended for distribution to customers. The unbilled revenue process requires management to make assumptions and judgments about input factors such as customer sales mix, temperature and estimated line losses (estimates of electricity and natural gas expected to be lost in the process of its transmission and distribution to customers). The assumptions and judgments are inherently uncertain and susceptible to change from period to period, and if the actual results differ from the projected results, the impact could be material.

Taxes related to the consumption of electricity and natural gas by the utility customers, such as fuel, energy, or other similar taxes, are components of the tariff rates charged by PHI’s utility subsidiaries and, as such, are billed to customers and recorded in Operating revenue. Accruals for the remittance of these taxes are recorded in Other taxes.

Pepco Energy Services Revenue

Revenue for Pepco Energy Services’ energy savings performance construction business and certain construction contracts in its underground transmission and distribution business is recognized using the percentage-of-completion method which recognizes revenue as work is completed and costs are incurred on its contracts. Under this method, Pepco Energy Services recognizes these contractual revenues based on the percentage of incurred costs relative to the estimated costs to complete a contract. Revenues from its operation and maintenance activities and measurement and verification activities in its energy savings business and certain construction contracts in its underground transmission and distribution business are recognized when earned.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in PHI’s gross revenues were $322 million, $321 million and $346 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Accounting for Derivatives

Accounting for Derivatives

PHI and its subsidiaries may use derivative instruments primarily to manage risk associated with commodity prices and interest rates. Risk management policies are determined by PHI’s Corporate Risk Management Committee (CRMC). The CRMC monitors interest rate fluctuation, commodity price fluctuation and credit risk exposure, and sets risk management policies that establish limits on unhedged risk.

PHI accounts for its derivative activities in accordance with FASB guidance on derivatives and hedging. Derivatives are recorded on the consolidated balance sheets as Derivative assets or Derivative liabilities and measured at fair value.

Changes in the fair value of derivatives held by DPL that do not qualify for hedge accounting or are not designated as hedges are presented on the consolidated statements of income (loss) as Fuel and purchased energy expense or Operating revenue, respectively. Changes in the fair value of derivatives held by DPL are deferred as regulatory assets or liabilities under the accounting guidance for regulated operations.

The gain or loss on a derivative that qualifies as a cash flow hedge of an exposure to variable cash flows of a forecasted transaction is initially recorded in accumulated other comprehensive loss (AOCL) (a separate component of equity) to the extent that the hedge is effective and is subsequently reclassified into earnings, in the same category as the item being hedged, when the gain or loss from the forecasted transaction occurs. If it is probable that a forecasted transaction will not occur, the deferred gain or loss in AOCL is immediately reclassified to earnings. Gains or losses related to any ineffective portion of cash flow hedges are also recognized in earnings immediately.

Changes in the fair value of derivatives designated as fair value hedges, as well as changes in the fair value of the hedged asset, liability or firm commitment, are recorded in the consolidated statements of income (loss).

The impact of derivatives that are marked to market through current earnings, the ineffective portion of cash flow hedges, and the portion of fair value hedges that flows to current earnings are presented on a net basis in the consolidated statements of income (loss) as Operating revenue or as Fuel and purchased energy expense. When a hedging gain or loss is realized, it is presented on a net basis in the same line item as the underlying item being hedged. Unrealized derivative gains and losses are presented gross on the consolidated balance sheets except where contractual netting agreements are in place with individual counterparties.

The fair value of derivatives is determined using quoted exchange prices where available. For instruments that are not traded on an exchange, pricing services and external broker quotes may also be used to determine fair value. For some custom and complex instruments, internal models use market-based information when external broker quotes are not available. For certain long-dated instruments, broker or exchange data are extrapolated, or capacity prices are forecasted, for future periods where information is limited. Models are also used to estimate volumes for certain transactions.

PHI may enter into master netting arrangements to mitigate credit risk related to its derivatives. Under FASB guidance on offsetting of balance sheet accounts (ASC 210-20), amounts recognized for derivative assets and liabilities and the fair value amounts recognized for any related collateral positions executed with the same counterparty under such master netting agreements are offset.

See Note (14), “Derivative Instruments and Hedging Activities,” for more information about the types of derivatives employed by PHI, the components of any unrealized and realized gains and losses and Note (15), “Fair Value Disclosures,” for the methodologies used to value them.

Stock-Based Compensation

Stock-Based Compensation

PHI recognizes compensation expense for stock-based awards, modifications or cancellations based on the grant-date fair value. Compensation expense is recognized over the requisite service period. A deferred tax asset and deferred tax benefit are also recognized concurrently with compensation expense for the tax effect of the deduction of stock options, restricted stock and restricted stock unit awards, which are deductible only upon exercise and/or vesting.

Historically, PHI’s compensation awards had included both time-based restricted stock awards that vest over a three-year service period and performance-based restricted stock and restricted stock units that were earned based on performance over a three-year period. Beginning in 2011, stock-based compensation awards have been granted primarily in the form of restricted stock units. Since May 2012, the Board of Directors have been granted an annual time-based restricted stock unit award that vests over one year as part of their compensation. The compensation expense associated with these awards is calculated based on the estimated fair value of the awards at the grant date and is recognized over the service or performance period.

PHI estimates the fair value of performance-based restricted stock unit awards using the Monte Carlo valuation model. These awards include performance conditions based upon PHI’s total stockholder return (TSR) versus a select group of peer companies over a three-year period. The effect of market conditions is considered in determining the awards’ fair value. This model values the specific features of employee share-based awards, including market-based performance conditions.

PHI’s current policy is to issue new shares to satisfy vested awards of restricted stock units.

Income Taxes

Income Taxes

PHI and the majority of its subsidiaries file a consolidated federal income tax return. Federal income taxes are allocated among PHI and the subsidiaries included in its consolidated group pursuant to a written tax sharing agreement, which was approved by the Securities and Exchange Commission (SEC) in 2002 in connection with the establishment of PHI as a public utility holding company. Under this tax sharing agreement, PHI’s consolidated federal income tax liability is allocated based upon PHI’s and its subsidiaries’ separate taxable income or loss amounts.

The consolidated financial statements include current and deferred income taxes. Current income taxes represent the amount of tax expected to be reported on PHI’s and its subsidiaries’ federal and state income tax returns. Deferred income tax assets and liabilities represent the tax effects of temporary differences between the financial statement basis and tax basis of existing assets and liabilities, and they are measured using presently enacted tax rates. See Note (11), “Income Taxes,” for a listing of primary deferred tax assets and liabilities. The portions of Pepco’s, DPL’s and ACE’s deferred tax liabilities applicable to their utility operations that have not been recovered from utility customers represent income taxes recoverable in the future and are included in Regulatory Assets on the consolidated balance sheets. See Note (7), “Regulatory Matters – Regulatory Assets and Regulatory Liabilities,” for additional information.

PHI recognizes interest on underpayments and overpayments of income taxes, interest on uncertain tax positions and tax-related penalties in income tax expense. Deferred income tax expense generally represents the net change during the reporting period in the net deferred tax liability and deferred recoverable income taxes.

Investment tax credits are amortized to income over the useful lives of the related property.

Cash and Cash Equivalents

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand, cash invested in money market funds and commercial paper held with original maturities of three months or less.

Restricted Cash Equivalents

Restricted Cash Equivalents

The Restricted cash equivalents included in Current assets and the Restricted cash equivalents included in Other assets consist of (i) cash held as collateral that is restricted from use for general corporate purposes and (ii) cash equivalents that are specifically segregated based on management’s intent to use such cash equivalents for a particular purpose. The classification as current or non-current conforms to the classification of the related liabilities.

Accounts Receivable and Allowance for Uncollectible Accounts

Accounts Receivable and Allowance for Uncollectible Accounts

PHI’s Accounts receivable balances primarily consist of customer accounts receivable arising from the sale of goods and services to customers within PHI’s service territories, other accounts receivable, and accrued unbilled revenue. Accrued unbilled revenue represents revenue earned in the current period but not billed to the customer until a future date (usually within one month after the receivable is recorded).

PHI maintains an allowance for uncollectible accounts and changes in the allowance are recorded as an adjustment to Other operation and maintenance expense in the consolidated statements of income (loss). PHI determines the amount of the allowance based on specific identification of material amounts at risk by customer and maintains a reserve based on its historical collection experience. The adequacy of this allowance is assessed on a quarterly basis by evaluating all known factors, such as the aging of the receivables, historical collection experience, the economic and competitive environment and changes in the creditworthiness of its customers. Accounts receivable are written off in the period in which the receivable is deemed uncollectible and collection efforts have been exhausted. Recoveries of Accounts receivable previously written off are recorded when received. Although PHI believes its allowance is adequate, it cannot anticipate with any certainty the changes in the financial condition of its customers. As a result, PHI records adjustments to the allowance for uncollectible accounts in the period in which the new information that requires an adjustment to the reserve becomes known.

Inventories

Inventories

PHI utilizes the weighted average cost method of accounting for inventory items. Under this method, an average price is determined for the quantity of units acquired at each price level and is applied to the ending quantity to calculate the total ending inventory balance. Materials and supplies are recorded in Inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed.

The cost of natural gas, including transportation costs, is included in Inventory when purchased and charged to Fuel and Purchased Energy expense when used.

Goodwill

Goodwill

Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired at the acquisition date. PHI tests its goodwill for impairment annually as of November 1 and whenever an event occurs or circumstances change in the interim that would more likely than not (that is, a greater than 50% chance) reduce the estimated fair value of a reporting unit below the carrying amount of its net assets. Factors that may result in an interim impairment test include, but are not limited to: a change in the identified reporting units; an adverse change in business conditions; a protracted decline in PHI’s stock price causing market capitalization to fall significantly below book value; an adverse regulatory action; or an impairment of long-lived assets in the reporting unit. PHI performed its most recent annual impairment test as of November 1, 2015, and its goodwill was not impaired as described in Note (6), “Goodwill.”

Regulatory Assets and Regulatory Liabilities

Regulatory Assets and Regulatory Liabilities

The operations of Pepco are regulated by the DCPSC and the MPSC. The operations of DPL are regulated by the DPSC and the MPSC. DPL’s interstate transportation and wholesale sale of natural gas are regulated by FERC. The operations of ACE are regulated by the NJBPU. The transmission of electricity by Pepco, DPL and ACE is regulated by FERC.

The FASB guidance on regulated operations (ASC 980) applies to Power Delivery. It allows regulated entities, in appropriate circumstances, to defer the income statement impact of certain costs that are expected to be recovered in future rates through the establishment of regulatory assets and defer certain revenues that are expected to be refunded to customers through the establishment of regulatory liabilities. Management’s assessment of the probability of recovery of regulatory assets requires judgment and interpretation of laws, regulatory commission orders and other factors. If management subsequently determines, based on changes in facts or circumstances, that a regulatory asset is not probable of recovery, then the regulatory asset would be eliminated through a charge to earnings.

Effective June 2007, the MPSC approved a bill stabilization adjustment (BSA) mechanism for retail customers of Pepco and DPL. Effective November 2009, the DCPSC approved a BSA for Pepco’s retail customers. For customers to whom the BSA applies, Pepco and DPL recognize distribution revenue based on an approved distribution charge per customer. From a revenue recognition standpoint, the BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during that period. Pursuant to this mechanism, Pepco and DPL recognize either (i) a positive adjustment equal to the amount by which revenue from Maryland and the District of Columbia retail distribution sales falls short of the revenue that Pepco and DPL are entitled to earn based on the approved distribution charge per customer, or (ii) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that Pepco and DPL are entitled to earn based on the approved distribution charge per customer (a Revenue Decoupling Adjustment). A net positive Revenue Decoupling Adjustment is recorded as a regulatory asset and a net negative Revenue Decoupling Adjustment is recorded as a regulatory liability.

Leasing Activities

Leasing Activities

Pepco Holdings’ lease transactions include plant, office space, equipment, software, vehicles and elements of power purchase agreements (PPAs). In accordance with FASB guidance on leases (ASC 840), these leases are classified as either leveraged leases, operating leases or capital leases.

Leveraged Leases

Income from investments in leveraged lease transactions, in which PHI was an equity participant, was accounted for using the financing method. In accordance with the financing method, investments in leased property were recorded as a receivable from the lessee to be recovered through the collection of future rentals. Income was recognized over the life of the lease at a constant rate of return on the positive net investment. Each quarter, PHI reviewed the carrying value of each lease, which included a review of the underlying financial assumptions, the timing and collectibility of cash flows, and the credit quality of the lessee. Changes to the underlying assumptions, if any, were accounted for in accordance with FASB guidance on leases and reflected in the carrying value of the lease effective for the quarter within which they occurred.

Operating Leases

An operating lease in which PHI or a subsidiary is the lessee generally results in a level income statement charge over the term of the lease, reflecting the rental payments required by the lease agreement. If rental payments are not made on a straight-line basis, PHI’s policy is to recognize rent expense on a straight-line basis over the lease term unless another systematic and rational allocation basis is more representative of the time pattern in which the leased property is physically employed.

Capital Leases

For ratemaking purposes, capital leases in which PHI or a subsidiary is the lessee are treated as operating leases; therefore, in accordance with FASB guidance on regulated operations (ASC 980), the amortization of the leased asset is based on the recovery of rental payments through customer rates. Investments in equipment under capital leases are stated at cost, less accumulated depreciation. Depreciation is recorded on a straight-line basis over the equipment’s estimated useful life.

Arrangements Containing a Lease

PPAs are deemed to contain a lease if the arrangement conveys the right to control the use of property, plant or equipment. If so, PHI determines the appropriate lease accounting classification.

Property, Plant and Equipment

Property, Plant and Equipment

Property, plant and equipment is recorded at original cost, including labor, materials, asset retirement costs and other direct and indirect costs including capitalized interest. The carrying value of Property, plant and equipment is evaluated for impairment whenever circumstances indicate the carrying value of those assets may not be recoverable. Upon retirement, the cost of regulated property, net of salvage, is charged to Accumulated depreciation. For non-regulated property, the cost and accumulated depreciation of the property, plant and equipment retired or otherwise disposed of are removed from the related accounts and included in the determination of any gain or loss on disposition.

The annual provision for depreciation on electric and natural gas property, plant and equipment is computed on a straight-line basis using composite rates by classes of depreciable property. Non-operating and other property is generally depreciated on a straight-line basis over the useful lives of the assets. The table below provides system-wide composite annual depreciation rates for the years ended December 31, 2015, 2014 and 2013.

	Transmission and Distribution									Generation
	2015			2014			2013			2015			2014			2013
Pepco		2.3	%		2.3	%		2.2	%		—			—			—
DPL		2.6	%		2.6	%		2.6	%		—			—			—
ACE		2.6	%		2.6	%		2.8	%		—			—			—
Pepco Energy Services		—			—			—			0.6	%		1.2	%		0.4	%

In 2010, subsidiaries of PHI received awards from the U.S. Department of Energy (DOE) under the American Recovery and Reinvestment Act of 2009. Pepco was awarded $149 million from DOE to fund a portion of the costs incurred for the implementation of an advanced metering infrastructure (AMI) system (a system that collects, measures and analyzes energy usage data from advanced digital meters known as smart meters), direct load control, distribution automation and communications infrastructure in its Maryland and District of Columbia service territories. ACE was awarded $19 million from DOE to fund a portion of the costs incurred for the implementation of direct load control, distribution automation and communications infrastructure in its New Jersey service territory. PHI elected to recognize the award proceeds as a reduction in the carrying value of the assets acquired rather than grant income over the service period.

Long-Lived Asset Impairment Evaluation

Long-Lived Asset Impairment Evaluation

PHI evaluates long-lived assets to be held and used, such as generating property and equipment, and real estate, for impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. Examples of such events or changes include a significant decrease in the market price of a long-lived asset or a significant adverse change in the manner in which an asset is being used or its physical condition. A long-lived asset to be held and used is written down to its estimated fair value if the expected future undiscounted cash flow from the asset is less than its carrying value.

For long-lived assets held for sale, an impairment loss is recognized to the extent that the asset’s carrying value exceeds its estimated fair value including costs to sell.

Capitalized Interest and Allowance for Funds Used During Construction

Capitalized Interest and Allowance for Funds Used During Construction

In accordance with FASB guidance on regulated operations (ASC 980), PHI’s utility subsidiaries may capitalize the capital costs of financing the construction of plant and equipment as allowance for funds used during construction (AFUDC). This results in the debt portion of AFUDC being recorded as a reduction of Interest expense and the equity portion of AFUDC being recorded as an increase to Other income in the accompanying consolidated statements of income (loss).

Pepco Holdings recorded AFUDC for borrowed funds of $8 million, $7 million and $7 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Pepco Holdings recorded amounts for the equity component of AFUDC of $14 million, $13 million and $11 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Amortization of Debt Issuance and Reacquisition Costs

Amortization of Debt Issuance and Reacquisition Costs

Pepco Holdings defers and amortizes debt issuance costs and long-term debt premiums and discounts over the lives of the respective debt issuances. When PHI utility subsidiaries refinance existing debt or redeem existing debt, any unamortized premiums, discounts and debt issuance costs, as well as debt redemption costs, are classified as regulatory assets and are amortized over the life of the original or new issue.

Asset Removal Costs

Asset Removal Costs

In accordance with FASB guidance on regulated operations (ASC 980), asset removal costs are recorded by PHI utility subsidiaries as Regulatory liabilities. At December 31, 2015 and 2014, $211 million and $250 million, respectively, of asset removal costs are included in Regulatory liabilities in the accompanying consolidated balance sheets.

Pension and Postretirement Benefit Plans

Pension and Postretirement Benefit Plans

PHI sponsors a non-contributory, defined benefit pension plan that covers substantially all employees of Pepco, DPL, ACE and certain employees of other PHI subsidiaries (the PHI Retirement Plan). PHI also provides supplemental retirement benefits to certain eligible executives and key employees through nonqualified retirement plans and provides certain postretirement health care and life insurance benefits for eligible retired employees. Most employees hired after January 1, 2005 will not have retiree health care coverage.

Net periodic benefit cost is included in Other operation and maintenance expense, net of the portion of the net periodic benefit cost capitalized as part of the cost of labor for internal construction projects. After intercompany allocations, the three utility subsidiaries are responsible for substantially all of the total PHI net periodic benefit cost.

PHI accounts for the PHI Retirement Plan, the nonqualified retirement plans, and the retirement health care and life insurance benefit plans in accordance with FASB guidance on retirement benefits (ASC 715).

See Note (9), “Pension and Other Postretirement Benefits,” for additional information.

Reclassifications

Reclassifications

Certain prior period amounts have been reclassified in order to conform to the current period presentation.

Discontinued Operations

Discontinued Operations (ASC 205)

In April 2014, the FASB issued new guidance on the reporting of discontinued operations that is effective for dispositions that occur after January 1, 2015. In order for dispositions to be presented as discontinued operations, the dispositions must represent a strategic shift that will have a major effect on an entity’s operations and financial results. Adoption of this guidance during the first quarter of 2015 did not have an impact on PHI’s consolidated financial statements.

Business Combinations

Business Combinations (ASC 805)

In November 2014, the FASB issued new recognition and disclosure requirements related to pushdown accounting. The new recognition requirements grant an acquired entity (or its subsidiaries) the option to elect whether and when a new accounting and reporting basis (pushdown accounting) will be applied when an acquirer obtains control of the acquired entity. This election may be made by the acquired entity (or its subsidiaries) for future change-in-control events or for its most recent change-in-control event, and the acquired entity will be required to determine whether pushdown accounting will be applied in the reporting period in which the change-in-control event occurs or in a subsequent reporting period.

The new required disclosures include information that enables financial statement users to evaluate the effects of pushdown accounting. Disclosures are required to be made in the period in which pushdown accounting is applied and are expected to include both qualitative and quantitative information.

The new recognition and disclosure requirements became effective on a prospective basis on November 18, 2014. PHI currently anticipates it may be affected by the new guidance if its Merger with Exelon is consummated.

Fair Value Measurement

Fair Value Measurement (ASC 820)

In May 2015, the FASB issued new disclosure requirements for investment fair values. Under the new requirements, investment fair values based on net asset value (NAV) per share will continue to be disclosed, however, a level will not be assigned to those investment fair values. The new requirements are effective for PHI beginning January 1, 2016, and are required to be implemented on a retrospective basis for all periods presented; however, early adoption is permitted. PHI has elected to early adopt the new guidance and implement the change in accounting principle in the fourth quarter of 2015. The impact of this guidance effected the presentation of certain investments that use NAV per share as a practical expedient in Note (9), “Pension and Other Postretirement Benefits” and had no impact to Note (15), “Fair Value Disclosure,” as the financial instruments measured at fair value on a recurring basis and other financial instruments are not based on NAV.

Presentation of Debt Issuance Costs

Presentation of Debt Issuance Costs (ASC 835)

In April 2015, the FASB issued new guidance for the presentation of debt issuance costs on the balance sheet. Debt issuance costs are currently required to be presented on the balance sheet as assets. However, under the new requirements, these debt issuance costs will be offset against the debt to which the costs relate. The new requirements are effective for PHI beginning January 1, 2016, and are required to be implemented on a retrospective basis for all periods presented; however, early adoption is permitted. PHI has elected to early adopt the new guidance in the fourth quarter of 2015. The table below illustrates the effects of the retrospective application on reported balances in PHI’s consolidated balance sheet as of December 31, 2014.

	December 31, 2014 As Filed		Reclassification ASC 835			December 31, 2014 As Adjusted
	(millions of dollars)
Other (within other assets)	$	166	$	(45	)	$	121
Long-term debt		4,441		(44	)		4,397
Transition bonds issued by ACE Funding		171		(1	)		170

Balance Sheet Classification of Deferred Taxes (ASC 740)

Balance Sheet Classification of Deferred Taxes (ASC 740)

In November 2015, the FASB issued new requirements for the balance sheet classification of deferred taxes. Entities are currently required to present a current and noncurrent deferred tax balance on the balance sheet. Under the new requirements, deferred taxes will only be presented as noncurrent. The new requirements are effective for PHI beginning January 1, 2017, and may be implemented on either a prospective or retrospective basis; however, early adoption is permitted. PHI has elected to early adopt the new guidance on a retrospective basis in the fourth quarter of 2015. The table below illustrates the effects of the retrospective application on reported balances in PHI’s consolidated balance sheet as of December 31, 2014.

	December 31, 2014 As Filed		Reclassification ASC 740			December 31, 2014 As Adjusted
	(millions of dollars)
Deferred income taxes, net (within current assets)	$	50	$	(50	)	$	—
Deferred income taxes, net (within other assets)		—		17			17
Other (within current liabilities)		314		(9	)		305
Deferred income tax liabilities, net		3,266		(24	)		3,242

Revenue from Contracts with Customers

Revenue from Contracts with Customers (ASC 606)

In May 2014, the FASB issued new recognition and disclosure requirements for revenue from contracts with customers, which supersedes the existing revenue recognition guidance. The new recognition requirements focus on when the customer obtains control of the goods or services, rather than the current risks and rewards model of recognition. The core principle of the new standard is that an entity will recognize revenue when it transfers goods or services to its customers in an amount that reflects the consideration an entity expects to be entitled to for those goods or services. The new disclosure requirements will include information intended to communicate the nature, amount, timing and any uncertainty of revenue and cash flows from applicable contracts, including any significant judgments and changes in judgments and assets recognized from the costs to obtain or fulfill a contract. Entities will generally be required to make more estimates and use more judgment under the new standard.

The new requirements will be effective for PHI beginning January 1, 2018, and may be implemented either retrospectively for all periods presented, or as a cumulative-effect adjustment as of January 1, 2018. Early adoption is permitted, but not before January 1, 2017. PHI is currently evaluating the potential impact of this new guidance on its consolidated financial statements and which implementation approach to select.

Business Combination

Business Combination (ASC 805)

In September 2015, the FASB issued new guidance on adjustments to provisional amounts recognized in a business combination, which are currently recognized on a retrospective basis. Under the new requirements, adjustments will be recognized in the reporting period in which the adjustments are determined. The effects of changes in depreciation, amortization, or other income arising from changes to the provisional amounts, if any, are included in earnings of the reporting period in which the adjustments to the provisional amounts are determined. An entity is also required to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The new requirements will be effective for PHI beginning January 1, 2016, and are required to be implemented on a prospective basis. Early adoption is permitted. PHI currently anticipates it may be affected by the new guidance if its Merger with Exelon is consummated.

Potomac Electric Power Co [Member]

Use of Estimates

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the financial statements and accompanying notes. Although Pepco believes that its estimates and assumptions are reasonable, they are based upon information available to management at the time the estimates are made. Actual results may differ significantly from these estimates.

Significant matters that involve the use of estimates include the assessment of contingencies, the calculation of future cash flows and fair value amounts for use in asset impairment calculations, pension and other postretirement benefits assumptions, the assessment of the adequacy of the allowance for uncollectible accounts, the assessment of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of unbilled revenue, recognition of changes in network service transmission rates for prior service year costs, accrual of loss contingency liabilities for general litigation and auto and other liability claims and income tax provisions and reserves. Additionally, Pepco is subject to legal, regulatory, and other proceedings and claims that arise in the ordinary course of its business. Pepco records an estimated liability for these proceedings and claims when it is probable that a loss has been incurred and the loss is reasonably estimable.

Revenue Recognition

Revenue Recognition

Pepco recognizes revenue upon distribution of electricity to its customers, including unbilled revenue for services rendered, but not yet billed. Pepco’s unbilled revenue was $76 million and $77 million as of December 31, 2015 and 2014, respectively, and these amounts are included in Accounts receivable. Pepco calculates unbilled revenue using an output-based methodology. This methodology is based on the supply of electricity intended for distribution to customers. The unbilled revenue process requires management to make assumptions and judgments about input factors such as customer sales mix, temperature, and estimated line losses (estimates of electricity expected to be lost in the process of its transmission and distribution to customers). The assumptions and judgments are inherently uncertain and susceptible to change from period to period, and if actual results differ from projected results, the impact could be material.

Taxes related to the consumption of electricity by Pepco’s customers, such as fuel, energy, or other similar taxes, are components of Pepco’s tariffs and, as such, are billed to customers and recorded in Operating revenue. Accruals for the remittance of these taxes by Pepco are recorded in Other taxes.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in Pepco’s gross revenues were $304 million, $304 million and $318 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Income Taxes

Income Taxes

Pepco, as a direct subsidiary of Pepco Holdings, is included in the consolidated federal income tax return of PHI. Federal income taxes are allocated to Pepco based upon the taxable income or loss amounts, determined on a separate return basis.

The financial statements include current and deferred income taxes. Current income taxes represent the amount of tax expected to be reported on Pepco’s state income tax returns and the amount of federal income tax allocated from Pepco Holdings.

Deferred income tax assets and liabilities represent the tax effects of temporary differences between the financial statement basis and tax basis of existing assets and liabilities and they are measured using presently enacted tax rates. The portion of Pepco’s deferred tax liability applicable to its utility operations that has not been recovered from utility customers represents income taxes recoverable in the future and is included in Regulatory assets on the balance sheets. See Note (6), “Regulatory Matters,” for additional information.

Deferred income tax expense generally represents the net change during the reporting period in the net deferred tax liability and deferred recoverable income taxes.

Pepco recognizes interest on underpayments and overpayments of income taxes, interest on uncertain tax positions, and tax-related penalties in income tax expense.

Investment tax credits are being amortized to income over the useful lives of the related property.

Cash and Cash Equivalents

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand, cash invested in money market funds and commercial paper held with original maturities of three months or less. Additionally, deposits in PHI’s money pool, which Pepco and certain other PHI subsidiaries use to manage short-term cash management requirements, are considered cash equivalents. Deposits in the money pool are guaranteed by PHI. PHI deposits funds in the money pool to the extent that the pool has insufficient funds to meet the needs of its participants, which may require PHI to borrow funds for deposit from external sources.

Restricted Cash Equivalents

Restricted Cash Equivalents

The Restricted cash equivalents included in Current assets consist of (i) cash held as collateral that is restricted from use for general corporate purposes and (ii) cash equivalents that are specifically segregated based on management’s intent to use such cash equivalents for a particular purpose. The classification as current conforms to the classification of the related liabilities.

Accounts Receivable and Allowance for Uncollectible Accounts

Accounts Receivable and Allowance for Uncollectible Accounts

Pepco’s Accounts receivable balance primarily consists of customer accounts receivable arising from the sale of goods and services to customers within its service territory, other accounts receivable, and accrued unbilled revenue. Accrued unbilled revenue represents revenue earned in the current period but not billed to the customer until a future date (usually within one month after the receivable is recorded).

Pepco maintains an allowance for uncollectible accounts and changes in the allowance are recorded as an adjustment to Other operation and maintenance expense in the statements of income. Pepco determines the amount of the allowance based on specific identification of material amounts at risk by customer and maintains a reserve based on its historical collection experience. The adequacy of this allowance is assessed on a quarterly basis by evaluating all known factors such as the aging of the receivables, historical collection experience, the economic and competitive environment and changes in the creditworthiness of its customers. Accounts receivable are written off in the period in which the receivable is deemed uncollectible and collection efforts have been exhausted. Recoveries of Accounts receivable previously written off are recorded when received. Although Pepco believes its allowance is adequate, it cannot anticipate with any certainty the changes in the financial condition of its customers. As a result, Pepco records adjustments to the allowance for uncollectible accounts in the period in which the new information that requires an adjustment to the reserve becomes known.

Inventories

Inventories

Included in Inventories are transmission and distribution materials and supplies. Pepco utilizes the weighted average cost method of accounting for inventory items. Under this method, an average price is determined for the quantity of units acquired at each price level and is applied to the ending quantity to calculate the total ending inventory balance. Materials and supplies are recorded in Inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed.

Regulatory Assets and Regulatory Liabilities

Regulatory Assets and Regulatory Liabilities

Pepco is regulated by the MPSC and the DCPSC. The transmission of electricity by Pepco is regulated by FERC.

Based on the regulatory framework in which it has operated, Pepco has historically applied, and in connection with its transmission and distribution business continues to apply, the Financial Accounting Standards Board (FASB) guidance on regulated operations (Accounting Standards Codification (ASC) 980). The guidance allows regulated entities, in appropriate circumstances, to defer the income statement impact of certain costs that are expected to be recovered in future rates through the establishment of regulatory assets and defer certain revenues that are expected to be refunded to customers through the establishment of regulatory liabilities. Management’s assessment of the probability of recovery of regulatory assets requires judgment and interpretation of laws, regulatory commission orders and other factors. If management subsequently determines, based on changes in facts or circumstances, that a regulatory asset is not probable of recovery, the regulatory asset would be eliminated through a charge to earnings.

Effective June 2007, the MPSC approved a bill stabilization adjustment (BSA) mechanism for retail customers. Effective November 2009, the DCPSC approved a BSA for retail customers. For customers to whom the BSA applies, Pepco recognizes distribution revenue based on an approved distribution charge per customer. From a revenue recognition standpoint, the BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during that period. Pursuant to this mechanism, Pepco recognizes either (i) a positive adjustment equal to the amount by which revenue from Maryland and the District of Columbia retail distribution sales falls short of the revenue that Pepco is entitled to earn based on the approved distribution charge per customer, or (ii) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that Pepco is entitled to earn based on the approved distribution charge per customer (a Revenue Decoupling Adjustment). A net positive Revenue Decoupling Adjustment is recorded as a regulatory asset and a net negative Revenue Decoupling Adjustment is recorded as a regulatory liability.

Leasing Activities

Leasing Activities

Pepco’s lease transactions include office space, equipment, software and vehicles. In accordance with FASB guidance on leases (ASC 840), these leases are classified as either operating leases or capital leases.

Operating Leases

An operating lease in which Pepco is the lessee generally results in a level income statement charge over the term of the lease, reflecting the rental payments required by the lease agreement. If rental payments are not made on a straight-line basis, Pepco’s policy is to recognize rent expense on a straight-line basis over the lease term unless another systematic and rational allocation basis is more representative of the time pattern in which the leased property is physically employed.

Capital Leases

For ratemaking purposes, capital leases in which Pepco is the lessee are treated as operating leases; therefore, in accordance with FASB guidance on regulated operations (ASC 980), the amortization of the leased asset is based on the recovery of rental payments through customer rates. Investments in equipment under capital leases are stated at cost, less accumulated depreciation. Depreciation is recorded on a straight-line basis over the equipment’s estimated useful life.

Property, Plant and Equipment

Property, Plant and Equipment

Property, plant and equipment is recorded at original cost, including labor, materials, asset retirement costs and other direct and indirect costs including capitalized interest. The carrying value of Property, plant and equipment is evaluated for impairment whenever circumstances indicate that the carrying value of those assets may not be recoverable. Upon retirement, the cost of regulated property, net of salvage, is charged to Accumulated depreciation. For additional information regarding the treatment of asset removal obligations, see the “Asset Removal Costs” section included in this Note.

The annual provision for depreciation on electric property, plant and equipment is computed on a straight-line basis using composite rates by classes of depreciable property. Non-operating and other property is generally depreciated on a straight-line basis over the useful lives of the assets. The system-wide composite annual depreciation rates for the years ended December 31, 2015, 2014 and 2013 for Pepco’s property were approximately 2.3%, 2.3% and 2.2%, respectively.

Long-Lived Asset Impairment Evaluation

Long-Lived Assets Impairment Evaluation

Pepco evaluates certain long-lived assets to be held and used (for example, equipment and real estate) for impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. Examples of such events or changes include a significant decrease in the market price of a long-lived asset or a significant adverse change in the manner in which an asset is being used or its physical condition. A long-lived asset to be held and used is written down to its estimated fair value if the expected future undiscounted cash flow from the asset is less than its carrying value.

For long-lived assets that can be classified as assets to be disposed of by sale, an impairment loss is recognized to the extent that the asset’s carrying value exceeds its estimated fair value including costs to sell.

Capitalized Interest and Allowance for Funds Used During Construction

Capitalized Interest and Allowance for Funds Used During Construction

In accordance with FASB guidance on regulated operations (ASC 980), utilities may capitalize the capital costs of financing the construction of plant and equipment as allowance for funds used during construction (AFUDC). This results in the debt portion of AFUDC being recorded as a reduction of Interest expense and the equity portion of AFUDC being recorded as an increase to Other income in the accompanying statements of income.

Pepco recorded AFUDC for borrowed funds of $6 million, $5 million and $5 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Pepco recorded amounts for the equity component of AFUDC of $12 million, $10 million and $9 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Amortization of Debt Issuance and Reacquisition Costs

Amortization of Debt Issuance and Reacquisition Costs

Pepco defers and amortizes debt issuance costs and long-term debt premiums and discounts over the lives of the respective debt issuances. When refinancing or redeeming existing debt, any unamortized premiums, discounts and debt issuance costs, as well as debt redemption costs, are classified as regulatory assets and are amortized generally over the life of the new issue.

Asset Removal Costs

Asset Removal Costs

In accordance with FASB guidance on regulated operations (ASC 980), asset removal costs are recorded as regulatory liabilities. At December 31, 2015 and 2014, $58 million and $84 million, respectively, of asset removal costs are included in Regulatory liabilities in the accompanying balance sheets.

Pension and Postretirement Benefit Plans

Pension and Postretirement Benefit Plans

Pepco Holdings sponsors a non-contributory, defined benefit pension plan that covers substantially all employees of Pepco and certain employees of other Pepco Holdings subsidiaries (the PHI Retirement Plan). Pepco Holdings also provides supplemental retirement benefits to certain eligible executives and key employees through nonqualified retirement plans and provides certain postretirement health care and life insurance benefits for eligible retired employees.

The PHI Retirement Plan is accounted for in accordance with FASB guidance on retirement benefits (ASC 715).

Reclassifications

Reclassifications

Certain prior period amounts have been reclassified in order to conform to the current period presentation.

Dividend Restrictions

Dividend Restrictions

All of Pepco’s shares of outstanding common stock are held by PHI, its parent company. In addition to its future financial performance, the ability of Pepco to pay dividends to its parent company is subject to limits imposed by: (i) state corporate laws, which impose limitations on the funds that can be used to pay dividends, and (ii) the prior rights of holders of future preferred stock, if any, and existing and future mortgage bonds and other long-term debt issued by Pepco and any other restrictions imposed in connection with the incurrence of liabilities. Pepco has no shares of preferred stock outstanding. Pepco had approximately $1,118 million and $1,077 million of retained earnings available for payment of common stock dividends at December 31, 2015 and 2014, respectively. These amounts represent the total retained earnings balances at those dates.

Business Combinations

Business Combinations (ASC 805)

In November 2014, the FASB issued new recognition and disclosure requirements related to pushdown accounting. The new recognition requirements grant an acquired entity (or its subsidiaries) the option to elect whether and when a new accounting and reporting basis (pushdown accounting) will be applied when an acquirer obtains control of the acquired entity. This election may be made by the acquired entity (or its subsidiaries) for future change-in-control events or for its most recent change-in-control event, and the acquired entity will be required to determine whether pushdown accounting will be applied in the reporting period in which the change-in-control event occurs or in a subsequent reporting period.

The new required disclosures include information that enables financial statement users to evaluate the effects of pushdown accounting. Disclosures are required to be made in the period in which pushdown accounting is applied and are expected to include both qualitative and quantitative information.

The new recognition and disclosure requirements became effective on a prospective basis on November 18, 2014.

Presentation of Debt Issuance Costs

Presentation of Debt Issuance Costs (ASC 835)

In April 2015, the FASB issued new guidance for the presentation of debt issuance costs on the balance sheet. Debt issuance costs are currently required to be presented on the balance sheet as assets. However, under the new requirements, these debt issuance costs will be offset against the debt to which the costs relate. The new requirements are effective for Pepco beginning January 1, 2016, and are required to be implemented on a retrospective basis for all periods presented; however, early adoption is permitted. Pepco has elected to early adopt the new guidance in the fourth quarter of 2015. The table below illustrates the effects of the retrospective application on reported balances in Pepco’s balance sheet as of December 31, 2014.

	December 31, 2014 As Filed		Reclassification ASC 835			December 31, 2014 As Adjusted
	(millions of dollars)
Other (within other assets)	$	71	$	(28	)	$	43
Long-term debt		2,124		(28	)		2,096

Balance Sheet Classification of Deferred Taxes (ASC 740)

Balance Sheet Classification of Deferred Taxes (ASC 740)

In November 2015, the FASB issued new requirements for the balance sheet classification of deferred taxes. Entities are currently required to present a current and noncurrent deferred tax balance on the balance sheet. Under the new requirements, deferred taxes will only be presented as noncurrent. The new requirements are be effective for PHI beginning January 1, 2017, and may be implemented on either a prospective or retrospective basis; however, early adoption is permitted. PHI has elected to early adopt the new guidance on a retrospective basis in the fourth quarter of 2015. The table below illustrates the effects of the retrospective application on reported balances in Pepco’s balance sheet as of December 31, 2014.

	December 31, 2014 As Filed		Reclassification ASC 740			December 31, 2014 As Adjusted
	(millions of dollars)
Deferred income taxes, net (within current assets)	$	14	$	(14	)	$	—
Other (within current liabilities)		102		(9	)		93
Deferred income tax liabilities, net		1,584		(5	)		1,579

Revenue from Contracts with Customers

Revenue from Contracts with Customers (ASC 606)

In May 2014, the FASB issued new recognition and disclosure requirements for revenue from contracts with customers, which supersedes the existing revenue recognition guidance. The new recognition requirements focus on when the customer obtains control of the goods or services, rather than the current risks and rewards model of recognition. The core principle of the new standard is that an entity will recognize revenue when it transfers goods or services to its customers in an amount that reflects the consideration an entity expects to be entitled to for those goods or services. The new disclosure requirements will include information intended to communicate the nature, amount, timing and any uncertainty of revenue and cash flows from applicable contracts, including any significant judgments and changes in judgments and assets recognized from the costs to obtain or fulfill a contract. Entities will generally be required to make more estimates and use more judgment under the new standard.

The new requirements will be effective for Pepco beginning January 1, 2018, and may be implemented either retrospectively for all periods presented, or as a cumulative-effect adjustment as of January 1, 2018. Early adoption is permitted, but not before January 1, 2017. Pepco is currently evaluating the potential impact of this new guidance on its financial statements and which implementation approach to select.

Business Combination

Business Combination (ASC 805)

In September 2015, the FASB issued new guidance on adjustments to provisional amounts recognized in a business combination, which are currently recognized on a retrospective basis. Under the new requirements, adjustments will be recognized in the reporting period in which the adjustments are determined. The effects of changes in depreciation, amortization, or other income arising from changes to the provisional amounts, if any, are included in earnings of the reporting period in which the adjustments to the provisional amounts are determined. An entity is also required to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The new requirements will be effective for Pepco beginning January 1, 2016, and are required to be implemented on a prospective basis. Early adoption is permitted. Pepco currently anticipates it may be affected by the new guidance if its Merger with Exelon is consummated.

Investment in Trust

Investment in Trust

Represents assets held in a trust for the benefit of participants in the Pepco Owned Life Insurance plan.

Delmarva Power & Light Co/De [Member]

Consolidation of Variable Interest Entities

Consolidation of Variable Interest Entities

DPL assesses its contractual arrangements with variable interest entities (VIEs) to determine whether it is the primary beneficiary and thereby has to consolidate the entities in accordance with FASB ASC 810. The guidance addresses conditions under which an entity should be consolidated based upon variable interests rather than voting interests. See Note (17), “Variable Interest Entities,” for additional information.

Use of Estimates

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the financial statements and accompanying notes. Although DPL believes that its estimates and assumptions are reasonable, they are based upon information available to management at the time the estimates are made. Actual results may differ significantly from these estimates.

Significant matters that involve the use of estimates include the assessment of contingencies, the calculation of future cash flows and fair value amounts for use in asset and goodwill impairment calculations, fair value calculations for derivative instruments, pension and other postretirement benefits assumptions, the assessment of the adequacy of the allowance for uncollectible accounts, the assessment of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of unbilled revenue, recognition of changes in network service transmission rates for prior service year costs, accrual of loss contingency liabilities for general litigation and auto and other liability claims, and income tax provisions and reserves. Additionally, DPL is subject to legal, regulatory, and other proceedings and claims that arise in the ordinary course of its business. DPL records an estimated liability for these proceedings and claims when it is probable that a loss has been incurred and the loss is reasonably estimable.

Revenue Recognition

Revenue Recognition

DPL recognizes revenue upon distribution of electricity and natural gas to its customers, including unbilled revenue for services rendered, but not yet billed. DPL’s unbilled revenue was $37 million and $63 million as of December 31, 2015 and 2014, respectively, and these amounts are included in Accounts receivable. DPL calculates unbilled revenue using an output-based methodology. This methodology is based on the supply of electricity or natural gas intended for distribution to customers. The unbilled revenue process requires management to make assumptions and judgments about input factors such as customer sales mix, temperature, and estimated line losses (estimates of electricity and natural gas expected to be lost in the process of its transmission and distribution to customers). The assumptions and judgments are inherently uncertain and susceptible to change from period to period, and if the actual results differ from the projected results, the impact could be material. Revenue from non-regulated electricity and natural gas sales is included in Electric revenue and Natural gas revenue, respectively.

Taxes related to the consumption of electricity and natural gas by DPL’s customers, such as fuel, energy, or other similar taxes, are components of DPL’s tariffs and, as such, are billed to customers and recorded in Operating revenue. Accruals for the remittance of these taxes by DPL are recorded in Other taxes.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in DPL’s gross revenues were $18 million, $16 million and $17 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Accounting for Derivatives

Accounting for Derivatives

DPL uses derivative instruments primarily to reduce natural gas commodity price volatility and to limit its customers’ exposure to natural gas price fluctuations under a hedging program approved by the DPSC. Derivatives are recorded in the balance sheets as Derivative assets or Derivative liabilities and measured at fair value. DPL enters physical natural gas contracts as part of the hedging program that qualify as normal purchases or normal sales, which are not required to be recorded in the financial statements until settled. DPL’s capacity contracts are not classified as derivatives. Changes in the fair value of derivatives that are not designated as cash flow hedges are reflected in income.

All premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all gains and losses related to hedging activities, are fully recoverable through the fuel adjustment clause approved by the DPSC, and are deferred under Financial Accounting Standards Board (FASB) guidance on regulated operations (Accounting Standards Codification (ASC) 980) until recovered.

Income Taxes

Income Taxes

DPL, as an indirect subsidiary of Pepco Holdings, is included in the consolidated federal income tax return of PHI. Federal income taxes are allocated to DPL based upon the taxable income or loss amounts, determined on a separate return basis.

The accompanying financial statements include current and deferred income taxes. Current income taxes represent the amount of tax expected to be reported on DPL’s state income tax returns and the amount of federal income tax allocated from Pepco Holdings.

Deferred income tax assets and liabilities represent the tax effects of temporary differences between the financial statement basis and tax basis of existing assets and liabilities, and they are measured using presently enacted tax rates. The portion of DPL’s deferred tax liability applicable to its utility operations that has not been recovered from utility customers represents income taxes recoverable in the future and is included in Regulatory assets on the accompanying balance sheets. See Note (7), “Regulatory Matters,” for additional information.

Deferred income tax expense generally represents the net change during the reporting period in the net deferred tax liability and deferred recoverable income taxes.

DPL recognizes interest on underpayments and overpayments of income taxes, interest on uncertain tax positions, and tax-related penalties in income tax expense.

Investment tax credits are being amortized to income over the useful lives of the related property.

Cash and Cash Equivalents

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand, cash invested in money market funds and commercial paper held with original maturities of three months or less. Additionally, deposits in PHI’s money pool, which DPL and certain other PHI subsidiaries use to manage short-term cash management requirements, are considered cash equivalents. Deposits in the money pool are guaranteed by PHI. PHI deposits funds in the money pool to the extent that the pool has insufficient funds to meet the needs of its participants, which may require PHI to borrow funds for deposit from external sources.

Accounts Receivable and Allowance for Uncollectible Accounts

Accounts Receivable and Allowance for Uncollectible Accounts

DPL’s Accounts receivable balance primarily consists of customer accounts receivable arising from the sale of goods and services to customers within its service territory, other accounts receivable, and accrued unbilled revenue. Accrued unbilled revenue represents revenue earned in the current period but not billed to the customer until a future date (usually within one month after the receivable is recorded).

DPL maintains an allowance for uncollectible accounts and changes in the allowance are recorded as an adjustment to Other operation and maintenance expense in the accompanying statements of income. DPL determines the amount of the allowance based on specific identification of material amounts at risk by customer and maintains a reserve based on its historical collection experience. The adequacy of this allowance is assessed on a quarterly basis by evaluating all known factors such as the aging of the receivables, historical collection experience, the economic and competitive environment and changes in the creditworthiness of its customers. Accounts receivable are written off in the period in which the receivable is deemed uncollectible and collection efforts have been exhausted. Recoveries of Accounts receivable previously written off are recorded when received. Although DPL believes its allowance is adequate, it cannot anticipate with any certainty the changes in the financial condition of its customers. As a result, DPL records adjustments to the allowance for uncollectible accounts in the period in which the new information that requires an adjustment to the reserve becomes known.

Inventories

Inventories

Included in Inventories are transmission and distribution materials and supplies and natural gas. DPL utilizes the weighted average cost method of accounting for inventory items. Under this method, an average price is determined for the quantity of units acquired at each price level and is applied to the ending quantity to calculate the total ending inventory balance. Materials and supplies are recorded in Inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed.

The cost of natural gas, including transportation costs, is included in Inventory when purchased and charged to Gas purchased expense when used.

Goodwill

Goodwill

Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired at the acquisition date. DPL tests its goodwill for impairment annually as of November 1 and whenever an event occurs or circumstances change in the interim that would more likely than not (that is, a greater than 50% chance) reduce the estimated fair value of DPL below the carrying amount of its net assets. Factors that may result in an interim impairment test include, but are not limited to: a change in the identified reporting unit, an adverse change in business conditions, an adverse regulatory action, or an impairment of DPL’s long-lived assets. DPL performed its most recent annual impairment test as of November 1, 2015, and its goodwill was not impaired as described in Note (6), “Goodwill.”

Regulatory Assets and Regulatory Liabilities

Regulatory Assets and Regulatory Liabilities

Certain aspects of DPL’s business are subject to regulation by the DPSC and the MPSC. The transmission of electricity by DPL is regulated by FERC. DPL’s interstate transportation and wholesale sale of natural gas are regulated by FERC.

Based on the regulatory framework in which it has operated, DPL has historically applied, and in connection with its transmission and distribution business continues to apply, FASB guidance on regulated operations (ASC 980). The guidance allows regulated entities, in appropriate circumstances, to defer the income statement impact of certain costs that are expected to be recovered in future rates through the establishment of regulatory assets and defer certain revenues that are expected to be refunded to customers through the establishment of regulatory liabilities. Management’s assessment of the probability of recovery of regulatory assets requires judgment and interpretation of laws, regulatory commission orders and other factors. If management subsequently determines, based on changes in facts or circumstances, that a regulatory asset is not probable of recovery, the regulatory asset would be eliminated through a charge to earnings.

Effective June 2007, the MPSC approved a bill stabilization adjustment (BSA) mechanism for retail customers. For customers to whom the BSA applies, DPL recognizes distribution revenue based on an approved distribution charge per customer. From a revenue recognition standpoint, the BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during that period. Pursuant to this mechanism, DPL recognizes either (i) a positive adjustment equal to the amount by which revenue from Maryland retail distribution sales falls short of the revenue that DPL is entitled to earn based on the approved distribution charge per customer, or (ii) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that DPL is entitled to earn based on the approved distribution charge per customer (a Revenue Decoupling Adjustment). A net positive Revenue Decoupling Adjustment is recorded as a regulatory asset and a net negative Revenue Decoupling Adjustment is recorded as a regulatory liability.

Leasing Activities

Leasing Activities

DPL’s lease transactions include plant, office space, equipment, software, vehicles and elements of power purchase agreements (PPAs). In accordance with FASB guidance on leases (ASC 840), these leases are classified as operating leases.

Operating Leases

An operating lease in which DPL is the lessee generally results in a level income statement charge over the term of the lease, reflecting the rental payments required by the lease agreement. If rental payments are not made on a straight-line basis, DPL’s policy is to recognize rent expense on a straight-line basis over the lease term unless another systematic and rational allocation basis is more representative of the time pattern in which the leased property is physically employed.

Arrangements Containing a Lease

PPAs are deemed to contain a lease if the arrangement conveys the right to control the use of property, plant or equipment. If so, DPL determines the appropriate lease accounting classification.

Property, Plant and Equipment

Property, Plant and Equipment

Property, plant and equipment is recorded at original cost, including labor, materials, asset retirement costs and other direct and indirect costs including capitalized interest. The carrying value of Property, plant and equipment is evaluated for impairment whenever circumstances indicate that the carrying value of those assets may not be recoverable. Upon retirement, the cost of regulated property, net of salvage, is charged to Accumulated depreciation. For additional information regarding the treatment of asset retirement obligations, see the “Asset Removal Costs” section included in this Note.

The annual provision for depreciation on electric and natural gas property, plant and equipment is computed on a straight-line basis using composite rates by classes of depreciable property. Non-operating and other property is generally depreciated on a straight-line basis over the useful lives of the assets. The system-wide composite annual depreciation rate for each of the years ended December 31, 2015, 2014 and 2013 for DPL’s property was approximately 2.6%.

Long-Lived Asset Impairment Evaluation

Long-Lived Assets Impairment Evaluation

DPL evaluates certain long-lived assets to be held and used (for example, equipment and real estate) for impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. Examples of such events or changes include a significant decrease in the market price of a long-lived asset or a significant adverse change in the manner in which an asset is being used or its physical condition. A long-lived asset to be held and used is written down to its estimated fair value if the expected future undiscounted cash flow from the asset is less than its carrying value.

For long-lived assets that can be classified as assets to be disposed of by sale, an impairment loss is recognized to the extent that the assets’ carrying value exceeds its estimated fair value including costs to sell.

Capitalized Interest and Allowance for Funds Used During Construction

Capitalized Interest and Allowance for Funds Used During Construction

In accordance with FASB guidance on regulated operations (ASC 980), utilities may capitalize the capital costs of financing the construction of plant and equipment as allowance for funds used during construction (AFUDC). This results in the debt portion of AFUDC being recorded as a reduction of Interest expense and the equity portion of AFUDC being recorded as an increase to Other income in the accompanying statements of income.

DPL recorded AFUDC for borrowed funds of $1 million, $1 million and $2 million for the years ended December 31, 2015, 2014 and 2013, respectively.

DPL recorded amounts for the equity component of AFUDC of $1 million, $2 million and $2 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Amortization of Debt Issuance and Reacquisition Costs

Amortization of Debt Issuance and Reacquisition Costs

DPL defers and amortizes debt issuance costs and long-term debt premiums and discounts over the lives of the respective debt issuances. When refinancing or redeeming existing debt, any unamortized premiums, discounts and debt issuance costs, as well as debt redemption costs, are classified as regulatory assets and are amortized generally over the life of the original issue.

Asset Removal Costs

Asset Removal Costs

In accordance with FASB guidance on regulated operations (ASC 980), asset removal costs are recorded as regulatory liabilities. At December 31, 2015 and 2014, $153 million and $166 million, respectively, of asset removal costs are included in Regulatory liabilities in the accompanying balance sheets.

Pension and Postretirement Benefit Plans

Pension and Postretirement Benefit Plans

Pepco Holdings sponsors a non-contributory, defined benefit pension plan that covers substantially all employees of DPL and certain employees of other Pepco Holdings subsidiaries (the PHI Retirement Plan). Pepco Holdings also provides supplemental retirement benefits to certain eligible executives and key employees through nonqualified retirement plans and provides certain postretirement health care and life insurance benefits for eligible retired employees.

The PHI Retirement Plan is accounted for in accordance with FASB guidance on retirement benefits (ASC 715).

Reclassifications

Reclassifications

Certain prior period amounts have been reclassified in order to conform to the current period presentation.

Dividend Restrictions

Dividend Restrictions

All of DPL’s shares of outstanding common stock are held by Conectiv, its parent company. In addition to its future financial performance, the ability of DPL to pay dividends to its parent company is subject to limits imposed by: (i) state corporate laws, which impose limitations on the funds that can be used to pay dividends, and (ii) the prior rights of holders of future preferred stock, if any, and existing and future mortgage bonds and other long-term debt issued by DPL and any other restrictions imposed in connection with the incurrence of liabilities. DPL has no shares of preferred stock outstanding. DPL had approximately $625 million and $641 million of retained earnings available for payment of common stock dividends at December 31, 2015 and 2014, respectively. These amounts represent the total retained earnings balances at those dates.

Business Combinations

Business Combinations (ASC 805)

In November 2014, the FASB issued new recognition and disclosure requirements related to pushdown accounting. The new recognition requirements grant an acquired entity (or its subsidiaries) the option to elect whether and when a new accounting and reporting basis (pushdown accounting) will be applied when an acquirer obtains control of the acquired entity. This election may be made by the acquired entity (or its subsidiaries) for future change-in-control events or for its most recent change-in-control event, and the acquired entity will be required to determine whether pushdown accounting will be applied in the reporting period in which the change-in-control event occurs or in a subsequent reporting period.

The new required disclosures include information that enables financial statement users to evaluate the effects of pushdown accounting. Disclosures are required to be made in the period in which pushdown accounting is applied and are expected to include both qualitative and quantitative information.

The new recognition and disclosure requirements became effective on a prospective basis on November 18, 2014.

Presentation of Debt Issuance Costs

Presentation of Debt Issuance Costs (ASC 835)

In April 2015, the FASB issued new guidance for the presentation of debt issuance costs on the balance sheet. Debt issuance costs are currently required to be presented on the balance sheet as assets. However, under the new requirements, these debt issuance costs will be offset against the debt to which the costs relate. The new requirements are effective for DPL beginning January 1, 2016, and are required to be implemented on a retrospective basis for all periods presented; however, early adoption is permitted. DPL has elected to early adopt the new guidance in the fourth quarter of 2015. The table below illustrates the effects of the retrospective application on reported balances in DPL’s balance sheet as of December 31, 2014.

	December 31, 2014 As Filed		Reclassification ASC 835			December 31, 2014 As Adjusted
	(millions of dollars)
Other (within other assets)	$	12	$	(8	)	$	4
Long-term debt		971		(8	)		963

Balance Sheet Classification of Deferred Taxes (ASC 740)

Balance Sheet Classification of Deferred Taxes (ASC 740)

In November 2015, the FASB issued new requirements for the balance sheet classification of deferred taxes. Entities are currently required to present a current and noncurrent deferred tax balance on the balance sheet. Under the new requirements, deferred taxes will only be presented as noncurrent. The new requirements are effective for PHI beginning January 1, 2017, and may be implemented on either a prospective or retrospective basis; however, early adoption is permitted. PHI has elected to early adopt the new guidance on a retrospective basis in the fourth quarter of 2015. The table below illustrates the effects of the retrospective application on reported balances in DPL’s balance sheet as of December 31, 2014.

	December 31, 2014 As Filed		Reclassification ASC 740			December 31, 2014 As Adjusted
	(millions of dollars)
Deferred income taxes, net (within current assets)	$	16	$	(16	)	$	—
Other (within current liabilities)		42		(1	)		41
Deferred income tax liabilities, net		893		(15	)		878

Revenue from Contracts with Customers

Revenue from Contracts with Customers (ASC 606)

In May 2014, the FASB issued new recognition and disclosure requirements for revenue from contracts with customers, which supersedes the existing revenue recognition guidance. The new recognition requirements focus on when the customer obtains control of the goods or services, rather than the current risks and rewards model of recognition. The core principle of the new standard is that an entity will recognize revenue when it transfers goods or services to its customers in an amount that reflects the consideration an entity expects to be entitled to for those goods or services. The new disclosure requirements will include information intended to communicate the nature, amount, timing and any uncertainty of revenue and cash flows from applicable contracts, including any significant judgments and changes in judgments and assets recognized from the costs to obtain or fulfill a contract. Entities will generally be required to make more estimates and use more judgment under the new standard.

The new requirements will be effective for DPL beginning January 1, 2018, and may be implemented either retrospectively for all periods presented, or as a cumulative-effect adjustment as of January 1, 2018. Early adoption is permitted, but not before January 1, 2017. DPL is currently evaluating the potential impact of this new guidance on its financial statements and which implementation approach to select.

Business Combination

Business Combination (ASC 805)

In September 2015, the FASB issued new guidance on adjustments to provisional amounts recognized in a business combination, which are currently recognized on a retrospective basis. Under the new requirements, adjustments will be recognized in the reporting period in which the adjustments are determined. The effects of changes in depreciation, amortization, or other income arising from changes to the provisional amounts, if any, are included in earnings of the reporting period in which the adjustments to the provisional amounts are determined. An entity is also required to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The new requirements will be effective for DPL beginning January 1, 2016, and are required to be implemented on a prospective basis. Early adoption is permitted. DPL currently anticipates it may be affected by the new guidance if its Merger with Exelon is consummated.

Atlantic City Electric Co [Member]

Consolidation Policy

Consolidation Policy

The accompanying consolidated financial statements include the accounts of ACE and its wholly owned subsidiary Atlantic City Electric Transition Funding, LLC (ACE Funding). All intercompany balances and transactions between subsidiaries have been eliminated. ACE uses the equity method to report investments, corporate joint ventures, partnerships, and affiliated companies where it holds an interest and can exercise significant influence over the operations and policies of the entity. Certain transmission and other facilities currently held are consolidated in proportion to ACE’s percentage interest in the facility.

Consolidation of Variable Interest Entities

Consolidation of Variable Interest Entities

ACE assesses its contractual arrangements with variable interest entities (VIEs) to determine whether it is the primary beneficiary and thereby has to consolidate the entities in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 810. The guidance addresses conditions under which an entity should be consolidated based upon variable interests rather than voting interests. See Note (16), “Variable Interest Entities,” for additional information.

Use of Estimates

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the consolidated financial statements and accompanying notes. Although ACE believes that its estimates and assumptions are reasonable, they are based upon information available to management at the time the estimates are made. Actual results may differ significantly from these estimates.

Significant matters that involve the use of estimates include the assessment of contingencies, the calculation of future cash flows and fair value amounts for use in asset impairment calculations, fair value calculations for derivative instruments, pension and other postretirement benefits assumptions, the assessment of the adequacy of the allowance for uncollectible accounts, the assessment of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of unbilled revenue, recognition of changes in network service transmission rates for prior service year costs, accrual of loss contingency liabilities for general litigation and auto and other liability claims, and income tax provisions and reserves. Additionally, ACE is subject to legal, regulatory, and other proceedings and claims that arise in the ordinary course of its business. ACE records an estimated liability for these proceedings and claims when it is probable that a loss has been incurred and the loss is reasonably estimable.

Revenue Recognition

Revenue Recognition

ACE recognizes revenue upon distribution of electricity to its customers, including unbilled revenue for electricity delivered but not yet billed. ACE’s unbilled revenue was $26 million and $32 million as of December 31, 2015 and 2014, respectively, and these amounts are included in Accounts receivable. ACE calculates unbilled revenue using an output-based methodology. This methodology is based on the supply of electricity intended for distribution to customers. The unbilled revenue process requires management to make assumptions and judgments about input factors such as customer sales mix, temperature, and estimated line losses (estimates of electricity expected to be lost in the process of its transmission and distribution to customers). The assumptions and judgments are inherently uncertain and susceptible to change from period to period, and if the actual results differ from the projected results, the impact could be material.

Taxes related to the consumption of electricity by ACE’s customers are a component of ACE’s tariffs and, as such, are billed to customers and recorded in Operating revenue. Accruals for the remittance of these taxes by ACE are recorded in Other taxes.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in ACE’s gross revenues were zero, $1 million and $11 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Income Taxes

Income Taxes

ACE, as an indirect subsidiary of Pepco Holdings, is included in the consolidated federal income tax return of PHI. Federal income taxes are allocated to ACE based upon the taxable income or loss amounts, determined on a separate return basis.

The consolidated financial statements include current and deferred income taxes. Current income taxes represent the amount of tax expected to be reported on ACE’s state income tax returns and the amount of federal income tax allocated from Pepco Holdings.

Deferred income tax assets and liabilities represent the tax effects of temporary differences between the financial statement basis and tax basis of existing assets and liabilities, and they are measured using presently enacted tax rates. The portion of ACE’s deferred tax liability applicable to its utility operations that has not been recovered from utility customers represents income taxes recoverable in the future and is included in Regulatory assets on the consolidated balance sheets. See Note (6), “Regulatory Matters,” for additional information.

Deferred income tax expense generally represents the net change during the reporting period in the net deferred tax liability and deferred recoverable income taxes.

ACE recognizes interest on underpayments and overpayments of income taxes, interest on uncertain tax positions, and tax-related penalties in income tax expense.

Investment tax credits are being amortized to income over the useful lives of the related property.

Cash and Cash Equivalents

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand, cash invested in money market funds and commercial paper held with original maturities of three months or less. Additionally, deposits in PHI’s money pool, which ACE and certain other PHI subsidiaries use to manage short-term cash management requirements, are considered cash equivalents. Deposits in the money pool are guaranteed by PHI. PHI deposits funds in the money pool to the extent that the pool has insufficient funds to meet the needs of its participants, which may require PHI to borrow funds for deposit from external sources.

Restricted Cash Equivalents

Restricted Cash Equivalents

The Restricted cash equivalents included in Current assets and the Restricted cash equivalents included in Other assets consist of (i) cash held as collateral that is restricted from use for general corporate purposes and (ii) cash equivalents that are specifically segregated based on management’s intent to use such cash equivalents for a particular purpose. The classification as current or non-current conforms to the classification of the related liabilities.

Accounts Receivable and Allowance for Uncollectible Accounts

Accounts Receivable and Allowance for Uncollectible Accounts

ACE’s Accounts receivable balance primarily consists of customer accounts receivable arising from the sale of goods and services to customers within its service territories, other accounts receivable, and accrued unbilled revenue. Accrued unbilled revenue represents revenue earned in the current period but not billed to the customer until a future date (usually within one month after the receivable is recorded).

ACE maintains an allowance for uncollectible accounts and changes in the allowance are recorded as an adjustment to Other operation and maintenance expense in the consolidated statements of income. ACE determines the amount of the allowance based on specific identification of material amounts at risk by customer and maintains a reserve based on its historical collection experience. The adequacy of this allowance is assessed on a quarterly basis by evaluating all known factors such as the aging of the receivables, historical collection experience, the economic and competitive environment and changes in the creditworthiness of its customers. Accounts receivable are written off in the period in which the receivable is deemed uncollectible and collection efforts have been exhausted. Recoveries of Accounts receivable previously written off are recorded when received. Although ACE believes its allowance is adequate, it cannot anticipate with any certainty the changes in the financial condition of its customers. As a result, ACE records adjustments to the allowance for uncollectible accounts in the period in which the new information that requires an adjustment to the reserve becomes known.

Inventories

Inventories

Included in inventories are transmission and distribution materials and supplies. ACE utilizes the weighted average cost method of accounting for inventory items. Under this method, an average price is determined for the quantity of units acquired at each price level and is applied to the ending quantity to calculate the total ending inventory balance. Materials and supplies are recorded in Inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed.

Regulatory Assets and Regulatory Liabilities

Regulatory Assets and Regulatory Liabilities

Certain aspects of ACE’s business are subject to regulation by the NJBPU. The transmission of electricity by ACE is regulated by FERC.

Based on the regulatory framework in which it has operated, ACE has historically applied, and in connection with its transmission and distribution business continues to apply, FASB guidance on regulated operations (ASC 980). The guidance allows regulated entities, in appropriate circumstances, to defer the income statement impact of certain costs that are expected to be recovered in future rates through the establishment of regulatory assets and defer certain revenues that are expected to be refunded to customers through the establishment of regulatory liabilities. Management’s assessment of the probability of recovery of regulatory assets requires judgment and interpretation of laws, regulatory commission orders and other factors. If management subsequently determines, based on changes in facts or circumstances, that a regulatory asset is not probable of recovery, the regulatory asset would be eliminated through a charge to earnings.

Leasing Activities

Leasing Activities

ACE’s lease transactions include plant, office space, equipment, software, vehicles and elements of power purchase agreements (PPAs). In accordance with FASB guidance on leases (ASC 840), these leases are classified as operating leases.

Operating Leases

An operating lease in which ACE is the lessee generally results in a level income statement charge over the term of the lease, reflecting the rental payments required by the lease agreement. If rental payments are not made on a straight-line basis, ACE’s policy is to recognize rent expense on a straight-line basis over the lease term unless another systematic and rational allocation basis is more representative of the time pattern in which the leased property is physically employed.

Arrangements Containing a Lease

PPAs are deemed to contain a lease if the arrangement conveys the right to control the use of property, plant or equipment. If so, ACE determines the appropriate lease accounting classification.

Property, Plant and Equipment

Property, Plant and Equipment

Property, plant and equipment is recorded at original cost, including labor, materials, asset retirement costs and other direct and indirect costs, including capitalized interest. The carrying value of Property, plant and equipment is evaluated for impairment whenever circumstances indicate that the carrying value of those assets may not be recoverable. Upon retirement, the cost of regulated property, net of salvage, is charged to accumulated depreciation.

The annual provision for depreciation on electric property, plant and equipment is computed on a straight-line basis using composite rates by classes of depreciable property. Non-operating and other property is generally depreciated on a straight-line basis over the useful lives of the assets. The system-wide composite annual depreciation rates for the years ended December 31, 2015, 2014 and 2013 for ACE’s property were approximately 2.6%, 2.6% and 2.8%, respectively.

Long-Lived Asset Impairment Evaluation

Long-Lived Asset Impairment Evaluation

ACE evaluates certain long-lived assets to be held and used (for example, equipment and real estate) for impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. Examples of such events or changes include a significant decrease in the market price of a long-lived asset or a significant adverse change in the manner in which an asset is being used or its physical condition. A long-lived asset to be held and used is written down to its estimated fair value if the expected future undiscounted cash flow from the asset is less than its carrying value.

For long-lived assets that can be classified as assets to be disposed of by sale, an impairment loss is recognized to the extent that the asset’s carrying value exceeds its estimated fair value including costs to sell.

Capitalized Interest and Allowance for Funds Used During Construction

Capitalized Interest and Allowance for Funds Used During Construction

In accordance with FASB guidance on regulated operations (ASC 980), utilities may capitalize the capital costs of financing the construction of plant and equipment as allowance for funds used during construction (AFUDC). This results in the debt portion of AFUDC being recorded as a reduction of Interest expense and the equity portion of AFUDC being recorded as an increase to Other income in the accompanying consolidated statements of income.

ACE recorded AFUDC for borrowed funds of $1 million, $1 million and less than $1 million for the years ended December 31, 2015, 2014 and 2013, respectively.

ACE recorded amounts for the equity component of AFUDC of $1 million, $1 million and less than $1 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Amortization of Debt Issuance and Reacquisition Costs

Amortization of Debt Issuance and Reacquisition Costs

ACE defers and amortizes debt issuance costs and long-term debt premiums and discounts over the lives of the respective debt issuances. When refinancing or redeeming existing debt, any unamortized premiums, discounts and debt issuance costs, as well as debt redemption costs, are classified as regulatory assets and are amortized generally over the life of the original issue.

Pension and Postretirement Benefit Plans

Pension and Postretirement Benefit Plans

Pepco Holdings sponsors a non-contributory, defined benefit pension plan that covers substantially all employees of ACE and certain employees of other Pepco Holdings subsidiaries (the PHI Retirement Plan). Pepco Holdings also provides supplemental retirement benefits to certain eligible executives and key employees through nonqualified retirement plans and provides certain postretirement health care and life insurance benefits for eligible retired employees.

The PHI Retirement Plan is accounted for in accordance with FASB guidance on retirement benefits (ASC 715).

Reclassifications

Reclassifications

Certain prior period amounts have been reclassified in order to conform to the current period presentation.

Dividend Restrictions

Dividend Restrictions

All of ACE’s shares of outstanding common stock are held by Conectiv, its parent company. In addition to its future financial performance, the ability of ACE to pay dividends to its parent company is subject to limits imposed by: (i) state corporate laws, which impose limitations on the funds that can be used to pay dividends and the regulatory requirement that ACE obtain the prior approval of the NJBPU before dividends can be paid if its equity as a percent of its total capitalization, excluding securitization debt, falls below 30%; (ii) the prior rights of holders of future preferred stock, if any, and existing and future mortgage bonds and other long-term debt issued by ACE and any other restrictions imposed in connection with the incurrence of liabilities; and (iii) certain provisions of ACE’s charter that impose restrictions on payment of common stock dividends for the benefit of preferred stockholders. Currently, the restriction in the ACE charter does not limit its ability to pay common stock dividends. ACE had approximately $235 million and $209 million of retained earnings available for payment of common stock dividends at December 31, 2015 and 2014, respectively. These amounts represent the total retained earnings balances at those dates.

Business Combinations

Business Combinations (ASC 805)

In November 2014, the FASB issued new recognition and disclosure requirements related to pushdown accounting. The new recognition requirements grant an acquired entity (or its subsidiaries) the option to elect whether and when a new accounting and reporting basis (pushdown accounting) will be applied when an acquirer obtains control of the acquired entity. This election may be made by the acquired entity (or its subsidiaries) for future change-in-control events or for its most recent change-in-control event, and the acquired entity will be required to determine whether pushdown accounting will be applied in the reporting period in which the change-in-control event occurs or in a subsequent reporting period.

The new required disclosures include information that enables financial statement users to evaluate the effects of pushdown accounting. Disclosures are required to be made in the period in which pushdown accounting is applied and are expected to include both qualitative and quantitative information.

The new recognition and disclosure requirements became effective on a prospective basis on November 18, 2014.

Presentation of Debt Issuance Costs

Presentation of Debt Issuance Costs (ASC 835)

In April 2015, the FASB issued new guidance for the presentation of debt issuance costs on the balance sheet. Debt issuance costs are currently required to be presented on the balance sheet as assets. However, under the new requirements, these debt issuance costs will be offset against the debt to which the costs relate. The new requirements are effective for ACE beginning January 1, 2016, and are required to be implemented on a retrospective basis for all periods presented; however, early adoption is permitted. ACE has elected to early adopt the new guidance in the fourth quarter of 2015. The table below illustrates the effects of the retrospective application on reported balances in ACE’s consolidated balance sheet as of December 31, 2014.

	December 31, 2014 As Filed		Reclassification ASC 835			December 31, 2014 As Adjusted
	(millions of dollars)
Other (within other assets)	$	12	$	(7	)	$	5
Long-term debt		888		(6	)		882
Transition bonds issued by ACE Funding		171		(1	)		170

Balance Sheet Classification of Deferred Taxes (ASC 740)

Balance Sheet Classification of Deferred Taxes (ASC 740)

In November 2015, the FASB issued new requirements for the balance sheet classification of deferred taxes. Entities are currently required to present a current and noncurrent deferred tax balance on the balance sheet. Under the new requirements, deferred taxes will only be presented as noncurrent. The new requirements are effective for PHI beginning January 1, 2017, and may be implemented on either a prospective or retrospective basis; however, early adoption is permitted. PHI has elected to early adopt the new guidance on a retrospective basis in the fourth quarter of 2015. The table below illustrates the effects of the retrospective application on reported balances in ACE’s consolidated balance sheet as of December 31, 2014.

	December 31, 2014 As Filed		Reclassification ASC 740			December 31, 2014 As Adjusted
	(millions of dollars)
Prepaid expenses and other	$	13	$	(10	)	$	3
Deferred income tax liabilities, net		865		(10	)		855

Revenue from Contracts with Customers

Revenue from Contracts with Customers (ASC 606)

In May 2014, the FASB issued new recognition and disclosure requirements for revenue from contracts with customers, which supersedes the existing revenue recognition guidance. The new recognition requirements focus on when the customer obtains control of the goods or services, rather than the current risks and rewards model of recognition. The core principle of the new standard is that an entity will recognize revenue when it transfers goods or services to its customers in an amount that reflects the consideration an entity expects to be entitled to for those goods or services. The new disclosure requirements will include information intended to communicate the nature, amount, timing and any uncertainty of revenue and cash flows from applicable contracts, including any significant judgments and changes in judgments and assets recognized from the costs to obtain or fulfill a contract. Entities will generally be required to make more estimates and use more judgment under the new standard.

The new requirements will be effective for ACE beginning January 1, 2018, and may be implemented either retrospectively for all periods presented, or as a cumulative-effect adjustment as of January 1, 2018. Early adoption is permitted, but not before January 1, 2017. ACE is currently evaluating the potential impact of this new guidance on its consolidated financial statements and which implementation approach to select.

Business Combination

Business Combination (ASC 805)

In September 2015, the FASB issued new guidance on adjustments to provisional amounts recognized in a business combination, which are currently recognized on a retrospective basis. Under the new requirements, adjustments will be recognized in the reporting period in which the adjustments are determined. The effects of changes in depreciation, amortization, or other income arising from changes to the provisional amounts, if any, are included in earnings of the reporting period in which the adjustments to the provisional amounts are determined. An entity is also required to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The new requirements will be effective for ACE beginning January 1, 2016, and are required to be implemented on a prospective basis. Early adoption is permitted. ACE currently anticipates it may be affected by the new guidance if its Merger with Exelon is consummated.

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Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2015

Accounting Policies [Abstract]

Annual Depreciation Rates

The table below provides system-wide composite annual depreciation rates for the years ended December 31, 2015, 2014 and 2013.

	Transmission and Distribution									Generation
	2015			2014			2013			2015			2014			2013
Pepco		2.3	%		2.3	%		2.2	%		—			—			—
DPL		2.6	%		2.6	%		2.6	%		—			—			—
ACE		2.6	%		2.6	%		2.8	%		—			—			—
Pepco Energy Services		—			—			—			0.6	%		1.2	%		0.4	%

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Newly Adopted Accounting Standards (Tables)

12 Months Ended

Dec. 31, 2015

Presentation Of Debt Issuance Costs [Member]

Effects of the Retrospective Application of Newly Adopted Accounting Standards on Reported Balances

The table below illustrates the effects of the retrospective application on reported balances in PHI’s consolidated balance sheet as of December 31, 2014.

	December 31, 2014 As Filed		Reclassification ASC 835			December 31, 2014 As Adjusted
	(millions of dollars)
Other (within other assets)	$	166	$	(45	)	$	121
Long-term debt		4,441		(44	)		4,397
Transition bonds issued by ACE Funding		171		(1	)		170

Balance Sheet Classification Of Deferred Taxes [Member]

Effects of the Retrospective Application of Newly Adopted Accounting Standards on Reported Balances

The table below illustrates the effects of the retrospective application on reported balances in PHI’s consolidated balance sheet as of December 31, 2014.

	December 31, 2014 As Filed		Reclassification ASC 740			December 31, 2014 As Adjusted
	(millions of dollars)
Deferred income taxes, net (within current assets)	$	50	$	(50	)	$	—
Deferred income taxes, net (within other assets)		—		17			17
Other (within current liabilities)		314		(9	)		305
Deferred income tax liabilities, net		3,266		(24	)		3,242

Atlantic City Electric Co [Member] | Presentation Of Debt Issuance Costs [Member]

Effects of the Retrospective Application of Newly Adopted Accounting Standards on Reported Balances

The table below illustrates the effects of the retrospective application on reported balances in ACE’s consolidated balance sheet as of December 31, 2014.

	December 31, 2014 As Filed		Reclassification ASC 835			December 31, 2014 As Adjusted
	(millions of dollars)
Other (within other assets)	$	12	$	(7	)	$	5
Long-term debt		888		(6	)		882
Transition bonds issued by ACE Funding		171		(1	)		170

Atlantic City Electric Co [Member] | Balance Sheet Classification Of Deferred Taxes [Member]

Effects of the Retrospective Application of Newly Adopted Accounting Standards on Reported Balances

The table below illustrates the effects of the retrospective application on reported balances in ACE’s consolidated balance sheet as of December 31, 2014.

	December 31, 2014 As Filed		Reclassification ASC 740			December 31, 2014 As Adjusted
	(millions of dollars)
Prepaid expenses and other	$	13	$	(10	)	$	3
Deferred income tax liabilities, net		865		(10	)		855

Potomac Electric Power Co [Member] | Presentation Of Debt Issuance Costs [Member]

Effects of the Retrospective Application of Newly Adopted Accounting Standards on Reported Balances

The table below illustrates the effects of the retrospective application on reported balances in Pepco’s balance sheet as of December 31, 2014.

	December 31, 2014 As Filed		Reclassification ASC 835			December 31, 2014 As Adjusted
	(millions of dollars)
Other (within other assets)	$	71	$	(28	)	$	43
Long-term debt		2,124		(28	)		2,096

Potomac Electric Power Co [Member] | Balance Sheet Classification Of Deferred Taxes [Member]

Effects of the Retrospective Application of Newly Adopted Accounting Standards on Reported Balances

The table below illustrates the effects of the retrospective application on reported balances in Pepco’s balance sheet as of December 31, 2014.

	December 31, 2014 As Filed		Reclassification ASC 740			December 31, 2014 As Adjusted
	(millions of dollars)
Deferred income taxes, net (within current assets)	$	14	$	(14	)	$	—
Other (within current liabilities)		102		(9	)		93
Deferred income tax liabilities, net		1,584		(5	)		1,579

Delmarva Power & Light Co/De [Member] | Presentation Of Debt Issuance Costs [Member]

Effects of the Retrospective Application of Newly Adopted Accounting Standards on Reported Balances

The table below illustrates the effects of the retrospective application on reported balances in DPL’s balance sheet as of December 31, 2014.

	December 31, 2014 As Filed		Reclassification ASC 835			December 31, 2014 As Adjusted
	(millions of dollars)
Other (within other assets)	$	12	$	(8	)	$	4
Long-term debt		971		(8	)		963

Delmarva Power & Light Co/De [Member] | Balance Sheet Classification Of Deferred Taxes [Member]

Effects of the Retrospective Application of Newly Adopted Accounting Standards on Reported Balances

The table below illustrates the effects of the retrospective application on reported balances in DPL’s balance sheet as of December 31, 2014.

	December 31, 2014 As Filed		Reclassification ASC 740			December 31, 2014 As Adjusted
	(millions of dollars)
Deferred income taxes, net (within current assets)	$	16	$	(16	)	$	—
Other (within current liabilities)		42		(1	)		41
Deferred income tax liabilities, net		893		(15	)		878

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Segment Information (Tables)

12 Months Ended

Dec. 31, 2015

Segment Reporting [Abstract]

Segment Financial Information for Continuing Operations

Segment financial information for continuing operations at and for the years ended December 31, 2015, 2014 and 2013, is as follows:

	Year Ended December 31, 2015
	Power Delivery			Pepco Energy Services			Corporate and Other (a)			PHI Consolidated
	(millions of dollars)
Operating Revenue	$	4,805		$	223		$	(5	)	$	5,023
Operating Expenses (b)		4,124	(c)		224			2			4,350
Operating Income (Loss)		681			(1	)		(7	)		673
Interest Expense		238			—			42			280
Other Income		36			1			17	(d)		54
Income Tax Expense (Benefit) (e)		177			(4	)		(44	)		129
Net Income from Continuing Operations		302			4			12			318
Total Assets		14,413			221			1,692			16,326
Construction Expenditures	$	1,196		$	3		$	31		$	1,230

(a) Total Assets in this column includes Pepco Holdings’ goodwill balance of $1.4 billion, all of which is allocated to Power Delivery for purposes of assessing impairment. Total assets also include capital expenditures related to certain hardware and software expenditures which primarily benefit Power Delivery. These expenditures are recorded as incurred in Corporate and Other and are allocated to Power Delivery once the assets are placed in service. Corporate and Other includes intercompany amounts of $(5) million for Operating Revenue, $(4) million for Operating Expenses and $(5) million for Interest Expense.

(b) Includes depreciation and amortization expense of $651 million, consisting of $606 million for Power Delivery, $4 million for Pepco Energy Services and $41 million for Corporate and Other.

(c) Includes $46 million ($27 million after-tax) related to gains on sales of land at Pepco.

(d) Includes $15 million ($10 million after-tax) increase in fair value of preferred stock derivative.

(e) Includes tax benefit of $3 million for Power Delivery, $1 million for Pepco Energy Services and $43 million for Corporate and Other associated with the Global Tax Settlement.

	Year Ended December 31, 2014
	Power Delivery		Pepco Energy Services			Corporate and Other (a)			PHI Consolidated
	(millions of dollars)
Operating Revenue	$	4,607	$	278		$	(7	)	$	4,878
Operating Expenses (b)		3,916		354	(c)		4			4,274
Operating Income (Loss)		691		(76	)		(11	)		604
Interest Expense		226		1			41			268
Other Income		40		2			2			44
Income Tax Expense (Benefit)		185		(36	)		(11	)		138
Net Income (Loss) from Continuing Operations		320		(39	)		(39	)		242
Total Assets		13,636		249			1,704			15,589
Construction Expenditures	$	1,144	$	3		$	76		$	1,223

(a) Total Assets in this column includes Pepco Holdings’ goodwill balance of $1.4 billion, all of which is allocated to Power Delivery for purposes of assessing impairment. Total assets also include capital expenditures related to certain hardware and software expenditures which primarily benefit Power Delivery. These expenditures are recorded as incurred in Corporate and Other and are allocated to Power Delivery once the assets are placed in service. Corporate and Other includes intercompany amounts of $(7) million for Operating Revenue, $(7) million for Operating Expenses and $(4) million for Interest Expense.

(b) Includes depreciation and amortization expense of $549 million, consisting of $511 million for Power Delivery, $7 million for Pepco Energy Services and $31 million for Corporate and Other.

(c) Includes impairment losses of $81 million ($48 million after-tax) associated with Pepco Energy Services’ combined heat and power thermal generating facilities and operations in Atlantic City.

	Year Ended December 31, 2013
	Power Delivery		Pepco Energy Services			Corporate and Other (a)			PHI Consolidated
	(millions of dollars)
Operating Revenue	$	4,472	$	203		$	(9	)	$	4,666
Operating Expenses (b)		3,828		201	(c)		(31	)		3,998
Operating Income		644		2			22			668
Interest Expense		228		1			44			273
Other Income		28		3			3			34
Income Tax Expense (d)		155		1			163	(e)		319
Net Income (Loss) from Continuing Operations		289		3			(182	)		110
Total Assets		12,868		337			1,573			14,778
Construction Expenditures	$	1,194	$	4		$	112		$	1,310

(a) Total Assets in this column includes Pepco Holdings’ goodwill balance of $1.4 billion, all of which is allocated to Power Delivery for purposes of assessing impairment. Total assets also include capital expenditures related to certain hardware and software expenditures which primarily benefit Power Delivery. These expenditures are recorded as incurred in Corporate and Other and are allocated to Power Delivery once the assets are placed in service. Corporate and Other includes intercompany amounts of $(10) million for Operating Revenue, $(9) million for Operating Expenses and $(5) million for Interest Expense.

(b) Includes depreciation and amortization expense of $473 million, consisting of $439 million for Power Delivery, $6 million for Pepco Energy Services and $28 million for Corporate and Other.

(c) Includes impairment losses of $4 million ($3 million after-tax) associated with Pepco Energy Services’ landfill gas-fired electric generation facility.

(d) Includes after-tax interest associated with uncertain and effectively settled tax positions allocated to each member of the consolidated group, including a $12 million interest benefit for Power Delivery and interest expense of $66 million for Corporate and Other.

(e) Includes non-cash charges of $101 million representing the establishment of valuation allowances against certain deferred tax assets of PCI included in Corporate and Other.

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Regulatory Matters (Tables)

12 Months Ended

Dec. 31, 2015

Schedule of Regulatory Assets and Regulatory Liabilities

The components of Pepco Holdings’ regulatory asset and liability balances at December 31, 2015 and 2014 are as follows:

	2015		2014
	(millions of dollars)
Regulatory Assets
Pension and other postretirement benefit costs	$	910	$	946
Demand-side management costs		403		329
Smart Grid costs		266		261
Recoverable income taxes		224		274
Securitized stranded costs		202		278
Incremental storm restoration costs		43		51
Deferred debt extinguishment costs		36		42
Deferred energy supply costs		32		73
Recoverable workers’ compensation and long-term disability costs		31		30
MAPP abandonment costs		7		33
Deferred losses on gas derivatives		2		4
Other		90		88
Total Regulatory Assets	$	2,246	$	2,409
Regulatory Liabilities
Asset removal costs	$	211	$	250
Reserves for FERC ROE transmission challenges		32		4
Federal and state tax benefits, related to securitized stranded costs		13		8
Deferred income taxes due to customers		12		44
Deferred energy supply costs		11		3
Other		29		34
Total Regulatory Liabilities	$	308	$	343

Atlantic City Electric Co [Member]

Schedule of Regulatory Assets and Regulatory Liabilities

The components of ACE’s regulatory asset and liability balances at December 31, 2015 and 2014 are as follows:

	2015		2014
	(millions of dollars)
Regulatory Assets
Securitized stranded costs	$	202	$	278
Recoverable income taxes		44		42
Deferred energy supply costs		27		58
Incremental storm restoration costs		18		15
Deferred debt extinguishment costs		7		8
Other		24		26
Total Regulatory Assets	$	322	$	427
Regulatory Liabilities
Federal and state tax benefits, related to securitized stranded costs	$	13	$	8
Reserves for FERC ROE transmission challenges		8		1
Deferred income taxes due to customers		3		3
Other		3		2
Total Regulatory Liabilities	$	27	$	14

Potomac Electric Power Co [Member]

Schedule of Regulatory Assets and Regulatory Liabilities

The components of Pepco’s regulatory asset and liability balances at December 31, 2015 and 2014 are as follows:

	2015		2014
	(millions of dollars)
Regulatory Assets
Demand-side management costs	$	292	$	238
Smart Grid costs		181		175
Recoverable income taxes		142		148
Recoverable workers’ compensation and long-term disability costs		31		30
Incremental storm restoration costs		19		29
Deferred debt extinguishment costs		19		22
MAPP abandonment costs		4		19
Deferred energy supply costs		3		3
Other		29		33
Total Regulatory Assets	$	720	$	697
Regulatory Liabilities
Asset removal costs	$	58	$	84
Reserves for FERC ROE transmission challenges		13		2
Deferred income taxes due to customers		6		4
Deferred energy supply costs		5		3
Other		10		11
Total Regulatory Liabilities	$	92	$	104

Delmarva Power & Light Co/De [Member]

Schedule of Regulatory Assets and Regulatory Liabilities

The components of DPL’s regulatory asset and liability balances at December 31, 2015 and 2014 are as follows:

	2015		2014
	(millions of dollars)
Regulatory Assets
Demand-side management costs	$	111	$	91
Smart Grid costs		85		86
Recoverable income taxes		38		84
COPCO acquisition adjustment		13		18
Deferred debt extinguishment costs		10		12
Incremental storm restoration costs		6		7
MAPP abandonment costs		3		14
Deferred energy supply costs		2		12
Deferred losses on gas derivatives		2		4
Other		38		28
Total Regulatory Assets	$	308	$	356
Regulatory Liabilities
Asset removal costs	$	153	$	166
Reserves for FERC ROE transmission challenges		11		1
Deferred energy supply costs		6		—
Deferred income taxes due to customers		3		37
Other		16		21
Total Regulatory Liabilities	$	189	$	225

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Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2015

Schedule of Property, Plant and Equipment

Property, plant and equipment is comprised of the following:

	Original Cost		Accumulated Depreciation		Net Book Value
	(millions of dollars)
At December 31, 2015
Generation	$	23	$	19	$	4
Distribution		10,051		3,161		6,890
Transmission		3,554		962		2,592
Gas		546		163		383
Construction work in progress		604		—		604
Non-operating and other property		1,440		609		831
Total	$	16,218	$	4,914	$	11,304
At December 31, 2014
Generation	$	104	$	100	$	4
Distribution		9,527		3,021		6,506
Transmission		3,252		934		2,318
Gas		511		153		358
Construction work in progress		688		—		688
Non-operating and other property		1,383		751		632
Total	$	15,465	$	4,959	$	10,506

Capital Lease Assets Recorded within Property, Plant and Equipment

Capital lease assets recorded within Property, Plant and Equipment at December 31, 2015 and 2014 are comprised of the following:

	Original Cost		Accumulated Amortization		Net Book Value
	(millions of dollars)
At December 31, 2015
Transmission	$	76	$	51	$	25
Distribution		76		51		25
Total	$	152	$	102	$	50
At December 31, 2014
Transmission	$	76	$	46	$	30
Distribution		76		46		30
Total	$	152	$	92	$	60

Atlantic City Electric Co [Member]

Schedule of Property, Plant and Equipment

Property, plant and equipment is comprised of the following:

	Original Cost		Accumulated Depreciation		Net Book Value
	(millions of dollars)
At December 31, 2015
Distribution	$	2,012	$	472	$	1,540
Transmission		968		228		740
Construction work in progress		158		—		158
Non-operating and other property		167		64		103
Total	$	3,305	$	764	$	2,541
At December 31, 2014
Generation	$	10	$	9	$	1
Distribution		1,931		450		1,481
Transmission		839		223		616
Construction work in progress		115		—		115
Non-operating and other property		178		78		100
Total	$	3,073	$	760	$	2,313

Potomac Electric Power Co [Member]

Schedule of Property, Plant and Equipment

Property, plant and equipment is comprised of the following:

	Original Cost		Accumulated Depreciation		Net Book Value
	(millions of dollars)
At December 31, 2015
Distribution	$	5,996	$	2,199	$	3,797
Transmission		1,378		475		903
Construction work in progress		318		—		318
Non-operating and other property		399		125		274
Total	$	8,091	$	2,799	$	5,292
At December 31, 2014
Distribution	$	5,668	$	2,082	$	3,586
Transmission		1,306		463		843
Construction work in progress		312		—		312
Non-operating and other property		478		271		207
Total	$	7,764	$	2,816	$	4,948

Capital Lease Assets Recorded within Property, Plant and Equipment

Capital lease assets recorded within Property, plant and equipment at December 31, 2015 and 2014 are comprised of the following:

	Original Cost		Accumulated Amortization		Net Book Value
	(millions of dollars)
At December 31, 2015
Transmission	$	76	$	51	$	25
Distribution		76		51		25
Total	$	152	$	102	$	50
At December 31, 2014
Transmission	$	76	$	46	$	30
Distribution		76		46		30
Total	$	152	$	92	$	60

Delmarva Power & Light Co/De [Member]

Schedule of Property, Plant and Equipment

Property, plant and equipment is comprised of the following:

	Original Cost		Accumulated Depreciation		Net Book Value
	(millions of dollars)
At December 31, 2015
Distribution	$	2,043	$	490	$	1,553
Transmission		1,208		259		949
Gas		546		163		383
Construction work in progress		107		—		107
Non-operating and other property		305		134		171
Total	$	4,209	$	1,046	$	3,163
At December 31, 2014
Distribution	$	1,928	$	489	$	1,439
Transmission		1,107		248		859
Gas		511		153		358
Construction work in progress		125		—		125
Non-operating and other property		275		131		144
Total	$	3,946	$	1,021	$	2,925

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Pension and Other Postretirement Benefits (Tables)

12 Months Ended

Dec. 31, 2015

Schedule of Changes in Benefit Obligations and Plan Assets

The following table shows changes in the benefit obligation and plan assets for the years ended December 31, 2015 and 2014:

	Pension Benefits						Other Postretirement Benefits
	2015			2014			2015			2014
	(millions of dollars)
Change in Benefit Obligation
Benefit obligation as of January 1	$	2,638		$	2,238		$	632		$	574
Service cost		57			44			7			7
Interest cost		109			109			24			26
Actuarial loss (gain)		(151	)		401			(61	)		59
Benefits paid		(163	)		(154	)		(39	)		(34	)
Benefit obligation as of December 31	$	2,490		$	2,638		$	563		$	632
Change in Plan Assets
Fair value of plan assets as of January 1	$	2,236		$	2,116		$	367		$	368
Actual return on plan assets		(61	)		268			1			21
Company and participant contributions		6			6			5			6
Benefits paid by plan		(163	)		(154	)		(25	)		(28	)
Fair value of plan assets as of December 31	$	2,018		$	2,236		$	348		$	367
Funded Status at end of year (plan assets less plan obligations)	$	(472	)	$	(402	)	$	(215	)	$	(265	)

Amounts Recognized in Consolidated Balance Sheets

The following table provides the amounts recorded in PHI’s consolidated balance sheets as of December 31, 2015 and 2014:

	Pension Benefits						Other Postretirement Benefits
	2015			2014			2015			2014
	(millions of dollars)
Regulatory asset	$	870		$	871		$	40		$	75
Current liabilities		(6	)		(6	)		—			—
Pension benefit obligation		(466	)		(396	)		—			—
Other postretirement benefit obligations		—			—			(215	)		(265	)
Deferred income tax liabilities		(162	)		(193	)		70			77
Accumulated other comprehensive loss, net of tax		28			37			—			—
Net amount recorded	$	264		$	313		$	(105	)	$	(113	)

Schedule of Amounts Included in AOCL and Regulatory Assets

Amounts included in AOCL (pre-tax) and Regulatory assets at December 31, 2015 and 2014 consist of:

	Pension Benefits				Other Postretirement Benefits
	2015		2014		2015			2014
	(millions of dollars)
Unrecognized net actuarial loss	$	910	$	925	$	128		$	176
Unamortized prior service cost (credit)		6		8		(88	)		(101	)
Total	$	916	$	933	$	40		$	75
Accumulated other comprehensive loss ($28 million and $37 million, net of tax, at December 31, 2015 and 2014, respectively)	$	46	$	62	$	—		$	—
Regulatory assets		870		871		40			75
Total	$	916	$	933	$	40		$	75

Summary of Changes in Plan Assets and Benefit Obligations Recognized in AOCL and Regulatory Assets

The table below provides the changes in plan assets and benefit obligations recognized in AOCL and Regulatory assets for the years ended December 31, 2015, 2014 and 2013:

	Pension Benefits									Other Postretirement Benefits
	2015			2014			2013			2015			2014			2013
	(millions of dollars)
Amounts amortized during the year:
Amortization of prior service (cost) credit	$	(2	)	$	(2	)	$	(2	)	$	13		$	13		$	11
Amortization of net actuarial loss		(65	)		(45	)		(67	)		(8	)		(3	)		(12	)
Amounts arising during the year:
Current year prior service cost (credit)		—			—			3			—			—			(124	)
Current year actuarial loss (gain)		50			276			(218	)		(39	)		62			(109	)
Total recognized in AOCL and Regulatory assets for the year ended December 31	$	(17	)	$	229		$	(284	)	$	(34	)	$	72		$	(234	)

Components of Net Periodic Benefit Costs

The table below provides the components of net periodic benefit costs recognized for the years ended December 31, 2015, 2014 and 2013:

	Pension Benefits									Other Postretirement Benefits
	2015			2014			2013			2015			2014			2013
	(millions of dollars)
Service cost	$	57		$	44		$	53		$	7		$	7		$	8
Interest cost		109			109			100			24			26			29
Expected return on plan assets		(140	)		(141	)		(145	)		(22	)		(24	)		(20	)
Amortization of prior service cost (credit)		2			2			2			(13	)		(13	)		(11	)
Amortization of net actuarial loss		65			45			67			8			3			12
Net periodic benefit cost	$	93		$	59		$	77		$	4		$	(1	)	$	18

Split of Combined Pension and Other Postretirement Net Periodic Benefit Costs

The table below provides the split of the combined pension and other postretirement net periodic benefit costs among subsidiaries for the years ended December 31, 2015, 2014 and 2013:

	2015		2014		2013
	(millions of dollars)
Pepco	$	30	$	22	$	34
DPL		15		7		18
ACE		15		13		17
Other subsidiaries		37		16		26
Total	$	97	$	58	$	95

Weighted Average Assumptions Used to Determine Benefit Obligations

The following weighted average assumptions were used to determine the benefit obligations at December 31, 2015 and 2014:

	Pension Benefits						Other Postretirement Benefits
	2015			2014			2015			2014
Discount rate		4.65% /4.55	% (a)		4.20	%		4.55	%		4.15	%
Rate of compensation increase		5.00	%		5.00	%		5.00	%		5.00	%
Health care cost trend rate assumed for current year – pre 65		—			—			6.33	%		6.67	%
Health care cost trend rate assumed for current year – post 65		—			—			5.40	%		5.50	%
Rate to which the cost trend rate is assumed to decline for all eligible retirees (the ultimate trend rate)		—			—			5.00	%		5.00	%
Year that the cost trend rate reaches the ultimate trend rate		—			—			2020			2020

(a) The discount rate for the qualified and nonqualified pension plans was 4.65% and 4.55%, respectively.

Summary of Effect of One Percent Change in Assumed Health Care Cost

A one-percentage-point change in assumed health care cost trend rates would have the following effects, in millions of dollars:

	1-Percentage- Point Increase		1-Percentage- Point Decrease
Increase (decrease) in total service and interest cost	$	1	$	(1	)
Increase (decrease) in postretirement benefit obligation	$	15	$	(18	)

Weighted Average Assumptions Used to Determine Net Periodic Benefit Costs

The following weighted average assumptions were used to determine the net periodic benefit cost for the years ended December 31, 2015, 2014 and 2013:

	Pension Benefits									Other Postretirement Benefits
	2015			2014			2013			2015			2014			2013
Discount rate		4.20	%		5.05	%		4.15	%		4.15	%		5.00	%		4.10%/4.95	% (a)
Expected long-term return on plan assets		6.50	%		7.00	%		7.00	%		6.75	%		7.25	%		7.00	%
Rate of compensation increase		5.00	%		5.00	%		5.00	%		5.00	%		5.00	%		5.00	%
Health care cost trend rate		—			—			—			6.67	%		7.00	%		7.50	%

(a) The discount rate was updated for remeasurement to 4.95% on July 1, 2013.

Schedule of Fair Value of Plan Assets

The following tables present the fair values of PHI’s pension and other postretirement benefit plan assets by asset category included in and excluded from the fair value hierarchy levels, as of December 31, 2015 and 2014:

			Fair Value Measurements at December 31, 2015
	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
Asset Category
Pension Plan Assets:
Equity:
Domestic (a)	$	311	$	120	$	191	$	—
International (b)		216		215		—		1
Fixed Income (c)		820		—		810		10
Cash Equivalents (d)		50		50		—		—
		1,397	$	385	$	1,001	$	11
Investments measured at fair value using net asset value as a practical expedient:
Equity:
Domestic (a)		33
Fixed Income (c)		504
Other:
Private Equity		38
Real Estate		46
Pension Plan Assets Total	$	2,018
Other Postretirement Plan Assets:
Equity (e)	$	197	$	197	$	—	$	—
Fixed Income (f)		120		120		—		—
Cash Equivalents		9		9		—		—
		326	$	326	$	—	$	—
Investments measured at fair value using net asset value as a practical expedient:
Equity (e)		22
Postretirement Plan Assets Total	$	348

(a) Domestic equity assets predominantly include domestic common stock and commingled funds.

(b) International equity assets predominantly include foreign common and preferred stock and warrants.

(c) Fixed income assets predominantly include corporate bonds, government bonds, municipal/provincial bonds, collateralized mortgage obligations and commingled funds.

(d) Cash equivalents predominantly include cash investments in short-term investment funds.

(e) Equity assets include domestic and international commingled funds.

(f) Fixed income assets include fixed income commingled funds.

			Fair Value Measurements at December 31, 2014
	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
Asset Category
Pension Plan Assets:
Equity:
Domestic (a)	$	341	$	128	$	213	$	—
International (b)		255		254		—		1
Fixed Income (c)		916		—		905		11
Cash Equivalents (d)		45		45		—		—
		1,557	$	427	$	1,118	$	12
Investments measured at fair value using net asset value as a practical expedient:
Equity:
Domestic (a)		35
Fixed Income (c)		543
Other:
Private Equity		47
Real Estate		54
Pension Plan Assets Total	$	2,236
Other Postretirement Plan Assets:
Equity (e)	$	208	$	208	$	—	$	—
Fixed Income (f)		126		126		—		—
Cash Equivalents		6		6		—		—
		340	$	340	$	—	$	—
Investments measured at fair value using net asset value as a practical expedient:
Equity (e)		27
Postretirement Plan Assets Total	$	367

(a) Domestic equity assets predominantly include domestic common stock and commingled funds.

(b) International equity assets predominantly include foreign common and preferred stock and warrants.

(c) Fixed income assets predominantly include corporate bonds, government bonds, municipal/provincial bonds, collateralized mortgage obligations and commingled funds.

(d) Cash equivalents predominantly include cash investments in short-term investment funds.

(e) Equity assets include domestic and international commingled funds.

(f) Fixed income assets include fixed income commingled funds.

Reconciliation of Fair Value Measurements Using Significant Unobservable Inputs

Reconciliations of the beginning and ending balances of PHI’s fair value measurements using significant unobservable inputs (level 3) for investments in the pension plan for the years ended December 31, 2015 and 2014 are shown below:

	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Equity		Fixed Income			Total Level 3
			(millions of dollars)
Balance as of January 1, 2015	$	1	$	11		$	12
Transfer in (out) of Level 3		—		—			—
Purchases		—		—			—
Sales		—		—			—
Settlements		—		(1	)		(1	)
Unrealized gain (loss)		—		—			—
Realized gain		—		—			—
Balance as of December 31, 2015	$	1	$	10		$	11
	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Equity		Fixed Income			Total Level 3
			(millions of dollars)
Balance as of January 1, 2014	$	1	$	11		$	12
Transfer in (out) of Level 3		—		—			—
Purchases		—		—			—
Sales		—		—			—
Settlements		—		—			—
Unrealized gain (loss)		—		—			—
Realized gain		—		—			—
Balance as of December 31, 2014	$	1	$	11		$	12

Schedule of Estimated Benefit Payments

Estimated future benefit payments to participants in PHI’s pension and other postretirement benefit plans, which reflect expected future service as appropriate, are as follows:

Years	Pension Benefits		Other Postretirement Benefits
	(millions of dollars)
2016	$	143	$	38
2017		143		38
2018		148		38
2019		153		38
2020		158		38
2021 through 2025		836		189

Pension Benefits [Member]

Summary of Plan Asset Allocations

The PHI Retirement Plan asset allocations at December 31, 2015 and 2014, by asset category, were as follows:

Asset Category	Plan Assets at December 31,						Target Plan Asset Allocation
	2015			2014			2015			2014
Equity		28	%		28	%		27	%		27	%
Fixed Income		66	%		65	%		68	%		68	%
Other (real estate, private equity)		6	%		7	%		5	%		5	%
Total		100	%		100	%		100	%		100	%

Other Postretirement Benefits [Member]

Summary of Plan Asset Allocations

PHI’s other postretirement benefit plan asset allocations at December 31, 2015 and 2014, by asset category, were as follows:

Asset Category	Plan Assets at December 31,						Target Plan Asset Allocation
	2015			2014			2015			2014
Equity		63	%		64	%		60	%		60	%
Fixed Income		34	%		34	%		35	%		35	%
Cash		3	%		2	%		5	%		5	%
Total		100	%		100	%		100	%		100	%

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Debt (Tables)

12 Months Ended

Dec. 31, 2015

Components of Long-Term Debt

The components of long-term debt are shown in the table below:

		At December 31,
Interest Rate	Maturity	2015		2014
		(millions of dollars)
First Mortgage Bonds
Pepco:
3.05%	2022	$	200	$	200
6.20% (a)(b)	2022		110		110
3.60%	2024		400		400
5.75% (c)(d)	2034		100		100
5.40% (c)(d)	2035		175		175
6.50% (a)(c)	2037		500		500
7.90%	2038		250		250
4.15%	2043		450		250
4.95%	2043		150		150
ACE:
7.68% (e)	2015 - 2016		2		17
7.75%	2018		250		250
6.80% (d)(f)	2021		39		39
4.35%	2021		200		200
3.375%	2024		150		150
3.50%	2025		150		—
4.875% (a)(f)	2029		23		23
5.80% (d)(g)	2034		120		120
5.80% (d)(g)	2036		105		105
DPL:
5.22% (h)	2016		100		100
3.50%	2023		500		500
4.00%	2042		250		250
4.15%	2045		200		—
Total First Mortgage Bonds			4,424		3,889
Unsecured Tax-Exempt Bonds
DPL:
5.40%	2031		78		78
Total Unsecured Tax-Exempt Bonds			78		78

NOTE: Schedule is continued on next page.

		At December 31,
Interest Rate	Maturity	2015			2014
		(millions of dollars)
Medium-Term Notes (unsecured)
DPL:
7.56% - 7.58%	2017	$	14		$	14
6.81%	2018		4			4
7.61%	2019		12			12
7.72%	2027		10			10
Total Medium-Term Notes (unsecured)			40			40
Notes (secured)
Pepco Energy Services:
6.70% - 7.46%	2015-2018		3			4
Notes (unsecured)
PHI:
2.70%	2015		—			250
5.90%	2016		190			190
6.125%	2017		81			81
7.45%	2032		185			185
DPL:
5.00%	2015		—			100
Total Notes (unsecured)			456			806
Total Long-Term Debt			5,001			4,817
Net unamortized discount			(2	)		(10	)
Unamortized debt issuance costs			(49	)		(44	)
Current portion of long-term debt			(294	)		(366	)
Total Net Long-Term Debt		$	4,656		$	4,397

(a) Represents a series of Collateral First Mortgage Bonds which must be cancelled and released as security for the issuer’s obligations under the corresponding series of issuer notes or tax-exempt bonds, at such time as the issuer does not have any first mortgage bonds outstanding (other than its Collateral First Mortgage Bonds), except that the issuer may not permit such release of collateral unless the issuer substitutes comparable obligations for such collateral.

(b) Represents a series of Collateral First Mortgage Bonds securing a series of senior notes issued by Pepco, which in turn secures a series of tax-exempt bonds issued for the benefit of Pepco.

(c) Represents a series of Collateral First Mortgage Bonds (as defined herein) securing a series of senior notes issued by Pepco.

(d) Represents a series of Collateral First Mortgage Bonds which must be cancelled and released as security for the issuer’s obligations under the corresponding series of issuer notes (as defined herein) or tax-exempt bonds, at such time as the issuer does not have any first mortgage bonds outstanding (other than its Collateral First Mortgage Bonds).

(e) Represents a series of Collateral First Mortgage Bonds securing a series of medium-term notes issued by ACE.

(f) Represents a series of Collateral First Mortgage Bonds securing a series of tax-exempt bonds issued for the benefit of ACE.

(g) Represents a series of Collateral First Mortgage Bonds securing a series of senior notes issued by ACE.

(h) Represents a series of Collateral First Mortgage Bonds securing a series of debt securities issued by DPL.

The outstanding first mortgage bonds issued by each of Pepco, DPL and ACE are issued under a mortgage and deed of trust and are secured by a first lien on substantially all of the issuing company’s property, plant and equipment, except for certain property excluded from the lien of the respective mortgage.

PHI’s long-term debt is subject to certain covenants. As of December 31, 2015, PHI and its subsidiaries were in compliance with all such covenants.

The table above does not separately identify $885 million, $100 million and $227 million in aggregate principal amount of senior notes, medium term notes and other debt securities (issuer notes) issued by each of Pepco, DPL and ACE, respectively, and $110 million and $62 million in aggregate principal amount of tax-exempt bonds issued for the benefit of Pepco and ACE, respectively. These issuer notes are secured by a like amount of first mortgage bonds (Collateral First Mortgage Bonds) of each respective issuer. In addition, these tax-exempt bonds are secured by a like amount of Collateral First Mortgage Bonds issued by the utility subsidiary for whose benefit the tax-exempt bonds were issued. The principal terms of each such series of issuer notes, or the issuer’s obligations in respect of each such series of tax-exempt bonds, are identical to the same terms of the corresponding series of Collateral First Mortgage Bonds. Payments of principal and interest made on a series of such issuer notes, or the satisfaction of the issuer’s obligations in respect of a series of such tax-exempt bonds, satisfy the corresponding obligations on the related series of Collateral First Mortgage Bonds. For these reasons, each such series of Collateral First Mortgage Bonds and the corresponding issuer notes and/or tax-exempt bonds together effectively represent a single financial obligation and are not identified in the table above separately.

Bond Issuances

During 2015, Pepco issued $200 million of 4.15% first mortgage bonds due March 15, 2043, with a 3.9% yield to maturity. Net proceeds from the issuance of the bonds, which included a premium of $8 million, were used by Pepco to repay outstanding commercial paper and for general corporate purposes.

During 2015, DPL issued $200 million of 4.15% first mortgage bonds due May 15, 2045. Net proceeds from the issuance of the bonds were used by DPL to repay outstanding commercial paper and for general corporate purposes.

During 2015, ACE issued $150 million of 3.50% first mortgage bonds due December 1, 2025 in a private placement. The net proceeds from the issuance of the bonds were used by ACE to repay outstanding commercial paper and for general corporate purposes.

Note Retirements

During 2015, ACE retired, at maturity, $15 million of its secured medium-term notes series C. The medium-term notes were secured by a like principal amount of its 7.68% first mortgage bonds due August 24, 2015, which under the mortgage and deed of trust were deemed to be satisfied when the medium-term notes were repaid.

During 2015, DPL retired, at maturity, $100 million of its 5.00% unsecured notes due June 1, 2015.

During 2015, PHI retired, at maturity, $250 million of its 2.70% unsecured notes due October 1, 2015.

Transition Bonds Issued by ACE Funding

The components of transition bonds are shown in the table below:

		At December 31,
Interest Rate	Maturity	2015			2014
		(millions of dollars)
4.91%	2017	$	—		$	17
5.05%	2020		39			51
5.55%	2023		132			147
Total Transition Bonds			171			215
Unamortized debt issuance costs			(1	)		(1	)
Current portion of long-term debt			(46	)		(44	)
Total Net Long-Term Transition Bonds		$	124		$	170

Components of Short-Term Debt

The components of PHI’s short-term debt at December 31, 2015 and 2014 are as follows:

	2015		2014
	(millions of dollars)
Commercial paper	$	658	$	624
Variable rate demand bonds		105		105
Term loan		300		—
Total	$	1,063	$	729

Atlantic City Electric Co [Member]

Components of Long-Term Debt

The components of long-term debt are shown in the table below:

Type of Debt	Interest Rate			Maturity	2015			2014
					(millions of dollars)
First Mortgage Bonds
		7.68	% (a)	2015-2016	$	2		$	17
		7.75	%	2018		250			250
		6.80	% (b)(c)	2021		39			39
		4.35	%	2021		200			200
		3.375	%	2024		150			150
		3.50	%	2025		150			—
		4.875	%(c)(d)	2029		23			23
		5.80	% (b)(e)	2034		120			120
		5.80	% (b)(e)	2036		105			105
Total long-term debt						1,039			904
Net unamortized discount						(1	)		(1	)
Unamortized debt issuance costs						(6	)		(6	)
Current portion of long-term debt						(2	)		(15	)
Total net long-term debt					$	1,030		$	882

(a) Represents a series of Collateral First Mortgage Bonds (as defined herein) securing a series of medium-term notes issued by ACE.

(b) Represents a series of Collateral First Mortgage Bonds which must be cancelled and released as security for ACE’s obligations under the corresponding series of issuer notes (as defined herein) or tax-exempt bonds, at such time as ACE does not have any first mortgage bonds outstanding (other than its Collateral First Mortgage Bonds).

(c) Represents a series of Collateral First Mortgage Bonds securing a series of tax-exempt bonds issued for the benefit of ACE.

(d) Represents a series of Collateral First Mortgage Bonds which must be cancelled and released as security for ACE’s obligations under the corresponding series of issuer notes or tax-exempt bonds, at such time as ACE does not have any first mortgage bonds outstanding (other than its Collateral First Mortgage Bonds), except that ACE may not permit such release of collateral unless ACE substitutes comparable obligations for such collateral.

(e) Represents a series of Collateral First Mortgage Bonds securing a series of senior notes issued by ACE.

The outstanding first mortgage bonds issued by ACE are issued under a mortgage and deed of trust and are secured by a first lien on substantially all of ACE’s property, plant and equipment, except for certain property excluded from the lien of the mortgage.

Maturities of ACE’s long-term debt outstanding at December 31, 2015 are $2 million in 2016, zero in 2017, $250 million in 2018, zero in 2019 and 2020, and $787 million thereafter.

ACE’s long-term debt is subject to certain covenants. As of December 31, 2015, ACE was in compliance with all such covenants.

The table above does not separately identify $227 million in aggregate principal amount of senior notes and medium term notes (issuer notes) issued by ACE and $62 million in aggregate principal amount of tax-exempt bonds issued for the benefit of ACE. These issuer notes and tax-exempt bonds are secured by a like amount of first mortgage bonds (Collateral First Mortgage Bonds) of ACE. The principal terms of each such series of issuer notes, or ACE’s obligations in respect of each such series of tax-exempt bonds, are identical to the same terms of the corresponding series of Collateral First Mortgage Bonds. Payments of principal and interest made on a series of such issuer notes, or the satisfaction of ACE obligations in respect of a series of such tax-exempt bonds, satisfy the corresponding obligations on the related series of Collateral First Mortgage Bonds. For these reasons, each such series of Collateral First Mortgage Bonds and the corresponding issuer notes or tax-exempt bonds together effectively represent a single financial obligation and are not identified in the table above separately.

Bond Issuance

During 2015, ACE issued $150 million of 3.50% first mortgage bonds due December 1, 2025 in a private placement. The net proceeds from the issuance of the bonds were used by ACE to repay outstanding commercial paper and for general corporate purposes.

Bond Retirement

During 2015, ACE retired, at maturity, $15 million of its secured medium-term notes series C. The medium-term notes were secured by a like principal amount of its 7.68% first mortgage bonds due August 24, 2015, which under the mortgage and deed of trust were deemed to be satisfied when the medium-term notes were repaid.

Transition Bonds Issued by ACE Funding

The components of transition bonds are shown in the table below:

Type of Debt	Interest Rate			Maturity	2015			2014
					(millions of dollars)
Transition Bonds
		4.91	%	2017	$	—		$	17
		5.05	%	2020		39			51
		5.55	%	2023		132			147
						171			215
Unamortized debt issuance costs						(1	)		(1	)
Current portion of long-term debt						(46	)		(44	)
Total net long-term Transition Bonds					$	124		$	170

Components of Short-Term Debt

The components of ACE’s short-term debt at December 31, 2015 and 2014 are as follows:

	2015		2014
	(millions of dollars)
Commercial paper	$	5	$	127

Potomac Electric Power Co [Member]

Components of Long-Term Debt

The components of long-term debt are shown in the table below:

Type of Debt	Interest Rate			Maturity	2015			2014
					(millions of dollars)
First Mortgage Bonds
		3.05	%	2022	$	200		$	200
		6.20	%(a)(b)	2022		110			110
		3.60	%	2024		400			400
		5.75	%(c)(d)	2034		100			100
		5.40	%(c)(d)	2035		175			175
		6.50	%(a)(c)	2037		500			500
		7.90	%	2038		250			250
		4.15	%	2043		450			250
		4.95	%	2043		150			150
Total long-term debt						2,335			2,135
Net unamortized discount						(3	)		(11	)
Unamortized debt issuance costs						(31	)		(28	)
Total net long-term debt					$	2,301		$	2,096

(a) Represents a series of Collateral First Mortgage Bonds which must be cancelled and released as security for Pepco’s obligations under the corresponding series of senior notes or tax-exempt bonds, at such time as Pepco does not have any first mortgage bonds outstanding (other than its Collateral First Mortgage Bonds), except that Pepco may not permit such release of collateral unless Pepco substitutes comparable obligations for such collateral.

(b) Represents a series of Collateral First Mortgage Bonds securing a series of senior notes issued by Pepco, which in turn secures a series of tax-exempt bonds issued for the benefit of Pepco.

(c) Represents a series of Collateral First Mortgage Bonds (as defined herein) securing a series of senior notes issued by Pepco.

(d) Represents a series of Collateral First Mortgage Bonds which must be cancelled and released as security for Pepco’s obligations under the corresponding series of senior notes or tax-exempt bonds, at such time as Pepco does not have any first mortgage bonds outstanding (other than its Collateral First Mortgage Bonds).

Components of Short-Term Debt

Pepco’s short-term debt at December 31, 2015 and 2014 consisted of the following:

	2015		2014
	(millions of dollars)
Commercial paper	$	64	$	104

Delmarva Power & Light Co/De [Member]

Components of Long-Term Debt

Long-Term Debt

The components of long-term debt are shown in the table below:

Type of Debt	Interest Rate	Maturity	2015			2014
			(millions of dollars)
First Mortgage Bonds
	5.22%(a)	2016	$	100		$	100
	3.50%	2023		500			500
	4.00%	2042		250			250
	4.15%	2045		200			—
				1,050			850
Unsecured Tax-Exempt Bonds
	5.40%	2031		78			78
				78			78
Medium-Term Notes (unsecured)
	7.56%-7.58%	2017		14			14
	6.81%	2018		4			4
	7.61%	2019		12			12
	7.72%	2027		10			10
				40			40
Notes (unsecured)
	5.00%	2015		—			100
				—			100
Total long-term debt				1,168			1,068
Net unamortized premium				2			3
Unamortized debt issuance costs				(9	)		(8	)
Current portion of long-term debt				(100	)		(100	)
Total net long-term debt			$	1,061		$	963

(a) Represents a series of Collateral First Mortgage Bonds securing a series of debt securities issued by DPL.

Components of Short-Term Debt

The components of DPL’s short-term debt at December 31, 2015 and 2014 are as follows:

	2015		2014
	(millions of dollars)
Commercial paper	$	105	$	106
Variable rate demand bonds		105		105
Total	$	210	$	211

XML

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2015

Provision for Consolidated Income Taxes from Continuing Operations

Provision for Consolidated Income Taxes – Continuing Operations

	For the Year Ended December 31,
	2015			2014			2013
	(millions of dollars)
Current Tax (Benefit) Expense
Federal	$	(3	)	$	(137	)	$	(128	)
State and local		12			(26	)		(9	)
Total Current Tax Expense (Benefit)		9			(163	)		(137	)
Deferred Tax Expense (Benefit)
Federal		92			261			393
State and local		30			41			65
Investment tax credit amortization		(2	)		(1	)		(2	)
Total Deferred Tax Expense		120			301			456
Total Consolidated Income Tax Expense Related to Continuing Operations	$	129		$	138		$	319

Reconciliation of Consolidated Income Tax Expense from Continuing Operations

Reconciliation of Consolidated Income Tax Expense – Continuing Operations

	For the Year Ended December 31,
	2015					2014					2013
	(millions of dollars)
Income tax at Federal statutory rate	$	156		35.0	%	$	133		35.0	%	$	150		35.0	%
Increases (decreases) resulting from:
State income taxes, net of federal effect		27		6.0	%		23		6.1	%		27		6.3	%
Asset removal costs		(14	)	(3.1	)%		(12	)	(3.2	)%		(14	)	(3.3	)%
Change in estimates and interest related to uncertain and effectively settled tax positions		(46	)	(10.3	)%		—		—			56		13.1	%
Deferred tax basis adjustments		7		1.6	%		—		—			—		—
Establishment of valuation allowances related to deferred tax assets		—		—			—		—			101		23.5	%
Merger related costs		4		0.9	%		7		1.8	%		—		—
Other, net		(5	)	(1.2	)%		(13	)	(3.4	)%		(1	)	(0.2	)%
Consolidated Income Tax Expense Related to Continuing Operations	$	129		28.9	%	$	138		36.3	%	$	319		74.4	%

Components of Consolidated Deferred Income Tax Liabilities (Assets)

Components of Consolidated Deferred Tax Liabilities (Assets)

	At December 31,
	2015			2014
	(millions of dollars)
Deferred Tax Liabilities (Assets)
Depreciation and other basis differences related to plant and equipment	$	3,273		$	2,962
Deferred electric service and electric restructuring liabilities		43			67
Federal and state net operating losses		(446	)		(400	)
Valuation allowances on state net operating losses		63			61
Pension and other postretirement benefits		92			116
Deferred taxes on amounts to be collected through future rates		86			94
Other		267			325
Total Deferred Tax Liabilities, net		3,378			3,225
Deferred tax assets included in Other Assets		15			17
Total Consolidated Deferred Tax Liabilities, net	$	3,393		$	3,242

Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits

Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits

	2015			2014			2013
	(millions of dollars)
Balance as of January 1,	$	850		$	831		$	200
Tax positions related to current year:
Additions		—			4			3
Reductions		—			(2	)		—
Tax positions related to prior years:
Additions		13			27			646	(b)
Reductions		(201	)(a)		(10	)		(12	)
Settlements		(628	)(a)		—			(6	)
Balance as of December 31,	$	34		$	850		$	831

(a) Reductions and settlements in 2015 resulted from the Global Tax Settlement. Settlements represent unrecognized tax benefits that were satisfied with cash or use of net operating losses and tax credits. The majority of the settlements were associated with the treatment of the former cross-border energy lease investments of PCI.

(b) These additions of unrecognized tax benefits in 2013 primarily relate to the former cross-border energy lease investments of PCI.

Other Taxes

	2015		2014		2013
	(millions of dollars)
Gross Receipts/Delivery	$	124	$	123	$	133
Property		92		84		77
County Fuel and Energy		143		143		153
Environmental, Use and Other		68		63		65
Total	$	427	$	413	$	428

Atlantic City Electric Co [Member]

Provision for Consolidated Income Taxes from Continuing Operations

Provision for Consolidated Income Taxes

	For the Year Ended December 31,
	2015			2014			2013
	(millions of dollars)
Current Tax (Benefit) Expense
Federal	$	(2	)	$	(7	)	$	(23	)
State and local		3			(2	)		(10	)
Total Current Tax Benefit		1			(9	)		(33	)
Deferred Tax Expense (Benefit)
Federal		25			30			28
State and local		5			7			25
Investment tax credit amortization		—			—			(1	)
Total Deferred Tax Expense		30			37			52
Total Consolidated Income Tax Expense	$	31		$	28		$	19

Reconciliation of Consolidated Income Tax Expense from Continuing Operations

Reconciliation of Consolidated Income Tax Expense

	For the Year Ended December 31,
	2015					2014					2013
	(millions of dollars)
Income tax at Federal statutory rate	$	24		35.0	%	$	26		35.0	%	$	24		35.0	%
Increases (decreases) resulting from:
State income taxes, net of federal effect		4		5.8	%		4		5.5	%		5		7.2	%
Change in estimates and interest related to uncertain and effectively settled tax positions		3		4.3	%		(1	)	(1.4	)%		(9	)	(13.0	)%
Deferred tax basis adjustments		2		2.9	%		—		—			(2	)	(2.9	)%
Investment tax credit amortization		—		—			—		—			(1	)	(1.4	)%
Other, net		(2	)	(3.1	)%		(1	)	(0.7	)%		2		2.6	%
Consolidated Income Tax Expense	$	31		44.9	%	$	28		38.4	%	$	19		27.5	%

Components of Consolidated Deferred Income Tax Liabilities (Assets)

Components of Consolidated Deferred Income Tax Liabilities (Assets)

	As of December 31,
	2015			2014
	(millions of dollars)
Deferred Tax Liabilities (Assets)
Depreciation and other basis differences related to plant and equipment	$	773		$	691
Deferred taxes on amounts to be collected through future rates		17			16
Payment for termination of purchased power contracts with NUGs		34			38
Deferred electric service and electric restructuring liabilities		47			71
Pension and other postretirement benefits		20			25
Federal and state net operating losses		(9	)		(26	)
Other		6			40
Total Consolidated Deferred Tax Liabilities, net	$	888		$	855

Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits

Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits

	2015			2014			2013
	(millions of dollars)
Balance as of January 1	$	13		$	9		$	17
Tax positions related to current year:
Additions		—			1			2
Reductions		—			—			—
Tax positions related to prior years:
Additions		—			5			1
Reductions		(10	)(a)		(2	)		(5	)
Settlements		(3	)(a)		—			(6	)
Balance as of December 31	$	—		$	13		$	9

(a) Reductions and settlements in 2015 resulted from the Global Tax Settlement. Settlements represent unrecognized tax benefits that were satisfied with cash or use of net operating losses and tax credits.

Other Taxes

These amounts are recoverable through rates.

	2015		2014			2013
	(millions of dollars)
Gross Receipts/Delivery	$	—	$	—		$	10
Property		4		3			3
Environmental, Use and Other		1		(1	)		1
Total	$	5	$	2		$	14

Potomac Electric Power Co [Member]

Provision for Consolidated Income Taxes from Continuing Operations

Provision for Income Taxes

	For the Year Ended December 31,
	2015			2014			2013
	(millions of dollars)
Current Tax Benefit
Federal	$	(57	)	$	(79	)	$	(39	)
State and local		6			(3	)		(1	)
Total Current Tax Benefit		(51	)		(82	)		(40	)
Deferred Tax Expense (Benefit)
Federal		125			150			96
State and local		24			24			24
Investment tax credit amortization		—			—			(1	)
Total Deferred Tax Expense		149			174			119
Total Income Tax Expense	$	98		$	92		$	79

Reconciliation of Consolidated Income Tax Expense from Continuing Operations

Reconciliation of Income Tax Expense

	For the Year Ended December 31,
	2015					2014					2013
	(millions of dollars)
Income tax at Federal statutory rate	$	100		35.0	%	$	92		35.0	%	$	80		35.0	%
Increases (decreases) resulting from:
State income taxes, net of federal effect		15		5.3	%		15		5.7	%		13		5.7	%
Asset removal costs		(14	)	(4.9	)%		(12	)	(4.6	)%		(14	)	(6.1	)%
Change in estimates and interest related to uncertain and effectively settled tax positions		(6	)	(2.1	)%		(1	)	(0.4	)%		(3	)	(1.3	)%
Deferred tax basis adjustments		6		2.1	%		—		—			—		—
Other, net		(3	)	(1.0	)%		(2	)	(0.7	)%		3		1.2	%
Income Tax Expense	$	98		34.4	%	$	92		35.0	%	$	79		34.5	%

Components of Consolidated Deferred Income Tax Liabilities (Assets)

Components of Deferred Income Tax Liabilities (Assets)

	At December 31,
	2015			2014
	(millions of dollars)
Deferred Tax Liabilities (Assets)
Depreciation and other basis differences related to plant and equipment	$	1,541		$	1,423
Pension and other postretirement benefits		95			103
Deferred taxes on amounts to be collected through future rates		55			59
Federal and state net operating losses		(141	)		(186	)
Other		171			180
Total Deferred Tax Liabilities, net	$	1,721		$	1,579

Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits

Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits

	2015			2014			2013
	(millions of dollars)
Balance as of January 1	$	97		$	101		$	91
Tax positions related to current year:
Additions		—			1			1
Reductions		—			(2	)		—
Tax positions related to prior years:
Additions		10			1			12
Reductions		(55	)(a)		(4	)		(3	)
Settlements		(40	)(a)		—			—
Balance as of December 31	$	12		$	97		$	101

(a) Reductions and settlements in 2015 resulted from the Global Tax Settlement. Settlements represent unrecognized tax benefits that were satisfied with cash or use of net operating losses and tax credits.

Other Taxes

Other Taxes

Taxes other than income taxes for each year are shown below. These amounts are recoverable through rates.

	2015		2014		2013
	(millions of dollars)
Gross Receipts/Delivery	$	107	$	107	$	108
Property		55		51		45
County Fuel and Energy		143		143		153
Environmental, Use and Other		64		62		62
Total	$	369	$	363	$	368

Delmarva Power & Light Co/De [Member]

Provision for Consolidated Income Taxes from Continuing Operations

Provision for Income Taxes

	For the Year Ended December 31,
	2015			2014			2013
	(millions of dollars)
Current Tax (Benefit) Expense
Federal	$	(26	)	$	(45	)	$	(8	)
State and local		2			—			—
Total Current Tax Benefit		(24	)		(45	)		(8	)
Deferred Tax Expense (Benefit)
Federal		73			99			53
State and local		1			12			12
Investment tax credit amortization		(1	)		(1	)		(1	)
Total Deferred Tax Expense		73			110			64
Total Income Tax Expense	$	49		$	65		$	56

Reconciliation of Consolidated Income Tax Expense from Continuing Operations

Reconciliation of Income Tax Expense

	For the Year Ended December 31,
	2015					2014					2013
	(millions of dollars)
Income tax at Federal statutory rate	$	44		35.0	%	$	59		35.0	%	$	51		35.0	%
Increases (decreases) resulting from:
State income taxes, net of federal effect		7		5.6	%		9		5.3	%		8		5.5	%
Change in estimates and interest related to uncertain and effectively settled tax positions		3		2.4	%		—		—			(1	)	(0.7	)%
Other, net		(5	)	(3.8	)%		(3	)	(1.8	)%		(2	)	(1.2	)%
Income Tax Expense	$	49		39.2	%	$	65		38.5	%	$	56		38.6	%

Components of Consolidated Deferred Income Tax Liabilities (Assets)

Components of Deferred Income Tax Liabilities (Assets)

	As of December 31,
	2015			2014
	(millions of dollars)
Deferred Tax Liabilities (Assets)
Depreciation and other basis differences related to plant and equipment	$	899		$	797
Deferred taxes on amounts to be collected through future rates		15			19
Federal and state net operating losses		(122	)		(115	)
Pension and other postretirement benefits		75			80
Electric restructuring liabilities		(4	)		(4	)
Other		78			101
Total Deferred Tax Liabilities, net	$	941		$	878

Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits

Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits

	2015			2014			2013
	(millions of dollars)
Balance as of January 1	$	22		$	9		$	9
Tax positions related to current year:
Additions		—			1			—
Reductions		—			—			—
Tax positions related to prior years:
Additions		3			13			—
Reductions		(13	)(a)		(1	)		—
Settlements		(9	)(a)		—			—
Balance as of December 31	$	3		$	22		$	9

(a) Reductions and settlements in 2015 resulted from the Global Tax Settlement. Settlements represent unrecognized tax benefits that were satisfied with cash or use of net operating losses and tax credits.

Other Taxes

	2015		2014		2013
	(millions of dollars)
Gross Receipts/Delivery	$	17	$	16	$	15
Property		28		24		24
Environmental, Use and Other		2		2		1
Total	$	47	$	42	$	40

XML

Stock-Based Compensation, Dividend Restrictions, and Calculations of Earnings Per Share of Common Stock (Tables)

12 Months Ended

Dec. 31, 2015

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Schedule of Restricted Stock and Restricted Stock Units

For performance-based restricted stock and restricted stock unit awards, the table reflects awards projected, for purposes of computing the weighted average grant date fair value, to achieve 100% of targeted performance criteria for each outstanding award cycle.

	Number of Shares			Weighted Average Grant Date Fair Value
Balance as of January 1, 2015
Restricted stock		54,165		$	26.80
Performance-based restricted stock		70,276			27.01
Time-based restricted stock units		468,958			19.61
Performance-based restricted stock units		827,981			17.73
Total		1,421,380
Granted during 2015
Performance-based restricted stock		48,347			26.10
Time-based restricted stock units		450,203			27.40
Performance-based restricted stock units		6,188			26.08
Total		504,738
Vested during 2015
Performance-based restricted stock		(93,906	)		26.78
Time-based restricted stock units		(288,429	)		20.61
Performance-based restricted stock units		(424,705	)		17.05
Total		(807,040	)
Forfeited during 2015
Time-based restricted stock units		(2,218	)		27.00
Performance-based restricted stock units		(826	)		19.33
Total		(3,044	)
Balance as of December 31, 2015 (a)
Restricted stock		54,165			26.80
Performance-based restricted stock		24,717			26.10
Time-based restricted stock units		628,514			24.71
Performance-based restricted stock units		408,638			18.56
Total		1,116,034

(a) The balance as of December 31, 2015 does not include 36,110 shares of restricted stock, 113,385 time-based restricted stock units and 104,628 performance-based restricted stock units that were vested for executives and 30,784 time-based restricted stock units that were vested for directors but had not yet settled.

Weighted Average Grant Date Fair Value Per Share

The following table provides the weighted average grant date fair value per share of those awards granted during each of the years ended December 31, 2015, 2014 and 2013:

	2015		2014		2013
Weighted average grant-date fair value of each restricted stock award granted during the year	$	—	$	26.80	$	—
Weighted average grant-date fair value of each performance-based restricted stock award granted during the year	$	26.10	$	27.01	$	—
Weighted average grant-date fair value of each time-based restricted stock unit award granted during the year	$	27.40	$	19.77	$	19.70
Weighted average grant-date fair value of each performance-based restricted stock unit award granted during the year	$	26.08	$	18.53	$	17.03

Dividends Received from Subsidiaries

For the years ended December 31, 2015, 2014 and 2013, dividends paid by PHI’s subsidiaries were as follows:

Subsidiary	2015		2014		2013
	(millions of dollars)
Pepco (paid to PHI)	$	146	$	86	$	46
DPL (paid to Conectiv)		92		100		30
ACE (paid to Conectiv)		12		26		60
Total	$	250	$	212	$	136

Calculation of Earnings Per Share of Common Stock

The numerator and denominator for basic and diluted earnings per share of common stock calculations are shown below.

	For the Year Ended December 31,
	2015		2014		2013
	(millions of dollars, except per share data)
Income (Numerator):
Net income from continuing operations	$	318	$	242	$	110
Net income (loss) from discontinued operations		9		—		(322	)
Net income (loss)	$	327	$	242	$	(212	)
Shares (Denominator) (in millions):
Weighted average shares outstanding for basic computation:
Average shares outstanding		253		251		246
Adjustment to shares outstanding		—		—		—
Weighted Average Shares Outstanding for Computation of Basic Earnings Per Share of Common Stock		253		251		246
Net effect of potentially dilutive shares (a)		1		1		—
Weighted Average Shares Outstanding for Computation of Diluted Earnings Per Share of Common Stock		254		252		246
Basic earnings per share of common stock from continuing operations	$	1.25	$	0.96	$	0.45
Basic earnings (loss) per share of common stock from discontinued operations		0.04		—		(1.31	)
Basic earnings (loss) per share	$	1.29	$	0.96	$	(0.86	)
Diluted earnings per share of common stock from continuing operations	$	1.25	$	0.96	$	0.45
Diluted earnings (loss) per share of common stock from discontinued operations		0.04		—		(1.31	)
Diluted earnings (loss) per share	$	1.29	$	0.96	$	(0.86	)

(a) There were no options to purchase shares of common stock that were excluded from the calculation of diluted earnings per share for the years ended December 31, 2015, 2014 and 2013.

Common Stock Reserved and Unissued

The following table presents Pepco Holdings’ common stock reserved and unissued at December 31, 2015:

Name of Plan	Number of Shares
DRP		4,584,077
Pepco Holdings Long-Term Incentive Plan (a)		6,946,614
Pepco Holdings 2012 Long-Term Incentive Plan		7,136,961
Pepco Holdings Retirement Savings Plan		3,456,261
Total		22,123,913

(a) No further awards will be made under this plan.

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Derivative Instruments and Hedging Activities (Tables)

12 Months Ended

Dec. 31, 2015

Fair Values of Derivative Instruments by Balance Sheet Location

The tables below identify the balance sheet location and fair values of derivative instruments as of December 31, 2015 and 2014:

	As of December 31, 2015
Balance Sheet Caption	Derivatives Designated as Hedging Instruments		Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting		Net Derivative Instruments
						(millions of dollars)
Derivative assets (current assets)	$	—	$	18		$	18		$	—	$	18
Derivative liabilities (current liabilities)		—		(2	)		(2	)		2		—
Net derivative asset	$	—	$	16		$	16		$	2	$	18

	As of December 31, 2014
Balance Sheet Caption	Derivatives Designated as Hedging Instruments		Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting		Net Derivative Instruments
						(millions of dollars)
Derivative assets (current assets)	$	—	$	3		$	3		$	—	$	3
Derivative liabilities (current liabilities)		—		(4	)		(4	)		4		—
Net derivative (liability) asset	$	—	$	(1	)	$	(1	)	$	4	$	3

Schedule of Cash Collateral Offset Against Derivative Positions

The amount of cash collateral that was offset against these derivative positions is as follows:

	December 31, 2015		December 31, 2014
	(millions of dollars)
Cash collateral pledged to counterparties with the right to reclaim (a)	$	2	$	4

(a) Includes cash deposits on commodity brokerage accounts.

Cash Flow Hedges Included in Accumulated Other Comprehensive Loss

The data in the following tables indicate the cumulative net loss after-tax related to terminated cash flow hedges by contract type included in AOCL, the portion of AOCL expected to be reclassified to income during the next 12 months, and the maximum hedge or deferral term:

Contracts	As of December 31, 2015				Maximum Term
	Accumulated Other Comprehensive Loss After-tax		Portion Expected to be Reclassified to Income during the Next 12 Months
	(millions of dollars)
Interest rate	$	8	$	1		200 months

Contracts	As of December 31, 2014				Maximum Term
	Accumulated Other Comprehensive Loss After-tax		Portion Expected to be Reclassified to Income during the Next 12 Months
	(millions of dollars)
Interest rate	$	9	$	1		212 months

Net Unrealized and Realized Derivative Gains (Losses) Deferred as Regulatory Liabilities and Regulatory Assets

The following table shows the net unrealized and net realized derivative gains and losses arising during the period associated with these derivatives that were recognized in the consolidated statements of income (loss) (through Fuel and purchased energy expense) and that were also deferred as regulatory liabilities and regulatory assets, respectively, for the years ended December 31, 2015, 2014 and 2013:

	For the Year Ended December 31,
	2015			2014			2013
	(millions of dollars)
Net unrealized (loss) gain arising during the period	$	(3	)	$	(3	)	$	4
Net realized (loss) gain recognized during the period		(5	)		2			(4	)

Net Outstanding Commodity Forward Contracts That Did Not Qualify for Hedge Accounting

As of December 31, 2015 and 2014, the quantities and positions of DPL’s net outstanding natural gas commodity forward contracts that did not qualify for hedge accounting were:

	December 31, 2015			December 31, 2014
Commodity	Quantity		Net Position	Quantity		Net Position
DPL – Natural gas (one Million British Thermal Units)		4,190,000	Long		3,892,500	Long

Delmarva Power & Light Co/De [Member]

Fair Values of Derivative Instruments by Balance Sheet Location

The tables below identify the balance sheet location and fair values of derivative instruments as of December 31, 2015 and 2014:

	As of December 31, 2015
Balance Sheet Caption	Derivatives Designated as Hedging Instruments		Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting		Net Derivative Instruments
	(millions of dollars)
Derivative liabilities (current liabilities)	$	—	$	(2	)	$	(2	)	$	2	$	—

	As of December 31, 2014
Balance Sheet Caption	Derivatives Designated as Hedging Instruments		Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting		Net Derivative Instruments
	(millions of dollars)
Derivative liabilities (current liabilities)	$	—	$	(4	)	$	(4	)	$	4	$	—

Schedule of Cash Collateral Offset Against Derivative Positions

The amount of cash collateral that was offset against these derivative positions is as follows:

	December 31, 2015		December 31, 2014
	(millions of dollars)
Cash collateral pledged to counterparties with the right reclaim (a)	$	2	$	4

(a) Includes cash deposits on commodity brokerage accounts.

Net Unrealized and Realized Derivative Gains (Losses) Deferred as Regulatory Liabilities and Regulatory Assets

The following table shows the net unrealized and net realized derivative gains and losses arising during the period associated with these derivatives that were recognized in the statements of income (through Purchased energy and Gas purchased expense) and that were also deferred as regulatory liabilities and regulatory assets, respectively, for the years ended December 31, 2015, 2014 and 2013:

	For the Year Ended December 31,
	2015			2014			2013
	(millions of dollars)
Net unrealized (loss) gain arising during the period	$	(3	)	$	(3	)	$	1
Net realized (loss) gain recognized during the period		(5	)		2			(4	)

Net Outstanding Commodity Forward Contracts That Did Not Qualify for Hedge Accounting

As of December 31, 2015 and 2014, the quantities and positions of DPL’s net outstanding natural gas commodity forward contracts that did not qualify for hedge accounting were:

	December 31, 2015			December 31, 2014
Commodity	Quantity		Net Position	Quantity		Net Position
Natural Gas (One Million British Thermal Units)		4,190,000	Long		3,892,500	Long

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Fair Value Disclosures (Tables)

12 Months Ended

Dec. 31, 2015

Fair Value of Financial Assets and Liabilities Measured on Recurring Basis

The following tables set forth, by level within the fair value hierarchy, PHI’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2015 and 2014. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. PHI’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Fair Value Measurements at December 31, 2015
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1) (a)		Significant Other Observable Inputs (Level 2) (a)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Derivative instruments
Preferred stock	$	18	$	—	$	—	$	18
Cash equivalents and restricted cash equivalents
Treasury fund		42		42		—		—
Executive deferred compensation plan assets
Money market funds and short-term investments		27		12		15		—
Life insurance contracts		46		—		27		19
Total	$	133	$	54	$	42	$	37
LIABILITIES
Derivative instruments (b)
Natural gas (c)	$	2	$	2	$	—	$	—
Executive deferred compensation plan liabilities
Life insurance contracts		30		—		30		—
Total	$	32	$	2	$	30	$	—

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2015.

(b) The fair values of derivative liabilities reflect netting by counterparty before the impact of collateral.

(c) Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.

	Fair Value Measurements at December 31, 2014
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1) (a)		Significant Other Observable Inputs (Level 2) (a)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Derivative instruments
Preferred stock	$	3	$	—	$	—	$	3
Restricted cash equivalents
Treasury fund		38		38		—		—
Executive deferred compensation plan assets
Money market funds and short-term investments		35		14		21		—
Life insurance contracts		46		—		27		19
Total	$	122	$	52	$	48	$	22
LIABILITIES
Derivative instruments (b)
Natural gas (c)	$	4	$	4	$	—	$	—
Executive deferred compensation plan liabilities
Life insurance contracts		30		—		30		—
Total	$	34	$	4	$	30	$	—

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2014.

(b) The fair values of derivative liabilities reflect netting by counterparty before the impact of collateral.

(c) Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.

Reconciliations of Fair Value Measurements Using Significant Unobservable Inputs (Level 3)

Reconciliations of the beginning and ending balances of PHI’s fair value measurements using significant unobservable inputs (Level 3) for the years ended December 31, 2015 and 2014 are shown below:

	Year Ended December 31,
	2015					2014
	Preferred Stock		Life Insurance Contracts			Preferred Stock		Life Insurance Contracts
	(millions of dollars)
Balance as of January 1	$	3	$	19		$	—	$	19
Total gains (losses) (realized and unrealized):
Included in income		15		5			—		3
Included in accumulated other comprehensive loss		—		—			—		—
Included in regulatory liabilities		—		—			—		—
Purchases		—		—			—		—
Issuances		—		(3	)		3		(3	)
Settlements		—		(2	)		—		—
Transfers in (out) of level 3		—		—			—		—
Balance as of December 31	$	18	$	19		$	3	$	19

Gains on Level 3 Instruments Included in Income

The breakdown of realized and unrealized gains on level 3 instruments included in income as a component of Other income or Other operation and maintenance expense for the periods below were as follows:

	Year Ended December 31,
	2015		2014
	(millions of dollars)
Total net gains included in income for the period	$	20	$	3
Change in unrealized gains relating to assets still held at reporting date	$	18	$	3

Fair Value of Financial Liabilities Measured on Recurring Basis

	Fair Value Measurements at December 31, 2015
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	5,523	$	—	$	4,941	$	582
Transition Bonds (b)		185		—		185		—
Long-term project funding		5		—		—		5
Total	$	5,713	$	—	$	5,126	$	587

(a) The carrying amount for Long-term debt, net of unamortized discount, was $4,999 million as of December 31, 2015.

(b) The carrying amount for Transition Bonds, including amounts due within one year, was $171 million as of December 31, 2015.

	Fair Value Measurements at December 31, 2014
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	5,583	$	—	$	5,136	$	447
Transition Bonds (b)		235		—		235		—
Long-term project funding		28		—		—		28
Total	$	5,846	$	—	$	5,371	$	475

(a) The carrying amount for Long-term debt, net of unamortized discount, was $4,807 million as of December 31, 2014.

(b) The carrying amount for Transition Bonds, including amounts due within one year, was $215 million as of December 31, 2014.

Atlantic City Electric Co [Member]

Fair Value of Financial Assets and Liabilities Measured on Recurring Basis

The following tables set forth by level within the fair value hierarchy ACE’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2015 and 2014. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. ACE’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Fair Value Measurements at December 31, 2015
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1) (a)		Significant Other Observable Inputs (Level 2) (a)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Cash equivalents and restricted cash equivalents
Treasury funds	$	30	$	30	$	—	$	—

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2015.

	Fair Value Measurements at December 31, 2014
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1) (a)		Significant Other Observable Inputs (Level 2) (a)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Cash equivalents and restricted cash equivalents
Treasury funds	$	24	$	24	$	—	$	—

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2014.

Fair Value of Financial Liabilities Measured on Recurring Basis

	Fair Value Measurements at December 31, 2015
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	1,140	$	—	$	860	$	280
Transition Bonds (b)		185		—		185		—
Total	$	1,325	$	—	$	1,045	$	280

(a) The carrying amount for Long-term debt, net of unamortized discount, was $1,038 million as of December 31, 2015.

(b) The carrying amount for Transition Bonds, including amounts due within one year, was $171 million as of December 31, 2015.

	Fair Value Measurements at December 31, 2014
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	1,035	$	—	$	903	$	132
Transition Bonds (b)		235		—		235		—
Total	$	1,270	$	—	$	1,138	$	132

(a) The carrying amount for Long-term debt, net of unamortized discount, was $903 million as of December 31, 2014.

(b) The carrying amount for Transition Bonds, including amounts due within one year, was $215 million as of December 31, 2014.

Potomac Electric Power Co [Member]

Fair Value of Financial Assets and Liabilities Measured on Recurring Basis

The following tables set forth, by level within the fair value hierarchy, Pepco’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2015 and 2014. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Pepco’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Fair Value Measurements at December 31, 2015
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1) (a)		Significant Other Observable Inputs (Level 2) (a)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Cash equivalents and restricted cash equivalents
Treasury funds	$	2	$	2	$	—	$	—
Executive deferred compensation plan assets
Money market funds and short-term investments		26		11		15		—
Life insurance contracts		42		—		23		19
Total	$	70	$	13	$	38	$	19
LIABILITIES
Executive deferred compensation plan liabilities
Life insurance contracts	$	6	$	—	$	6	$	—
Total	$	6	$	—	$	6	$	—

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2015.

	Fair Value Measurements at December 31, 2014
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1) (a)		Significant Other Observable Inputs (Level 2) (a)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Restricted cash equivalents
Treasury fund	$	5	$	5	$	—	$	—
Executive deferred compensation plan assets
Money market funds and short-term investments		34		13		21		—
Life insurance contracts		41		—		23		18
Total	$	80	$	18	$	44	$	18
LIABILITIES
Executive deferred compensation plan liabilities
Life insurance contracts	$	7	$	—	$	7	$	—
Total	$	7	$	—	$	7	$	—

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2014.

Reconciliations of Fair Value Measurements Using Significant Unobservable Inputs (Level 3)

Reconciliations of the beginning and ending balances of Pepco’s fair value measurements using significant unobservable inputs (Level 3) for the years ended December 31, 2015 and 2014 are shown below.

	2015			2014
	Life Insurance Contracts			Life Insurance Contracts
	(millions of dollars)
Balance as of January 1	$	18		$	18
Total gains (losses) (realized and unrealized):
Included in income		5			3
Included in accumulated other comprehensive loss		—			—
Purchases		—			—
Issuances		(3	)		(3	)
Settlements		(1	)		—
Transfers in (out) of level 3		—			—
Balance as of December 31	$	19		$	18

Gains on Level 3 Instruments Included in Income

The breakdown of realized and unrealized gains on level 3 instruments included in income as a component of Other income or Other operation and maintenance expense for the periods below were as follows:

	Year Ended December 31,
	2015		2014
	(millions of dollars)
Total gains included in income for the period	$	5	$	3
Change in unrealized gains relating to assets still held at reporting date	$	3	$	3

Fair Value of Financial Liabilities Measured on Recurring Basis

	Fair Value Measurements at December 31, 2015
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	2,673	$	—	$	2,673	$	—

(a) The carrying amount for Long-term debt, net of unamortized discount, was $2,332 million as of December 31, 2015.

	Fair Value Measurements at December 31, 2014
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	2,624	$	—	$	2,624	$	—
Project funding		12		—		—		12
Total	$	2,636	$	—	$	2,624	$	12

(a) The carrying amount for Long-term debt, net of unamortized discount, was $2,124 million as of December 31, 2014.

Delmarva Power & Light Co/De [Member]

Fair Value of Financial Assets and Liabilities Measured on Recurring Basis

The following tables set forth, by level within the fair value hierarchy, DPL’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2015 and 2014. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. DPL’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Fair Value Measurements at December 31, 2015
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1) (a)		Significant Other Observable Inputs (Level 2) (a)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Derivative instruments (b)
Natural gas (c)	$	2	$	2	$	—	$	—
Executive deferred compensation plan liabilities
Life insurance contracts		1		—		1		—
Total	$	3	$	2	$	1	$	—

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2015.

(b) The fair value of derivative liabilities reflect netting by counterparty before the impact of collateral.

(c) Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.

	Fair Value Measurements at December 31, 2014
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1) (a)		Significant Other Observable Inputs (Level 2) (a)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Restricted cash equivalents
Treasury funds	$	5	$	5	$	—	$	—
Executive deferred compensation plan assets
Money market funds		1		1		—		—
Life insurance contracts		1		—		—		1
Total	$	7	$	6	$	—	$	1
LIABILITIES
Derivative instruments (b)
Natural gas (c)	$	4	$	4	$	—	$	—
Executive deferred compensation plan liabilities
Life insurance contracts		1		—		1		—
Total	$	5	$	4	$	1	$	—

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2014.

(b) The fair value of derivative liabilities reflect netting by counterparty before the impact of collateral.

(c) Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.

Reconciliations of Fair Value Measurements Using Significant Unobservable Inputs (Level 3)

Reconciliations of the beginning and ending balances of DPL’s fair value measurements using significant unobservable inputs (Level 3) for the years ended December 31, 2015 and 2014 are shown below:

	Year Ended December 31, 2015			Year Ended December 31, 2014
	Life Insurance Contracts			Life Insurance Contracts
	(millions of dollars)
Balance as of January 1	$	1		$	1
Total gains (losses) (realized and unrealized):
Included in income		—			—
Included in accumulated other comprehensive loss		—			—
Included in regulatory liabilities		—			—
Purchases		—			—
Issuances		—			—
Settlements		(1	)		—
Transfers in (out) of Level 3		—			—
Balance as of December 31	$	—		$	1

Fair Value of Financial Liabilities Measured on Recurring Basis

	Fair Value Measurements at December 31, 2015
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	1,183	$	—	$	1,080	$	103

(a) The carrying amount for Long-term debt, including unamortized premium, was $1,170 million as of December 31, 2015.

	Fair Value Measurements at December 31, 2014
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	1,123	$	—	$	1,016	$	107

(a) The carrying amount for Long-term debt, including unamortized premium, was $1,071 million as of December 31, 2014.

XML

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2015

Schedule of Accrued Liabilities for Environmental Exposures

The total accrued liabilities for the environmental contingencies described below of PHI and its subsidiaries at December 31, 2015 are summarized as follows:

				Legacy Generation
	Transmission and Distribution			Regulated			Non-Regulated		Total
				(millions of dollars)
Balance as of January 1	$	17		$	6		$	5	$	28
Accruals		7			3			—		10
Payments		(4	)		(1	)		—		(5	)
Balance as of December 31		20			8			5		33
Less amounts in Other Current Liabilities		3			1			—		4
Amounts in Other Deferred Credits	$	17		$	7		$	5	$	29

Schedule of Commitments and Obligations

As of December 31, 2015, PHI and its subsidiaries were parties to a variety of agreements pursuant to which they were guarantors. The commitments and obligations were as follows:

	Guarantor
	PHI		Pepco		DPL		ACE		Total
	(millions of dollars)
Guarantees associated with disposal of Conectiv Energy assets (a)	$	13	$	—	$	—	$	—	$	13
Guaranteed lease residual values (b)		3		5		6		5		19
Total	$	16	$	5	$	6	$	5	$	32

(a) Represents guarantees by PHI of Conectiv Energy’s derivative portfolio transferred in connection with the disposition of Conectiv Energy’s wholesale business. The derivative portfolio guarantee is currently $13 million and covers Conectiv Energy’s performance prior to the assignment. The guarantee will terminate in 2016.

(b) Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $52 million, $9 million of which is a guarantee by PHI, $13 million by Pepco, $16 million by DPL and $14 million by ACE. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.

Atlantic City Electric Co [Member]

Schedule of Accrued Liabilities for Environmental Exposures

The total accrued liabilities for the environmental contingencies of ACE described below at December 31, 2015 are summarized as follows:

	Legacy Generation - Regulated
	(millions of dollars)
Balance as of January 1	$	1
Accruals		—
Payments		—
Balance as of December 31		1
Less amounts in Other Current Liabilities		—
Amounts in Other Deferred Credits	$	1

Potomac Electric Power Co [Member]

Schedule of Accrued Liabilities for Environmental Exposures

The total accrued liabilities for the environmental contingencies of Pepco described below at December 31, 2015 are summarized as follows:

	Transmission and Distribution			Legacy Generation - Regulated		Total
	(millions of dollars)
Balance as of January 1	$	16		$	3	$	19
Accruals		4			3		7
Payments		(2	)		—		(2	)
Balance as of December 31		18			6		24
Less amounts in Other Current Liabilities		2			—		2
Amounts in Other Deferred Credits	$	16		$	6	$	22

Delmarva Power & Light Co/De [Member]

Schedule of Accrued Liabilities for Environmental Exposures

The total accrued liabilities for the environmental contingencies of DPL described below at December 31, 2015 are summarized as follows:

	Transmission and Distribution			Legacy Generation - Regulated			Total
	(millions of dollars)
Balance as of January 1	$	1		$	2		$	3
Accruals		3			—			3
Payments		(2	)		(1	)		(3	)
Balance as of December 31		2			1			3
Less amounts in Other Current Liabilities		1			1			2
Amounts in Other Deferred Credits	$	1		$	—		$	1

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Accumulated Other Comprehensive Loss (Tables)

12 Months Ended

Dec. 31, 2015

Equity [Abstract]

Schedule of Components of Other Comprehensive Loss

The components of Pepco Holdings’ AOCL relating to continuing and discontinued operations are as follows. For additional information, see the consolidated statements of comprehensive income.

	Year Ended December 31,
	2015			2014			2013
	(millions of dollars)
Balance as of January 1	$	(46	)	$	(34	)	$	(48	)
Treasury Lock
Balance as of January 1		(9	)		(9	)		(10	)
Amount of pre-tax loss reclassified to Interest expense		1			1			1
Income tax expense		—			1			—
Balance as of December 31		(8	)		(9	)		(9	)
Pension and Other Postretirement Benefits
Balance as of January 1		(37	)		(25	)		(32	)
Amount of amortization of net prior service cost and actuarial loss reclassified to Other operation and maintenance expense		6			5			5
Amount of net prior service cost and actuarial gain (loss) arising during the year		9			(25	)		8
Income tax (benefit) expense		6			(8	)		6
Balance as of December 31		(28	)		(37	)		(25	)
Commodity Derivatives
Balance as of January 1		—			—			(6	)
Amount of net pre-tax loss reclassified to Income (loss) from discontinued operations before income tax		—			—			10
Income tax expense		—			—			4
Balance as of December 31		—			—			—
Balance as of December 31	$	(36	)	$	(46	)	$	(34	)

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Quarterly Financial Information (Tables)

12 Months Ended

Dec. 31, 2015

Schedule of Quarterly Financial Information

The totals of the four quarterly basic and diluted earnings per common share amounts may not equal the basic and diluted earnings per common share for the year due to changes in the number of shares of common stock outstanding during the year.

	2015
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(millions of dollars, except per share amounts)
Total Operating Revenue	$	1,371		$	1,140		$	1,362		$	1,150		$	5,023
Total Operating Expenses		1,229			1,001			1,179			941	(b)		4,350
Operating Income		142			139			183			209			673
Other Expenses		(59	)		(59	)		(43	)(a)		(65)			(226)
Income from Continuing Operations Before Income Tax Expense		83			80			140			144			447
Income Tax Expense Related to Continuing Operations		30			27			49			23	(c)		129
Net Income From Continuing Operations		53			53			91			121			318
Income from Discontinued Operations, net of taxes		—			—			—			9	(d)		9
Net Income	$	53		$	53		$	91		$	130		$	327
Basic and Diluted Earnings Per Share of Common Stock:
Earnings Per Share of Common Stock from Continuing Operations	$	0.21		$	0.21		$	0.36		$	0.48		$	1.25
Earnings Per Share of Common Stock from Discontinued Operations	$	—		$	—		$	—		$	0.03		$	0.04
Earnings Per Share of Common Stock	$	0.21		$	0.21		$	0.36		$	0.51		$	1.29
Cash Dividends Per Share of Common Stock	$	0.27		$	0.27		$	0.27		$	0.27		$	1.08

(a) Includes $15 million ($10 million after-tax) increase in fair value of preferred stock derivative.

(b) Includes gains of $46 million ($27 million after-tax) associated with the sale of Pepco non-utility land.

(c) Includes income tax benefit of $47 million associated with the Global Tax Settlement and a tax charge of $7 million to correct prior period errors.

(d) Includes income tax benefit of $9 million associated with the Global Tax Settlement.

	2014
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(millions of dollars, except per share amounts)
Total Operating Revenue (a)	$	1,330		$	1,117		$	1,313		$	1,118		$	4,878
Total Operating Expenses (b)		1,157			966			1,147			1,004	(c)		4,274
Operating Income		173			151			166			114			604
Other Expenses		(52	)		(53	)		(53	)		(66	)		(224	)
Income from Continuing Operations Before Income Tax Expense		121			98			113			48			380
Income Tax Expense Related to Continuing Operations		46			45			34			13			138
Net Income	$	75		$	53		$	79		$	35		$	242
Basic and Diluted Earnings Per Share of Common Stock	$	0.30		$	0.21		$	0.31		$	0.14		$	0.96
Cash Dividends Per Share of Common Stock	$	0.27		$	0.27		$	0.27		$	0.27		$	1.08

(a) During the fourth quarter of 2014, ACE reversed unbilled revenue of $3 million ($2 million after-tax) to correct an error that had overstated operating revenue in the third quarter of 2014.

(b) Includes pre-tax impairment losses of $53 million ($32 million after-tax) and $28 million ($16 million after-tax) in the third and fourth quarters of 2014, respectively, at Pepco Energy Services associated with its combined heat and power thermal generating facilities and operations in Atlantic City.

(c) Includes a charge of $3 million ($2 million after-tax) to correct a prior period error related to the recoverability of certain regulatory assets at ACE.

Atlantic City Electric Co [Member]

Schedule of Quarterly Financial Information

Quarterly data normally vary seasonally because of temperature variations and differences between summer and winter rates. Therefore, comparisons by quarter within a year are not meaningful.

	2015
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(millions of dollars)
Total Operating Revenue	$	333		$	286		$	387		$	292		$	1,298
Total Operating Expenses		313			254			349			252			1,168
Operating Income		20			32			38			40			130
Other Expenses		(14	)		(15	)		(17	)		(15	)		(61	)
Income Before Income Tax Expense		6			17			21			25			69
Income Tax Expense		2			7			7			15	(a)		31
Net Income	$	4		$	10		$	14		$	10		$	38

(a) Includes income tax charge of $3 million associated with the Global Tax Settlement and a tax charge of $2 million to correct prior period errors.

	2014
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(millions of dollars)
Total Operating Revenue (a)	$	340		$	253		$	347		$	273		$	1,213
Total Operating Expenses		309			228			295			246	(b)		1,078
Operating Income		31			25			52			27			135
Other Expenses		(15	)		(15	)		(15	)		(17	)		(62	)
Income Before Income Tax Expense		16			10			37			10			73
Income Tax Expense		6			4			14			4			28
Net Income	$	10		$	6		$	23		$	6		$	45

(a) During the fourth quarter of 2014, ACE reversed unbilled revenue of $3 million ($2 million after-tax) to correct an error that had overstated operating revenue in the third quarter of 2014.

(b) Includes a charge of $3 million ($2 million after-tax) to correct a prior period error related to the recoverability of certain regulatory assets.

Potomac Electric Power Co [Member]

Schedule of Quarterly Financial Information

Quarterly data normally vary seasonally because of temperature variations and differences between summer and winter rates. Therefore, comparisons by quarter within a year are not meaningful.

	2015
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(millions of dollars)
Total Operating Revenue	$	556		$	518		$	612		$	503		$	2,189
Total Operating Expenses		493			435			497			379	(a)		1,804
Operating Income		63			83			115			124			385
Other Expenses		(25	)		(23	)		(23	)		(29	)		(100	)
Income Before Income Tax Expense		38			60			92			95			285
Income Tax Expense		12			18			32			36	(b)		98
Net Income	$	26		$	42		$	60		$	59		$	187

(a) Includes gains of $46 million ($27 million after-tax) associated with the sale of non-utility land.

(b) Includes net income tax benefit of $9 million associated with the Global Tax Settlement, a tax charge of $3 million for an uncertain tax position not related to the Global Tax Settlement and a tax charge of $6 million to correct prior period errors.

	2014
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(millions of dollars)
Total Operating Revenue	$	535		$	508		$	587		$	471		$	2,101
Total Operating Expenses		469			414			462			408			1,753
Operating Income		66			94			125			63			348
Other Expenses		(18	)		(20	)		(20	)		(27	)		(85	)
Income Before Income Tax Expense		48			74			105			36			263
Income Tax Expense		16			28			38			10			92
Net Income	$	32		$	46		$	67		$	26		$	171

Delmarva Power & Light Co/De [Member]

Schedule of Quarterly Financial Information

Quarterly data normally vary seasonally because of temperature variations and differences between summer and winter rates. Therefore, comparisons by quarter within a year are not meaningful.

	2015
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(millions of dollars)
Total Operating Revenue	$	423		$	275		$	317		$	303		$	1,318
Total Operating Expenses		361			251			285			256			1,153
Operating Income		62			24			32			47			165
Other Expenses		(9	)		(11	)		(8	)		(12	)		(40	)
Income Before Income Tax Expense		53			13			24			35			125
Income Tax Expense		21			5			9			14	(a)		49
Net Income	$	32		$	8		$	15		$	21		$	76

(a) Includes income tax charge of $3 million associated with the Global Tax Settlement.

	2014
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(millions of dollars)
Total Operating Revenue	$	397		$	279		$	309		$	308		$	1,293
Total Operating Expenses		326			239			264			257			1,086
Operating Income		71			40			45			51			207
Other Expenses		(9	)		(8	)		(9	)		(12	)		(38	)
Income Before Income Tax Expense		62			32			36			39			169
Income Tax Expense		25			13			13			14			65
Net Income	$	37		$	19		$	23		$	25		$	104

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Discontinued Operations (Tables)

12 Months Ended

Dec. 31, 2015

Income (Loss) from Discontinued Operations, net of income taxes

PHI’s income (loss) from discontinued operations, net of income taxes, is comprised of the following:

	For the Year Ended December 31,
	2015		2014		2013
	(millions of dollars)
Cross-border energy lease investments	$	9	$	—	$	(327	)
Pepco Energy Services’ retail electric and natural gas supply businesses		—		—		5
Income (loss) from discontinued operations, net of income taxes	$	9	$	—	$	(322	)

Discontinued Operations [Member]

Derivative Gain (Loss) for Retail Electric and Natural Gas Supply Businesses

For the years ended December 31, 2015, 2014, and 2013, the amount of the derivative gain (loss) for the retail electric and natural gas supply businesses of Pepco Energy Services recognized in Income (loss) from discontinued operations, net of income taxes is provided in the table below:

	For the Year Ended December 31,
	2015		2014		2013
	(millions of dollars)
Reclassification of mark-to-market to realized on settlement of contracts	$	—	$	—	$	10
Unrealized mark-to-market loss		—		—		—
Total net gain	$	—	$	—	$	10

Cross-Border Energy Lease Investments [Member]

Income (Loss) from Discontinued Operations, net of income taxes

The operating results for the cross-border energy lease investments are as follows:

	For the Year Ended December 31,
	2015		2014		2013
	(millions of dollars)
Operating revenue from PHI’s cross-border energy lease investments	$	—	$	—	$	7
Non-cash charge to reduce carrying value of PHI’s cross-border energy lease investments		—		—		(373	)
Total operating revenue	$	—	$	—	$	(366	)
Income (loss) from operations of discontinued operations, net of income taxes (a)	$	9	$	—	$	(325	)
Net losses associated with the early termination of the cross-border energy lease investments, net of income taxes		—		—		(2	)
Income (loss) from discontinued operations, net of income taxes	$	9	$	—	$	(327	)

(a) Includes income tax benefit of approximately $9 million and $44 million for the years ended December 31, 2015 and 2013, respectively.

Pepco Energy Services [Member] | Discontinued Operations [Member]

Income (Loss) from Discontinued Operations, net of income taxes

The operating results for the retail electric and natural gas supply businesses of Pepco Energy Services are as follows:

	For the Year Ended December 31,
	2015		2014		2013
	(millions of dollars)
Operating revenue	$	—	$	—	$	84
Income from operations of discontinued operations, net of income taxes	$	—	$	—	$	4
Net gains associated with accelerated disposition of retail electric and natural gas contracts, net of income taxes		—		—		1
Income from discontinued operations, net of income taxes (a)	$	—	$	—	$	5

(a) Includes income tax expense of approximately $3 million for the year ended December 31, 2013.

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Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2015

Atlantic City Electric Co [Member]

Schedule of Related Party Transactions Included in Financial Statements

In addition to the PHI Service Company charges described above, ACE’s consolidated financial statements include the following related party transactions in its consolidated statements of income:

	For the Year Ended December 31,
	2015			2014			2013
	(millions of dollars)
Meter reading services provided by Millennium Account Services LLC (an ACE affiliate) (a)	$	(4	)	$	(4	)	$	(4	)
Intercompany lease transactions (a)		(1	)		(1	)		(1	)
Intercompany use revenue (b)		1			2			3

(a) Included in Other operation and maintenance expense.

(b) Included in Operating revenue.

As of December 31, 2015 and 2014, ACE had the following balances on its consolidated balance sheets due to related parties:

	2015			2014
	(millions of dollars)
Payable to Related Party (current) (a)
PHI Service Company	$	(15	)	$	(14	)
Other		(1	)		(1	)
Total	$	(16	)	$	(15	)

(a) Included in Accounts payable due to associated companies.

Potomac Electric Power Co [Member]

Schedule of Related Party Transactions Included in Financial Statements

As of December 31, 2015 and 2014, Pepco had the following balances on its balance sheets due to related parties:

	2015			2014
	(millions of dollars)
Payable to Related Party (current) (a)
PHI Service Company	$	(25	)	$	(27	)
Pepco Energy Services (b)		(4	)		(2	)
Other		(1	)		(1	)
Total	$	(30	)	$	(30	)

(a) Included in Accounts payable due to associated companies.

(b) Pepco bills customers on behalf of Pepco Energy Services where Pepco Energy Services has performed work for certain government agencies under a General Services Administration area-wide agreement. Amount also includes charges for utility work performed by Pepco Energy Services on behalf of Pepco.

Delmarva Power & Light Co/De [Member]

Schedule of Related Party Transactions Included in Financial Statements

In addition to the PHI Service Company charges described above, DPL’s financial statements include the following related party transactions in its statements of income:

	For the Year Ended December 31,
	2015		2014		2013
	(millions of dollars)
Intercompany lease transactions (a)	$	4	$	5	$	4

(a) Included in Electric revenue.

As of December 31, 2015 and 2014, DPL had the following balances on its balance sheets due to related parties:

	2015			2014
	(millions of dollars)
Payable to Related Party (current) (a)
PHI Service Company	$	(19	)	$	(18	)
Other		(1	)		1
Total	$	(20	)	$	(17	)

(a) Included in Accounts payable due to associated companies.

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Organization - Additional Information (Detail) - USD ($)								12 Months Ended
	Jul. 24, 2015	Apr. 27, 2015	Jan. 26, 2015	Oct. 27, 2014	Jul. 29, 2014	Apr. 30, 2014	Apr. 29, 2014	Dec. 31, 2015	Dec. 31, 2014
Organization [Line Items]
Common stock, par value							$ 0.01	$ 0.01	$ 0.01
Right to receive cash under cancellation of shares							$ 27.25
Amount of Non Voting Series A Preferred Stock Purchase price								$ 54,000,000	$ 126,000,000
Termination fee							$ 259,000,000
Reimbursement of termination related expenses							$ 40,000,000
Potomac Electric Power Co [Member]
Organization [Line Items]
Common stock, par value								$ 0.01	$ 0.01
Delmarva Power & Light Co/De [Member]
Organization [Line Items]
Common stock, par value							$ 0.01	2.25	2.25
Right to receive cash under cancellation of shares							$ 27.25
Termination fee							$ 259,000,000
Reimbursement of termination related expenses							$ 40,000,000
Atlantic City Electric Co [Member]
Organization [Line Items]
Common stock, par value							$ 0.01	3.00	$ 3.00
Right to receive cash under cancellation of shares							$ 27.25
Termination fee							$ 259,000,000
Reimbursement of termination related expenses							40,000,000
Terminations Due to New Acquisition Proposal [Member]
Organization [Line Items]
Termination fee							293,000,000
Terminations Due to New Acquisition Proposal [Member] | Delmarva Power & Light Co/De [Member]
Organization [Line Items]
Termination fee							293,000,000
Terminations Due to New Acquisition Proposal [Member] | Atlantic City Electric Co [Member]
Organization [Line Items]
Termination fee							293,000,000
Non-Voting Series A Preferred Stock [Member]
Organization [Line Items]
Issuance of non-voting Series A Preferred Stock, shares issued						9,000
Non-voting Series A Preferred Stock, par value						$ 0.01
Non-voting Series A Preferred Stock, shares purchased price						$ 90,000,000
Non-voting Series A Preferred Stock, maximum number of shares issued	1,800	1,800	1,800	1,800	1,800
Amount of Non Voting Series A Preferred Stock Purchase price	$ 18,000,000	$ 18,000,000	$ 18,000,000	$ 18,000,000	$ 18,000,000
Non-voting Series A Preferred Stock, maximum aggregate consideration							180,000,000
Redemption of preferred stock at purchase price								10,000
Non-voting Series A Preferred Stock, cumulative, non-participating cash dividend						0.10%
Non-Voting Series A Preferred Stock [Member] | Potomac Electric Power Co [Member]
Organization [Line Items]
Issuance of non-voting Series A Preferred Stock, shares issued						9,000
Non-voting Series A Preferred Stock, par value						$ 0.01
Non-voting Series A Preferred Stock, shares purchased price						$ 90,000,000
Non-voting Series A Preferred Stock, maximum number of shares issued	1,800	1,800	1,800	1,800	1,800
Amount of Non Voting Series A Preferred Stock Purchase price	$ 90,000,000	$ 90,000,000	$ 90,000,000	$ 90,000,000	$ 90,000,000
Non-voting Series A Preferred Stock, maximum aggregate consideration							180,000,000
Non-voting Series A Preferred Stock, cumulative, non-participating cash dividend						0.10%
Non-Voting Series A Preferred Stock [Member] | Delmarva Power & Light Co/De [Member]
Organization [Line Items]
Issuance of non-voting Series A Preferred Stock, shares issued						9,000
Non-voting Series A Preferred Stock, par value						$ 0.01
Non-voting Series A Preferred Stock, shares purchased price						$ 90,000,000
Non-voting Series A Preferred Stock, maximum number of shares issued	1,800	1,800	1,800	1,800	1,800
Amount of Non Voting Series A Preferred Stock Purchase price	$ 90,000,000	$ 90,000,000	$ 90,000,000	$ 90,000,000	$ 90,000,000
Non-voting Series A Preferred Stock, maximum aggregate consideration							180,000,000
Redemption of preferred stock at purchase price								10,000
Non-voting Series A Preferred Stock, cumulative, non-participating cash dividend						0.10%
Non-Voting Series A Preferred Stock [Member] | Atlantic City Electric Co [Member]
Organization [Line Items]
Issuance of non-voting Series A Preferred Stock, shares issued						9,000
Non-voting Series A Preferred Stock, par value						$ 0.01
Non-voting Series A Preferred Stock, shares purchased price						$ 90,000,000
Non-voting Series A Preferred Stock, maximum number of shares issued	1,800	1,800	1,800	1,800	1,800
Amount of Non Voting Series A Preferred Stock Purchase price	$ 90,000,000	$ 90,000,000	$ 90,000,000	$ 90,000,000	$ 90,000,000
Non-voting Series A Preferred Stock, maximum aggregate consideration							$ 180,000,000
Redemption of preferred stock at purchase price								$ 10,000
Non-voting Series A Preferred Stock, cumulative, non-participating cash dividend						0.10%
Maximum [Member] | Non-Voting Series A Preferred Stock [Member]
Organization [Line Items]
Non-voting Series A Preferred Stock, maximum number of shares issued							18,000
Maximum [Member] | Non-Voting Series A Preferred Stock [Member] | Potomac Electric Power Co [Member]
Organization [Line Items]
Non-voting Series A Preferred Stock, maximum number of shares issued							18,000
Maximum [Member] | Non-Voting Series A Preferred Stock [Member] | Delmarva Power & Light Co/De [Member]
Organization [Line Items]
Non-voting Series A Preferred Stock, maximum number of shares issued							18,000
Maximum [Member] | Non-Voting Series A Preferred Stock [Member] | Atlantic City Electric Co [Member]
Organization [Line Items]
Non-voting Series A Preferred Stock, maximum number of shares issued							18,000
Maximum [Member] | Exelon [Member]
Organization [Line Items]
Out-of-pocket expenses, connection with the Merger Agreement							$ 40,000,000
Maximum [Member] | Exelon [Member] | Delmarva Power & Light Co/De [Member]
Organization [Line Items]
Out-of-pocket expenses, connection with the Merger Agreement							40,000,000
Maximum [Member] | Exelon [Member] | Atlantic City Electric Co [Member]
Organization [Line Items]
Out-of-pocket expenses, connection with the Merger Agreement							$ 40,000,000

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Significant Accounting Policies - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2010
Significant Accounting Policies [Line Items]
Unbilled revenue	$ 139,000,000	$ 172,000,000
Taxes included in gross revenues	$ 322,000,000	$ 321,000,000	$ 346,000,000
Restricted stock awards vesting period	1 year	1 year
Unbilled receivables billing period	1 month
Estimated fair value of an asset	Greater than 50%
AFUDC for borrowed funds	$ 8,000,000	$ 7,000,000	7,000,000
AFUDC for equity component	$ 14,000,000	13,000,000	11,000,000
Number of subsidiaries, allocated	3
Retained earnings	$ 617,000,000	565,000,000
Asset Removal Costs [Member]
Significant Accounting Policies [Line Items]
Regulatory liabilities	$ 211,000,000	250,000,000
Maximum [Member]
Significant Accounting Policies [Line Items]
Original maturities of cash and cash equivalents	3 months
Time-Based Restricted Stock Units were Granted to Each Non-Employee Director [Member]
Significant Accounting Policies [Line Items]
Restricted stock awards vesting period	3 years
Performance Based Restricted Stock Units [Member]
Significant Accounting Policies [Line Items]
Restricted stock awards vesting period	3 years
Delmarva Power & Light Co/De [Member]
Significant Accounting Policies [Line Items]
Unbilled revenue	$ 37,000,000	63,000,000
Taxes included in gross revenues	$ 18,000,000	16,000,000	17,000,000
Unbilled receivables billing period	1 month
Estimated fair value of an asset	Greater than 50%
AFUDC for borrowed funds	$ 1,000,000	1,000,000	2,000,000
AFUDC for equity component	$ 1,000,000	2,000,000	$ 2,000,000
Preferred stock, shares outstanding	0
Retained earnings	$ 625,000,000	641,000,000
Delmarva Power & Light Co/De [Member] | Asset Removal Costs [Member]
Significant Accounting Policies [Line Items]
Regulatory liabilities	$ 153,000,000	$ 166,000,000
Delmarva Power & Light Co/De [Member] | Maximum [Member]
Significant Accounting Policies [Line Items]
Original maturities of cash and cash equivalents	3 months
Delmarva Power & Light Co/De [Member] | Transmission and Distribution [Member]
Significant Accounting Policies [Line Items]
Annual Depreciation Rate	2.60%	2.60%	2.60%
Atlantic City Electric Co [Member]
Significant Accounting Policies [Line Items]
Unbilled revenue	$ 26,000,000	$ 32,000,000
Taxes included in gross revenues	$ 0	1,000,000	$ 11,000,000
Unbilled receivables billing period	1 month
Awards received from the U.S. DOE				$ 19,000,000
AFUDC for borrowed funds	$ 1,000,000	1,000,000
AFUDC for equity component	$ 1,000,000	1,000,000
Preferred stock, shares outstanding	0
Retained earnings	$ 235,000,000	$ 209,000,000
Securitization debt capitalization rate	30.00%
Atlantic City Electric Co [Member] | Maximum [Member]
Significant Accounting Policies [Line Items]
Original maturities of cash and cash equivalents	3 months
AFUDC for borrowed funds			1,000,000
AFUDC for equity component			$ 1,000,000
Atlantic City Electric Co [Member] | Transmission and Distribution [Member]
Significant Accounting Policies [Line Items]
Annual Depreciation Rate	2.60%	2.60%	2.80%
Potomac Electric Power Co [Member]
Significant Accounting Policies [Line Items]
Unbilled revenue	$ 76,000,000	$ 77,000,000
Taxes included in gross revenues	$ 304,000,000	304,000,000	$ 318,000,000
Unbilled receivables billing period	1 month
Awards received from the U.S. DOE				$ 149,000,000
AFUDC for borrowed funds	$ 6,000,000	5,000,000	5,000,000
AFUDC for equity component	$ 12,000,000	10,000,000	$ 9,000,000
Preferred stock, shares outstanding	0
Retained earnings	$ 1,118,000,000	1,077,000,000
Potomac Electric Power Co [Member] | Asset Removal Costs [Member]
Significant Accounting Policies [Line Items]
Regulatory liabilities	$ 58,000,000	$ 84,000,000
Potomac Electric Power Co [Member] | Maximum [Member]
Significant Accounting Policies [Line Items]
Original maturities of cash and cash equivalents	3 months
Potomac Electric Power Co [Member] | Transmission and Distribution [Member]
Significant Accounting Policies [Line Items]
Annual Depreciation Rate	2.30%	2.30%	2.20%

XML

Significant Accounting Policies - Annual Depreciation Rates (Detail)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Transmission and Distribution [Member] | Potomac Electric Power Co [Member]
Property, Plant and Equipment [Line Items]
Annual Depreciation Rate	2.30%	2.30%	2.20%
Transmission and Distribution [Member] | Delmarva Power & Light Co/De [Member]
Property, Plant and Equipment [Line Items]
Annual Depreciation Rate	2.60%	2.60%	2.60%
Transmission and Distribution [Member] | Atlantic City Electric Co [Member]
Property, Plant and Equipment [Line Items]
Annual Depreciation Rate	2.60%	2.60%	2.80%
Generation [Member] | Pepco Energy Services [Member]
Property, Plant and Equipment [Line Items]
Annual Depreciation Rate	0.60%	1.20%	0.40%

XML

Newly Adopted Accounting Standards - Effects of the Retrospective Application of Newly Adopted Accounting Standards on Reported Balances (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Other (within other assets)	$ 129	$ 121
Prepaid expenses and other	72	63
Long-term debt	4,656	4,397
Transition bonds issued by ACE Funding	124	170
Deferred income taxes, net (within current assets)	0	0
Deferred income taxes, net (within other assets)	15	17
Other (within current liabilities)	287	305
Deferred income tax liabilities, net	3,393	3,242
Potomac Electric Power Co [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Other (within other assets)	42	43
Prepaid expenses and other	20	21
Long-term debt	2,301	2,096
Other (within current liabilities)	68	93
Deferred income tax liabilities, net	1,721	1,579
Delmarva Power & Light Co/De [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Other (within other assets)	1	4
Prepaid expenses and other	10	12
Long-term debt	1,061	963
Other (within current liabilities)	39	41
Deferred income tax liabilities, net	941	878
Atlantic City Electric Co [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Other (within other assets)	4	5
Prepaid expenses and other	1	3
Long-term debt	1,030	882
Transition bonds issued by ACE Funding	124	170
Other (within current liabilities)	21	22
Deferred income tax liabilities, net	$ 888	855
As Filed [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Other (within other assets)		166
Long-term debt		4,441
Transition bonds issued by ACE Funding		171
Deferred income taxes, net (within current assets)		50
Other (within current liabilities)		314
Deferred income tax liabilities, net		3,266
As Filed [Member] | Potomac Electric Power Co [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Other (within other assets)		71
Long-term debt		2,124
Deferred income taxes, net (within current assets)		14
Other (within current liabilities)		102
Deferred income tax liabilities, net		1,584
As Filed [Member] | Delmarva Power & Light Co/De [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Other (within other assets)		12
Long-term debt		971
Deferred income taxes, net (within current assets)		16
Other (within current liabilities)		42
Deferred income tax liabilities, net		893
As Filed [Member] | Atlantic City Electric Co [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Other (within other assets)		12
Prepaid expenses and other		13
Long-term debt		888
Transition bonds issued by ACE Funding		171
Deferred income tax liabilities, net		865
Scenario, Adjustment [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Other (within other assets)		(45)
Long-term debt		(44)
Transition bonds issued by ACE Funding		(1)
Deferred income taxes, net (within current assets)		(50)
Deferred income taxes, net (within other assets)		17
Other (within current liabilities)		(9)
Deferred income tax liabilities, net		(24)
Scenario, Adjustment [Member] | Potomac Electric Power Co [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Other (within other assets)		(28)
Long-term debt		(28)
Deferred income taxes, net (within current assets)		(14)
Other (within current liabilities)		(9)
Deferred income tax liabilities, net		(5)
Scenario, Adjustment [Member] | Delmarva Power & Light Co/De [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Other (within other assets)		(8)
Long-term debt		(8)
Deferred income taxes, net (within current assets)		(16)
Other (within current liabilities)		(1)
Deferred income tax liabilities, net		(15)
Scenario, Adjustment [Member] | Atlantic City Electric Co [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Other (within other assets)		(7)
Prepaid expenses and other		(10)
Long-term debt		(6)
Transition bonds issued by ACE Funding		(1)
Deferred income tax liabilities, net		$ (10)

XML

Segment Information - Segment Financial Information for Continuing Operations (Detail) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Operating Revenue	$ 1,150	$ 1,362	$ 1,140	$ 1,371	$ 1,118	$ 1,313	$ 1,117	$ 1,330	$ 5,023	$ 4,878	$ 4,666
Operating Expenses	941	1,179	1,001	1,229	1,004	1,147	966	1,157	4,350	4,274	3,998
Operating Income (Loss)	209	183	139	142	114	166	151	173	673	604	668
Interest Expense									280	268	273
Other income									54	44	34
Income Tax Expense (Benefit)	23	49	27	30	13	$ 34	$ 45	$ 46	129	138	319
Net Income (Loss) from Continuing Operations	121	$ 91	$ 53	$ 53					318	242	110
Total Assets	16,326				15,589				16,326	15,589	14,778
Construction Expenditures									1,230	1,223	1,310
Power Delivery [Member]
Segment Reporting Information [Line Items]
Operating Revenue									4,805	4,607	4,472
Operating Expenses									4,124	3,916	3,828
Operating Income (Loss)									681	691	644
Interest Expense									238	226	228
Other income									36	40	28
Income Tax Expense (Benefit)									177	185	155
Net Income (Loss) from Continuing Operations									302	320	289
Total Assets	14,413				13,636				14,413	13,636	12,868
Construction Expenditures									1,196	1,144	1,194
Pepco Energy Services [Member]
Segment Reporting Information [Line Items]
Operating Revenue									223	278	203
Operating Expenses									224	354	201
Operating Income (Loss)									(1)	(76)	2
Interest Expense										1	1
Other income									1	2	3
Income Tax Expense (Benefit)									(4)	(36)	1
Net Income (Loss) from Continuing Operations									4	(39)	3
Total Assets	221				249				221	249	337
Construction Expenditures									3	3	4
Corporate and Other [Member]
Segment Reporting Information [Line Items]
Operating Revenue									(5)	(7)	(9)
Operating Expenses									2	4	(31)
Operating Income (Loss)									(7)	(11)	22
Interest Expense									42	41	44
Other income									17	2	3
Income Tax Expense (Benefit)									(44)	(11)	163
Net Income (Loss) from Continuing Operations									12	(39)	(182)
Total Assets	$ 1,692				$ 1,704				1,692	1,704	1,573
Construction Expenditures									$ 31	$ 76	$ 112

XML

Segment Information - Segment Financial Information for Continuing Operations (Parenthetical) (Detail) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Goodwill	$ 1,406				$ 1,407				$ 1,406	$ 1,407
Operating Revenue	1,150	$ 1,362	$ 1,140	$ 1,371	1,118	$ 1,313	$ 1,117	$ 1,330	5,023	4,878	$ 4,666
Operating Expenses	941	1,179	1,001	1,229	1,004	1,147	966	1,157	4,350	4,274	3,998
Interest Expense									280	268	273
Depreciation and amortization									651	549	473
Gains on sales of land	46								46
Gains on sales of land, after tax	27
Increase in fair value of preferred stock derivative		15							15
Increase in fair value of preferred stock derivative, after-tax		10
Income Tax Benefit	(23)	$ (49)	$ (27)	$ (30)	(13)	$ (34)	$ (45)	$ (46)	(129)	(138)	(319)
Impairment losses										81	4
Tax Settlement [Member]
Segment Reporting Information [Line Items]
Income Tax Benefit	47
Power Delivery [Member]
Segment Reporting Information [Line Items]
Operating Revenue									4,805	4,607	4,472
Operating Expenses									4,124	3,916	3,828
Interest Expense									238	226	228
Depreciation and amortization									606	511	439
Gains on sales of land									46
Gains on sales of land, after tax									27
Income Tax Benefit									(177)	(185)	(155)
Interest benefit on uncertain tax positions											12
Power Delivery [Member] | Tax Settlement [Member]
Segment Reporting Information [Line Items]
Income Tax Benefit									3
Power Delivery [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Goodwill	$ 1,400				$ 1,400				1,400	1,400	1,400
Inter Company Amounts [Member] | Corporate and Other [Member]
Segment Reporting Information [Line Items]
Operating Revenue									(5)	(7)	(10)
Operating Expenses									(4)	(7)	(9)
Interest Expense									(5)	(4)	(5)
Pepco Energy Services [Member]
Segment Reporting Information [Line Items]
Operating Revenue									223	278	203
Operating Expenses									224	354	201
Interest Expense										1	1
Depreciation and amortization									4	7	6
Income Tax Benefit									4	36	(1)
Impairment losses										81
Impairment losses, after-tax										48
Pepco Energy Services [Member] | Tax Settlement [Member]
Segment Reporting Information [Line Items]
Income Tax Benefit									1
Pepco Energy Services [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Impairment losses										81	4
Impairment losses, after-tax										48	3
Corporate and Other [Member]
Segment Reporting Information [Line Items]
Operating Revenue									(5)	(7)	(9)
Operating Expenses									2	4	(31)
Interest Expense									42	41	44
Depreciation and amortization									41	31	28
Increase in fair value of preferred stock derivative									15
Increase in fair value of preferred stock derivative, after-tax									10
Income Tax Benefit									44	$ 11	(163)
Interest expense on uncertain tax positions											66
Valuation allowances against deferred tax assets											$ 101
Corporate and Other [Member] | Tax Settlement [Member]
Segment Reporting Information [Line Items]
Income Tax Benefit									$ 43

XML

Goodwill - Additional Information (Detail) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Goodwill [Line Items]
Goodwill	$ 1,406,000,000	$ 1,407,000,000
Accumulated impairment loss	12,000,000	18,000,000
Delmarva Power & Light Co/De [Member]
Goodwill [Line Items]
Goodwill	8,000,000	8,000,000
Accumulated impairment loss	$ 0	$ 0

XML

Regulatory Matters - Schedule of Regulatory Assets and Regulatory Liabilities (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Public Utilities, General Disclosures [Line Items]
Regulatory assets	$ 2,246	$ 2,409
Regulatory Liabilities	308	343
Pension and Other Postretirement Benefit Costs [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory assets	910	946
Securitized Stranded Costs [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory assets	202	278
Recoverable Income Taxes [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory assets	224	274
Demand-Side Management Costs [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory assets	403	329
Smart Grid Costs [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory assets	266	261
Deferred Energy Supply Costs [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory assets	32	73
Incremental Storm Restoration Costs [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory assets	43	51
Deferred Debt Extinguishment Costs [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory assets	36	42
MAPP Abandonment Costs [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory assets	7	33
Recoverable Workers' Compensation and Long-Term Disability Costs [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory assets	31	30
Deferred Losses on Gas Derivatives [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory assets	2	4
Other Regulatory Assets [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory assets	90	88
Asset Removal Costs [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Liabilities	211	250
Deferred Income Taxes Due to Customers [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Liabilities	12	44
Deferred Energy Supply Costs [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Liabilities	11	3
Other Regulatory Liabilities [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Liabilities	29	34
Federal and State Tax Benefits, Related to Securitized Stranded Costs [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Liabilities	13	8
Reserves for FERC ROE Transmission Challenges [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Liabilities	32	4
Potomac Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory assets	720	697
Regulatory Liabilities	92	104
Potomac Electric Power Co [Member] | Recoverable Income Taxes [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory assets	142	148
Potomac Electric Power Co [Member] | Demand-Side Management Costs [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory assets	292	238
Potomac Electric Power Co [Member] | Smart Grid Costs [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory assets	181	175
Potomac Electric Power Co [Member] | Deferred Energy Supply Costs [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory assets	3	3
Potomac Electric Power Co [Member] | Incremental Storm Restoration Costs [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory assets	19	29
Potomac Electric Power Co [Member] | Deferred Debt Extinguishment Costs [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory assets	19	22
Potomac Electric Power Co [Member] | MAPP Abandonment Costs [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory assets	4	19
Potomac Electric Power Co [Member] | Recoverable Workers' Compensation and Long-Term Disability Costs [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory assets	31	30
Potomac Electric Power Co [Member] | Other Regulatory Assets [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory assets	29	33
Potomac Electric Power Co [Member] | Asset Removal Costs [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Liabilities	58	84
Potomac Electric Power Co [Member] | Deferred Income Taxes Due to Customers [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Liabilities	6	4
Potomac Electric Power Co [Member] | Deferred Energy Supply Costs [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Liabilities	5	3
Potomac Electric Power Co [Member] | Other Regulatory Liabilities [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Liabilities	10	11
Potomac Electric Power Co [Member] | Reserves for FERC ROE Transmission Challenges [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Liabilities	13	2
Delmarva Power & Light Co/De [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory assets	308	356
Regulatory Liabilities	189	225
Delmarva Power & Light Co/De [Member] | Recoverable Income Taxes [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory assets	38	84
Delmarva Power & Light Co/De [Member] | Demand-Side Management Costs [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory assets	111	91
Delmarva Power & Light Co/De [Member] | Smart Grid Costs [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory assets	85	86
Delmarva Power & Light Co/De [Member] | Deferred Energy Supply Costs [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory assets	2	12
Delmarva Power & Light Co/De [Member] | Incremental Storm Restoration Costs [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory assets	6	7
Delmarva Power & Light Co/De [Member] | Deferred Debt Extinguishment Costs [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory assets	10	12
Delmarva Power & Light Co/De [Member] | MAPP Abandonment Costs [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory assets	3	14
Delmarva Power & Light Co/De [Member] | Deferred Losses on Gas Derivatives [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory assets	2	4
Delmarva Power & Light Co/De [Member] | Other Regulatory Assets [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory assets	38	28
Delmarva Power & Light Co/De [Member] | COPCO Acquisition Adjustment [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory assets	13	18
Delmarva Power & Light Co/De [Member] | Asset Removal Costs [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Liabilities	153	166
Delmarva Power & Light Co/De [Member] | Deferred Income Taxes Due to Customers [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Liabilities	3	37
Delmarva Power & Light Co/De [Member] | Deferred Energy Supply Costs [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Liabilities	6
Delmarva Power & Light Co/De [Member] | Other Regulatory Liabilities [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Liabilities	16	21
Delmarva Power & Light Co/De [Member] | Reserves for FERC ROE Transmission Challenges [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Liabilities	11	1
Atlantic City Electric Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory assets	322	427
Regulatory Liabilities	27	14
Atlantic City Electric Co [Member] | Securitized Stranded Costs [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory assets	202	278
Atlantic City Electric Co [Member] | Recoverable Income Taxes [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory assets	44	42
Atlantic City Electric Co [Member] | Deferred Energy Supply Costs [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory assets	27	58
Atlantic City Electric Co [Member] | Incremental Storm Restoration Costs [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory assets	18	15
Atlantic City Electric Co [Member] | Deferred Debt Extinguishment Costs [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory assets	7	8
Atlantic City Electric Co [Member] | Other Regulatory Assets [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory assets	24	26
Atlantic City Electric Co [Member] | Deferred Income Taxes Due to Customers [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Liabilities	3	3
Atlantic City Electric Co [Member] | Other Regulatory Liabilities [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Liabilities	3	2
Atlantic City Electric Co [Member] | Federal and State Tax Benefits, Related to Securitized Stranded Costs [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Liabilities	13	8
Atlantic City Electric Co [Member] | Reserves for FERC ROE Transmission Challenges [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Liabilities	$ 8	$ 1

XML

Regulatory Matters - Additional Information (Detail)											1 Months Ended														12 Months Ended		30 Months Ended
	Feb. 01, 2016 USD ($)	Nov. 06, 2015 USD ($)	Sep. 11, 2015 USD ($)	Jun. 01, 2015 USD ($)	May. 19, 2015 USD ($)	Apr. 17, 2015 USD ($)	Dec. 08, 2014	Dec. 07, 2014	Apr. 15, 2014 USD ($)	Sep. 20, 2013 USD ($)	Aug. 31, 2015	Mar. 31, 2015 USD ($)	Oct. 31, 2014	Aug. 31, 2014 USD ($)	Jul. 31, 2014 USD ($)	May. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)	Oct. 31, 2013 USD ($)	Jul. 31, 2013 USD ($)	Mar. 31, 2013 USD ($)	Feb. 28, 2013	Nov. 30, 2012 USD ($)	Jul. 31, 2012 USD ($)	Dec. 31, 2011 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2011	Dec. 31, 2015 USD ($)	Apr. 30, 2012 MW
Public Utilities, General Disclosures [Line Items]
Transition bond maturity, lower range																									2016
Transition bond maturity, upper range																									2023
Date of acquisition																									Apr. 29, 2014
Return on equity, percentage		10.00%																	9.36%					10.75%
Approved rate change															$ 8,750,000				$ 27,900,000				$ 18,100,000
Return on equity, percentage															9.62%								9.31%
Effect of proposed change on Gas Cost Rate											26.00%
Adjusted rate change									$ 37,400,000
Charges on cost of recovery																			$ 24,000,000
Consolidated tax adjustment calculation review period													5 years
Percentage of revenue requirement related to consolidated tax adjustment calculation													25.00%
Basis-point		0.50%
Return of equity effective date		Mar. 08, 2016
New power plant output | MW																												661
Undergrounding project cost																$ 1,000,000,000
Entity share to complete project																500,000,000
Federal Energy Regulatory Commission Return On Equity Complaint [Member]
Public Utilities, General Disclosures [Line Items]
Return on equity, percentage							8.80%	10.80%
Reserve for litigation filed																									$ 32,000,000		$ 32,000,000
Expected [Member]
Public Utilities, General Disclosures [Line Items]
Requested rate change																	$ 43,300,000					$ 60,800,000		$ 68,400,000
Return on equity, percentage																	10.25%
Actual [Member]
Public Utilities, General Disclosures [Line Items]
Adjusted rate change																								66,200,000
District of Columbia [Member] | DC Undergrounding Task Force [Member]
Public Utilities, General Disclosures [Line Items]
Underground project cost																375,000,000
MAPP Abandonment Costs [Member]
Public Utilities, General Disclosures [Line Items]
Project termination costs																									Aug. 24, 2012
Amortization and recovery period																									2016-05
Minimum [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory asset, amortization period, years																									1 year
New power plant output | MW																												650
Maximum [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory asset, amortization period, years																									20 years
New power plant output | MW																												700
Maximum [Member] | District of Columbia [Member] | Department of Transportation [Member]
Public Utilities, General Disclosures [Line Items]
Under grounding project costs covered by existing capital projects program																125,000,000
Pepco and Delmarva Power Light Co [Member]
Public Utilities, General Disclosures [Line Items]
Incremental Storm Restoration Costs Amortization and recovery period																										5 years
Delmarva Power & Light Co/De [Member]
Public Utilities, General Disclosures [Line Items]
Requested rate change										$ 39,000,000								$ 56,000,000		$ 42,000,000
Return on equity, percentage		10.00%												9.70%						10.25%					10.80%
Approved rate change														$ 15,100,000
Return on equity, percentage														9.70%
Increased distribution base period																		4 years
Estimated return on equity, year one																		7.41%
Estimated return on equity, year two																		8.80%
Estimated return on equity, year three																		9.75%
Estimated return on equity, year four																		9.75%
Customer refundable fees																		$ 500,000
Effect of proposed change on Gas Cost Rate											26.00%
Basis-point		0.50%																							0.50%		0.50%
Return of equity effective date		Mar. 08, 2016
Customer refunds		$ 11,900,000
New power plant output | MW																												661
Goodwill transferred to a regulatory asset																									$ 41,000,000		$ 41,000,000
Return earned on regulatory assets																									12.95%		12.95%
Delmarva Power & Light Co/De [Member] | Federal Energy Regulatory Commission Return On Equity Complaint [Member]
Public Utilities, General Disclosures [Line Items]
Return on equity, percentage							8.80%	10.80%													8.70%				11.30%
Reserve for litigation filed																									$ 11,000,000		$ 11,000,000
Delmarva Power & Light Co/De [Member] | Minimum [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory asset, amortization period, years																									1 year
New power plant output | MW																												650
Delmarva Power & Light Co/De [Member] | Minimum [Member] | Federal Energy Regulatory Commission Return On Equity Complaint [Member]
Public Utilities, General Disclosures [Line Items]
Return on equity, percentage																					6.78%
Delmarva Power & Light Co/De [Member] | Maximum [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory asset, amortization period, years																									20 years
New power plant output | MW																												700
Delmarva Power & Light Co/De [Member] | Maximum [Member] | Federal Energy Regulatory Commission Return On Equity Complaint [Member]
Public Utilities, General Disclosures [Line Items]
Return on equity, percentage																					10.33%
Atlantic City Electric Co [Member]
Public Utilities, General Disclosures [Line Items]
Transition bond maturity, lower range																									2016
Transition bond maturity, upper range																									2023
Incremental Storm Restoration Costs Amortization and recovery period																										3 years
Requested rate change						$ 33,900,000						$ 52,000,000
Return on equity, percentage		10.00%																							10.80%
Approved rate change			$ 32,600,000	$ (1,300,000)	$ 33,900,000
Contributions received by ACE																									$ 11,000,000		$ 11,000,000
Consolidated tax adjustment calculation review period													5 years
Percentage of revenue requirement related to consolidated tax adjustment calculation													25.00%
Basis-point																									0.50%		0.50%
Return of equity effective date		Mar. 08, 2016
Customer refunds		$ 9,500,000
Atlantic City Electric Co [Member] | Subsequent Event [Member]
Public Utilities, General Disclosures [Line Items]
Overall annual rate increase as net impact of adjusting charges	$ 8,800,000
Atlantic City Electric Co [Member] | Federal Energy Regulatory Commission Return On Equity Complaint [Member]
Public Utilities, General Disclosures [Line Items]
Return on equity, percentage							8.80%	10.80%													8.70%				11.30%
Reserve for litigation filed																									$ 8,000,000		$ 8,000,000
Atlantic City Electric Co [Member] | Minimum [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory asset, amortization period, years																									1 year
Atlantic City Electric Co [Member] | Minimum [Member] | Federal Energy Regulatory Commission Return On Equity Complaint [Member]
Public Utilities, General Disclosures [Line Items]
Return on equity, percentage																					6.78%
Atlantic City Electric Co [Member] | Maximum [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory asset, amortization period, years																									20 years
Contributions paid by ACE																											$ 1,000,000
Atlantic City Electric Co [Member] | Maximum [Member] | Federal Energy Regulatory Commission Return On Equity Complaint [Member]
Public Utilities, General Disclosures [Line Items]
Return on equity, percentage																					10.33%
Potomac Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Requested rate change																								$ 68,400,000
Return on equity, percentage		10.00%																	9.36%			10.25%		10.75%	10.80%
Approved rate change															$ 8,750,000				$ 27,900,000				$ 18,100,000
Return on equity, percentage															9.62%				9.36%				9.31%
Adjusted rate change									$ 37,400,000
Charges on cost of recovery																			$ 24,000,000
Basis-point		0.50%																							0.50%		0.50%
Return of equity effective date		Mar. 08, 2016
Customer refunds		$ 14,200,000
New power plant output | MW																												661
Undergrounding project cost																1,000,000,000
Entity share to complete project																500,000,000
Potomac Electric Power Co [Member] | Federal Energy Regulatory Commission Return On Equity Complaint [Member]
Public Utilities, General Disclosures [Line Items]
Return on equity, percentage							8.80%	10.80%													8.70%				11.30%
Reserve for litigation filed																									$ 13,000,000		$ 13,000,000
Potomac Electric Power Co [Member] | Expected [Member]
Public Utilities, General Disclosures [Line Items]
Requested rate change																	$ 43,300,000					$ 60,800,000
Return on equity, percentage																	10.25%
Potomac Electric Power Co [Member] | Actual [Member]
Public Utilities, General Disclosures [Line Items]
Adjusted rate change																								$ 66,200,000
Potomac Electric Power Co [Member] | District of Columbia [Member] | DC Undergrounding Task Force [Member]
Public Utilities, General Disclosures [Line Items]
Underground project cost																375,000,000
Potomac Electric Power Co [Member] | Minimum [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory asset, amortization period, years																									1 year
New power plant output | MW																												650
Potomac Electric Power Co [Member] | Minimum [Member] | Federal Energy Regulatory Commission Return On Equity Complaint [Member]
Public Utilities, General Disclosures [Line Items]
Return on equity, percentage																					6.78%
Potomac Electric Power Co [Member] | Maximum [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory asset, amortization period, years																									20 years
New power plant output | MW																												700
Potomac Electric Power Co [Member] | Maximum [Member] | Federal Energy Regulatory Commission Return On Equity Complaint [Member]
Public Utilities, General Disclosures [Line Items]
Return on equity, percentage																					10.33%
Potomac Electric Power Co [Member] | Maximum [Member] | District of Columbia [Member] | Department of Transportation [Member]
Public Utilities, General Disclosures [Line Items]
Under grounding project costs covered by existing capital projects program																$ 125,000,000

XML

Property, Plant and Equipment - Schedule of Property, Plant and Equipment (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Original Cost	$ 16,218	$ 15,465
Accumulated Depreciation	4,914	4,959
Net Book Value	11,304	10,506
Potomac Electric Power Co [Member]
Property, Plant and Equipment [Line Items]
Original Cost	8,091	7,764
Accumulated Depreciation	2,799	2,816
Net Book Value	5,292	4,948
Delmarva Power & Light Co/De [Member]
Property, Plant and Equipment [Line Items]
Original Cost	4,209	3,946
Accumulated Depreciation	1,046	1,021
Net Book Value	3,163	2,925
Atlantic City Electric Co [Member]
Property, Plant and Equipment [Line Items]
Original Cost	3,305	3,073
Accumulated Depreciation	764	760
Net Book Value	2,541	2,313
Generation [Member]
Property, Plant and Equipment [Line Items]
Original Cost	23	104
Accumulated Depreciation	19	100
Net Book Value	4	4
Generation [Member] | Atlantic City Electric Co [Member]
Property, Plant and Equipment [Line Items]
Original Cost		10
Accumulated Depreciation		9
Net Book Value		1
Distribution [Member]
Property, Plant and Equipment [Line Items]
Original Cost	10,051	9,527
Accumulated Depreciation	3,161	3,021
Net Book Value	6,890	6,506
Distribution [Member] | Potomac Electric Power Co [Member]
Property, Plant and Equipment [Line Items]
Original Cost	5,996	5,668
Accumulated Depreciation	2,199	2,082
Net Book Value	3,797	3,586
Distribution [Member] | Delmarva Power & Light Co/De [Member]
Property, Plant and Equipment [Line Items]
Original Cost	2,043	1,928
Accumulated Depreciation	490	489
Net Book Value	1,553	1,439
Distribution [Member] | Atlantic City Electric Co [Member]
Property, Plant and Equipment [Line Items]
Original Cost	2,012	1,931
Accumulated Depreciation	472	450
Net Book Value	1,540	1,481
Transmission [Member]
Property, Plant and Equipment [Line Items]
Original Cost	3,554	3,252
Accumulated Depreciation	962	934
Net Book Value	2,592	2,318
Transmission [Member] | Potomac Electric Power Co [Member]
Property, Plant and Equipment [Line Items]
Original Cost	1,378	1,306
Accumulated Depreciation	475	463
Net Book Value	903	843
Transmission [Member] | Delmarva Power & Light Co/De [Member]
Property, Plant and Equipment [Line Items]
Original Cost	1,208	1,107
Accumulated Depreciation	259	248
Net Book Value	949	859
Transmission [Member] | Atlantic City Electric Co [Member]
Property, Plant and Equipment [Line Items]
Original Cost	968	839
Accumulated Depreciation	228	223
Net Book Value	740	616
Construction Work in Progress [Member]
Property, Plant and Equipment [Line Items]
Original Cost	604	688
Net Book Value	604	688
Construction Work in Progress [Member] | Potomac Electric Power Co [Member]
Property, Plant and Equipment [Line Items]
Original Cost	318	312
Net Book Value	318	312
Construction Work in Progress [Member] | Delmarva Power & Light Co/De [Member]
Property, Plant and Equipment [Line Items]
Original Cost	107	125
Net Book Value	107	125
Construction Work in Progress [Member] | Atlantic City Electric Co [Member]
Property, Plant and Equipment [Line Items]
Original Cost	158	115
Net Book Value	158	115
Non-Operating and Other Property [Member]
Property, Plant and Equipment [Line Items]
Original Cost	1,440	1,383
Accumulated Depreciation	609	751
Net Book Value	831	632
Non-Operating and Other Property [Member] | Potomac Electric Power Co [Member]
Property, Plant and Equipment [Line Items]
Original Cost	399	478
Accumulated Depreciation	125	271
Net Book Value	274	207
Non-Operating and Other Property [Member] | Delmarva Power & Light Co/De [Member]
Property, Plant and Equipment [Line Items]
Original Cost	305	275
Accumulated Depreciation	134	131
Net Book Value	171	144
Non-Operating and Other Property [Member] | Atlantic City Electric Co [Member]
Property, Plant and Equipment [Line Items]
Original Cost	167	178
Accumulated Depreciation	64	78
Net Book Value	103	100
Gas [Member]
Property, Plant and Equipment [Line Items]
Original Cost	546	511
Accumulated Depreciation	163	153
Net Book Value	383	358
Gas [Member] | Delmarva Power & Light Co/De [Member]
Property, Plant and Equipment [Line Items]
Original Cost	546	511
Accumulated Depreciation	163	153
Net Book Value	$ 383	$ 358

XML

Property, Plant and Equipment - Additional Information (Detail)				12 Months Ended
	Nov. 10, 2015 USD ($)	Oct. 16, 2015 USD ($) a	Jul. 02, 2015 USD ($) a	Dec. 31, 2015 USD ($) a	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)
Property, Plant and Equipment [Line Items]
Present value of future minimum lease payments				$ 152,000,000
Semi-annual payments				$ 8,000,000
Description of lease term				Over a 25-year period that began in December 1994
Guaranteed residual value due at end of lease term				$ 1
Approximate annual commitments, 2016				15,000,000
Approximate annual commitments, 2017				15,000,000
Approximate annual commitments, 2018				15,000,000
Approximate annual commitments, 2019				$ 16,000,000
Impairment losses					$ 81,000,000	$ 4,000,000
Long lived assets after impairment, carrying amount					$ 2,000,000
Percentage of change in the estimated cash flows					10.00%
Percentage of change in discount rate assumptions					1.00%
Minimum [Member]
Property, Plant and Equipment [Line Items]
Range of discount rates					10.00%
Maximum [Member]
Property, Plant and Equipment [Line Items]
Range of discount rates					16.00%
Pepco Energy Services [Member]
Property, Plant and Equipment [Line Items]
Impairment losses					$ 81,000,000
Impairment losses, after-tax					48,000,000
Long-lived assets before impairment, carrying amount					83,000,000
Buzzard Point [Member]
Property, Plant and Equipment [Line Items]
Area of land held as non-utility property | a			3.5
Carrying value of land			$ 2,000,000
Sale price of land			$ 39,000,000
Gain on sale of land before tax	$ 37,000,000
Gain on sale of land after tax	22,000,000
No Ma [Member]
Property, Plant and Equipment [Line Items]
Area of land held as non-utility property | a		3.8		1.8
Carrying value remaining portion of land				$ 4,000,000
Sale price of remaining portion of land				$ 13,000,000
Period to purchase remaining portion of land				90 days
No Ma [Member] | Third Party Sale Agreement [Member]
Property, Plant and Equipment [Line Items]
Area of land held as non-utility property | a		2
Carrying value of land		$ 5,000,000
Sale price of land		$ 14,000,000
Gain on sale of land before tax				$ 9,000,000
Gain on sale of land after tax				5,000,000
Subsidiaries [Member]
Property, Plant and Equipment [Line Items]
Jointly owned plant, net book value ownership				16,000,000	15,000,000
Impairment losses						4,000,000
Impairment losses, after-tax						$ 3,000,000
Potomac Electric Power Co [Member]
Property, Plant and Equipment [Line Items]
Present value of future minimum lease payments				152,000,000
Semi-annual payments				$ 8,000,000
Description of lease term				Over a 25-year period that began in December 1994
Guaranteed residual value due at end of lease term				$ 1
Approximate annual commitments, 2016				15,000,000
Approximate annual commitments, 2017				15,000,000
Approximate annual commitments, 2018				15,000,000
Approximate annual commitments, 2019				$ 16,000,000
Potomac Electric Power Co [Member] | Buzzard Point [Member]
Property, Plant and Equipment [Line Items]
Area of land held as non-utility property | a			3.5
Carrying value of land			$ 2,000,000
Sale price of land			$ 39,000,000
Gain on sale of land before tax	37,000,000
Gain on sale of land after tax	$ 22,000,000
Potomac Electric Power Co [Member] | No Ma [Member]
Property, Plant and Equipment [Line Items]
Area of land held as non-utility property | a				1.8
Carrying value remaining portion of land				$ 4,000,000
Sale price of remaining portion of land				$ 13,000,000
Period to purchase remaining portion of land				90 days
Potomac Electric Power Co [Member] | No Ma [Member] | Third Party Sale Agreement [Member]
Property, Plant and Equipment [Line Items]
Area of land held as non-utility property | a		2.0
Carrying value of land		$ 5,000,000
Sale price of land		$ 14,000,000
Gain on sale of land before tax				$ 9,000,000
Gain on sale of land after tax				5,000,000
Conectiv Energy [Member]
Property, Plant and Equipment [Line Items]
Asset retirement obligation				7,000,000
Atlantic City Electric Co [Member]
Property, Plant and Equipment [Line Items]
Jointly owned plant, net book value ownership				$ 11,000,000	$ 11,000,000

XML

Property, Plant and Equipment - Capital Lease Assets Recorded within Property, Plant and Equipment (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Capital Leased Assets [Line Items]
Original Cost	$ 152	$ 152
Accumulated Amortization	102	92
Net Book Value	50	60
Transmission [Member]
Capital Leased Assets [Line Items]
Original Cost	76	76
Accumulated Amortization	51	46
Net Book Value	25	30
Distribution [Member]
Capital Leased Assets [Line Items]
Original Cost	76	76
Accumulated Amortization	51	46
Net Book Value	$ 25	$ 30

XML

Pension and Other Postretirement Benefits - Schedule of Changes in Benefit Obligations and Plan Assets (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Benefits [Member]
Change in Benefit Obligation
Service cost	$ 57	$ 44	$ 53
Interest cost	109	109	100
Change in Plan Assets
Fair value of plan assets at beginning of year	1,557
Fair value of plan assets at end of year	1,397	1,557
Pension Benefits [Member] | Investments Measured at Fair Value [Member]
Change in Benefit Obligation
Benefit obligation at beginning of year	2,638	2,238
Service cost	57	44
Interest cost	109	109
Actuarial loss (gain)	(151)	401
Benefits paid	(163)	(154)
Benefit obligation at end of year	2,490	2,638	2,238
Change in Plan Assets
Fair value of plan assets at beginning of year	2,236	2,116
Actual return on plan assets	(61)	268
Company and participant contributions	6	6
Benefits paid by plan	(163)	(154)
Fair value of plan assets at end of year	2,018	2,236	2,116
Funded Status at end of year (plan assets less plan obligations)	(472)	(402)
Other Postretirement Benefits [Member]
Change in Benefit Obligation
Service cost	7	7	8
Interest cost	24	26	29
Change in Plan Assets
Fair value of plan assets at beginning of year	340
Fair value of plan assets at end of year	326	340
Other Postretirement Benefits [Member] | Investments Measured at Fair Value [Member]
Change in Benefit Obligation
Benefit obligation at beginning of year	632	574
Service cost	7	7
Interest cost	24	26
Actuarial loss (gain)	(61)	59
Benefits paid	(39)	(34)
Benefit obligation at end of year	563	632	574
Change in Plan Assets
Fair value of plan assets at beginning of year	367	368
Actual return on plan assets	1	21
Company and participant contributions	5	6
Benefits paid by plan	(25)	(28)
Fair value of plan assets at end of year	348	367	$ 368
Funded Status at end of year (plan assets less plan obligations)	$ (215)	$ (265)

XML

Pension and Other Postretirement Benefits - Additional Information (Detail)		12 Months Ended
	Jul. 01, 2013	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($) Amendments	Dec. 31, 2012 USD ($)
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation		$ 2,300,000,000	$ 2,400,000,000
Service periods for participating employee		11 years	11 years
Unfunded capital commitments		$ 9,000,000	$ 11,000,000
Pension contribution				$ 120,000,000
Percentage of participants vested		100.00%
Defined contribution plan matching contributions		$ 14,000,000	13,000,000	12,000,000
Pension and other postretirement net periodic benefit cost		97,000,000	58,000,000	95,000,000
Other postretirement benefit obligations		215,000,000	265,000,000
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net loss to be amortized from AOCL or regulatory assets into net periodic benefit cost		63,000,000
Prior service cost to be amortized from AOCL or regulatory assets into net periodic benefit cost		$ 7,000,000
Percentage of plan asset target allocation		68.00%
Pension and other postretirement net periodic benefit cost		$ 93,000,000	59,000,000	77,000,000
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net loss to be amortized from AOCL or regulatory assets into net periodic benefit cost		1,000,000
Prior service cost to be amortized from AOCL or regulatory assets into net periodic benefit cost		13,000,000
OPEB contributions		2,000,000	1,000,000
Pension and other postretirement net periodic benefit cost		4,000,000	(1,000,000)	18,000,000
Other postretirement benefit obligations		215,000,000	265,000,000
Potomac Electric Power Co [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension contribution		0	0	0
Pension and other postretirement net periodic benefit cost		30,000,000	22,000,000	$ 34,000,000
Prepaid pension expense		291,000,000	316,000,000
Other postretirement benefit obligations		49,000,000	57,000,000
Potomac Electric Power Co [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Number of amendments, PHI approved | Amendments				2
Reduction in net periodic benefit cost			$ 7,000,000
Percentage of postretirement benefit costs			40.00%
OPEB contributions		2,000,000	$ 1,000,000	$ 6,000,000
Delmarva Power & Light Co/De [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension contribution		0	0	10,000,000
Pension and other postretirement net periodic benefit cost		15,000,000	7,000,000	$ 18,000,000
Prepaid pension expense		205,000,000	220,000,000
Other postretirement benefit obligations		19,000,000	21,000,000
Delmarva Power & Light Co/De [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Number of amendments, PHI approved | Amendments				2
Reduction in net periodic benefit cost			4,000,000
OPEB contributions		0	0	$ 3,000,000
Delmarva Power & Light Co/De [Member] | Retiree [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension contribution		0	0
PHI Service Company [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Number of amendments, PHI approved | Amendments				2
Reduction in net periodic benefit cost				$ 193,000,000	$ 69,000,000
Prior service credit included in projected benefit obligation				$ 124,000,000
Amortization period				10 years
Change in the discount rate	4.95%				4.10%
Reduction of the projected benefit obligation			$ 19,000,000
Percentage of postretirement benefit costs			36.00%
PHI Service Company [Member] | Retiree [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension contribution		0	$ 0
Atlantic City Electric Co [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension contribution		0	0	$ 30,000,000
Pension and other postretirement net periodic benefit cost		15,000,000	13,000,000	$ 17,000,000
Prepaid pension expense		83,000,000	96,000,000
Other postretirement benefit obligations		33,000,000	36,000,000
Atlantic City Electric Co [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Number of amendments, PHI approved | Amendments				2
Reduction in net periodic benefit cost			$ 3,000,000
Percentage of postretirement benefit costs			45.00%
OPEB contributions		3,000,000	$ 3,000,000	$ 6,000,000
Atlantic City Electric Co [Member] | Retiree [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension contribution		0	0
Subsidiaries [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and other postretirement net periodic benefit cost		37,000,000	16,000,000	$ 26,000,000
Subsidiaries [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
OPEB contributions		$ 0	$ 0

XML

Pension and Other Postretirement Benefits - Amounts Recognized in Consolidated Balance Sheets (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Regulatory asset	$ 2,246	$ 2,409
Current liabilities	(2,308)	(2,056)
Pension benefit obligation	(466)	(396)
Other postretirement benefit obligations	(215)	(265)
Deferred income tax liabilities	(3,393)	(3,242)
Deferred income tax liabilities	15	17
Accumulated other comprehensive loss, net of tax	36	46	$ 34	$ 48
Pension Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Regulatory asset	870	871
Current liabilities	(6)	(6)
Pension benefit obligation	(466)	(396)
Deferred income tax liabilities	(162)	(193)
Accumulated other comprehensive loss, net of tax	28	37
Net amount recorded	264	313
Other Postretirement Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Regulatory asset	40	75
Other postretirement benefit obligations	(215)	(265)
Deferred income tax liabilities	70	77
Net amount recorded	$ (105)	$ (113)

XML

Pension and Other Postretirement Benefits - Schedule of Amounts Included in AOCL and Regulatory Assets (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Regulatory assets	$ 2,246	$ 2,409
Pension Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Unrecognized net actuarial loss	910	925
Unamortized prior service cost (credit)	6	8
Total	916	933
Accumulated other comprehensive loss ($28 million and $37 million, net of tax, at December 31, 2015 and 2014, respectively)	46	62
Regulatory assets	870	871
Total	916	933
Other Postretirement Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Unrecognized net actuarial loss	128	176
Unamortized prior service cost (credit)	(88)	(101)
Total	40	75
Regulatory assets	40	75
Total	$ 40	$ 75

XML

Pension and Other Postretirement Benefits - Schedule of Amounts Included in AOCL and Regulatory Assets (Parenthetical) (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Accumulated other comprehensive loss, net of tax	$ 36	$ 46	$ 34	$ 48
Pension Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Accumulated other comprehensive loss, net of tax	$ 28	$ 37

XML

Pension and Other Postretirement Benefits - Changes in Plan Assets and Benefit Obligations Recognized in AOCL and Regulatory Assets (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Benefits [Member]
Amounts amortized during the year:
Amortization of prior service (cost) credit	$ (2)	$ (2)	$ (2)
Amortization of net actuarial loss	(65)	(45)	(67)
Amounts arising during the year:
Current year prior service cost (credit)			3
Current year actuarial loss (gain)	50	276	(218)
Total recognized in AOCL and Regulatory assets for the year ended December 31	(17)	229	(284)
Other Postretirement Benefits [Member]
Amounts amortized during the year:
Amortization of prior service (cost) credit	13	13	11
Amortization of net actuarial loss	(8)	(3)	(12)
Amounts arising during the year:
Current year prior service cost (credit)			(124)
Current year actuarial loss (gain)	(39)	62	(109)
Total recognized in AOCL and Regulatory assets for the year ended December 31	$ (34)	$ 72	$ (234)

XML

Pension and Other Postretirement Benefits - Components of Net Periodic Benefit Costs (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost	$ 97	$ 58	$ 95
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	57	44	53
Interest cost	109	109	100
Expected return on plan assets	(140)	(141)	(145)
Amortization of prior service cost (credit)	2	2	2
Amortization of net actuarial loss	65	45	67
Net periodic benefit cost	93	59	77
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	7	7	8
Interest cost	24	26	29
Expected return on plan assets	(22)	(24)	(20)
Amortization of prior service cost (credit)	(13)	(13)	(11)
Amortization of net actuarial loss	8	3	12
Net periodic benefit cost	$ 4	$ (1)	$ 18

XML

Pension and Other Postretirement Benefits - Split of Combined Pension and Other Postretirement Net Periodic Benefit Costs (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost	$ 97	$ 58	$ 95
Potomac Electric Power Co [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost	30	22	34
Delmarva Power & Light Co/De [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost	15	7	18
Atlantic City Electric Co [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost	15	13	17
Subsidiaries [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost	$ 37	$ 16	$ 26

XML

Pension and Other Postretirement Benefits - Weighted Average Assumptions Used to Determine Benefit Obligations (Detail)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Pension Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Discount rate	4.65%	4.20%
Rate of compensation increase	5.00%	5.00%
Other Postretirement Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Discount rate	4.55%	4.15%
Rate of compensation increase	5.00%	5.00%
Rate to which the cost trend rate is assumed to decline for all eligible retirees (the ultimate trend rate)	5.00%	5.00%
Year that the cost trend rate reaches the ultimate trend rate	2020	2020
Other Postretirement Benefits [Member] | Pre 65 [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Health care cost trend rate assumed for current year	6.33%	6.67%
Other Postretirement Benefits [Member] | Post 65 [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Health care cost trend rate assumed for current year	5.40%	5.50%

XML

Pension and Other Postretirement Benefits - Weighted Average Assumptions Used to Determine Benefit Obligations (Parenthetical) (Detail)	Dec. 31, 2015
Qualified Pension Plans [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Discount rate	4.65%
Non Qualified Pension Plans [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Discount rate	4.55%

XML

Pension and Other Postretirement Benefits - Summary of Effect of One Percent Change in Assumed Health Care Cost (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($)
Compensation and Retirement Disclosure [Abstract]
Effect of one percentage point increase in total service and interest cost	$ 1
Effect of one percentage point increase in postretirement benefit obligation	15
Effect of one percentage point decrease in total service and interest cost	(1)
Effect of one percentage point decrease in postretirement benefit obligation	$ (18)

XML

Pension and Other Postretirement Benefits - Weighted Average Assumptions Used to Determine Net Periodic Benefit Costs (Detail)		12 Months Ended
	Jul. 01, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Discount rate		4.20%	5.05%	4.15%
Expected long-term return on plan assets		6.50%	7.00%	7.00%
Rate of compensation increase		5.00%	5.00%	5.00%
Other Postretirement Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Discount rate	4.95%	4.15%	5.00%	4.10%
Expected long-term return on plan assets		6.75%	7.25%	7.00%
Rate of compensation increase		5.00%	5.00%	5.00%
Health care cost trend rate		6.67%	7.00%	7.50%

XML

Pension and Other Postretirement Benefits - Weighted Average Assumptions Used to Determine Net Periodic Benefit Costs (Parenthetical) (Detail)		12 Months Ended
	Jul. 01, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Other Postretirement Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Updated discount rate	4.95%	4.15%	5.00%	4.10%

XML

Pension and Other Postretirement Benefits - Summary of Plan Asset Allocations (Detail)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Assets, Equity	28.00%	28.00%
Plan Assets, Fixed Income	66.00%	65.00%
Plan Assets, Other	6.00%	7.00%
Plan Assets, Total	100.00%	100.00%
Target Plan Asset Allocation, Equity	27.00%	27.00%
Target Plan Asset Allocation, Fixed Income	68.00%	68.00%
Target Plan Asset Allocation, Other	5.00%	5.00%
Target Plan Asset Allocation, Total	100.00%	100.00%
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Assets, Equity	63.00%	64.00%
Plan Assets, Fixed Income	34.00%	34.00%
Plan Assets, Cash	3.00%	2.00%
Plan Assets, Total	100.00%	100.00%
Target Plan Asset Allocation, Equity	60.00%	60.00%
Target Plan Asset Allocation, Fixed Income	35.00%	35.00%
Target Plan Asset Allocation, Cash	5.00%	5.00%
Target Plan Asset Allocation, Total	100.00%	100.00%

XML

Pension and Other Postretirement Benefits - Schedule of Fair Value of Plan Assets (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 1,397	$ 1,557
Pension Benefits [Member] | Equity Securities Domestic [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	311	341
Pension Benefits [Member] | Equity Securities International [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	216	255
Pension Benefits [Member] | Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	820	916
Pension Benefits [Member] | Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	50	45
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	326	340
Other Postretirement Benefits [Member] | Equity Securities Domestic [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	197	208
Other Postretirement Benefits [Member] | Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	120	126
Other Postretirement Benefits [Member] | Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	9	6
Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	385	427
Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member] | Pension Benefits [Member] | Equity Securities Domestic [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	120	128
Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member] | Pension Benefits [Member] | Equity Securities International [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	215	254
Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member] | Pension Benefits [Member] | Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	50	45
Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	326	340
Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member] | Other Postretirement Benefits [Member] | Equity Securities Domestic [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	197	208
Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member] | Other Postretirement Benefits [Member] | Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	120	126
Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member] | Other Postretirement Benefits [Member] | Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	9	6
Significant Other Observable Inputs (Level 2) [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	1,001	1,118
Significant Other Observable Inputs (Level 2) [Member] | Pension Benefits [Member] | Equity Securities Domestic [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	191	213
Significant Other Observable Inputs (Level 2) [Member] | Pension Benefits [Member] | Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	810	905
Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	11	12	$ 12
Significant Unobservable Inputs (Level 3) [Member] | Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	10	11	11
Significant Unobservable Inputs (Level 3) [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	1	1	1
Significant Unobservable Inputs (Level 3) [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	11	12
Significant Unobservable Inputs (Level 3) [Member] | Pension Benefits [Member] | Equity Securities International [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	1	1
Significant Unobservable Inputs (Level 3) [Member] | Pension Benefits [Member] | Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	10	11
Investments Measured at Fair Value [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	2,018	2,236	2,116
Investments Measured at Fair Value [Member] | Pension Benefits [Member] | Equity Securities Domestic [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	33	35
Investments Measured at Fair Value [Member] | Pension Benefits [Member] | Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	504	543
Investments Measured at Fair Value [Member] | Pension Benefits [Member] | Private Equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	38	47
Investments Measured at Fair Value [Member] | Pension Benefits [Member] | Real Estate [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	46	54
Investments Measured at Fair Value [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	348	367	$ 368
Investments Measured at Fair Value [Member] | Other Postretirement Benefits [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 22	$ 27

XML

Pension and Other Postretirement Benefits - Reconciliation of Fair Value Measurements Using Significant Unobservable Inputs (Detail) - Significant Unobservable Inputs (Level 3) [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at beginning of year	$ 12	$ 12
Transfer in (out) of Level 3	0	0
Purchases	0	0
Sales	0	0
Settlements	(1)
Unrealized gain (loss)	0	0
Realized gain	0	0
Fair value of plan assets at end of year	11	12
Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at beginning of year	1	1
Transfer in (out) of Level 3	0	0
Purchases	0	0
Sales	0	0
Unrealized gain (loss)	0	0
Realized gain	0	0
Fair value of plan assets at end of year	1	1
Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at beginning of year	11	11
Transfer in (out) of Level 3	0	0
Purchases	0	0
Sales	0	0
Settlements	(1)
Unrealized gain (loss)	0	0
Realized gain	0	0
Fair value of plan assets at end of year	$ 10	$ 11

XML

Pension and Other Postretirement Benefits - Schedule of Estimated Benefit Payments (Detail) $ in Millions	Dec. 31, 2015 USD ($)
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
2016	$ 143
2017	143
2018	148
2019	153
2020	158
2021 through 2025	836
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
2016	38
2017	38
2018	38
2019	38
2020	38
2021 through 2025	$ 189

XML

Debt - Components of Long-Term Debt (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Debt instrument, carrying value	$ 5,001	$ 4,817
Net unamortized discount	(2)	(10)
Unamortized debt issuance costs	(49)	(44)
Current portion of long-term debt	(294)	(366)
Total net long-term debt	4,656	4,397
Total long-term debt	5,001	4,817
First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt instrument, carrying value	4,424	3,889
Total long-term debt	4,424	3,889
Medium-Term Notes [Member]
Debt Instrument [Line Items]
Debt instrument, carrying value	40	40
Total long-term debt	40	40
Unsecured Notes [Member]
Debt Instrument [Line Items]
Debt instrument, carrying value	456	806
Total long-term debt	456	806
Transition Bonds [Member]
Debt Instrument [Line Items]
Debt instrument, carrying value	171	215
Unamortized debt issuance costs	(1)	(1)
Current portion of long-term debt	(46)	(44)
Total Net Long-Term Debt	124	170
Total long-term debt	$ 171	215
3.05% Due 2022 [Member] | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt interest percentage	3.05%
Debt instrument maturity date	2022
Debt instrument, carrying value	$ 200	200
Total long-term debt	$ 200	200
6.20% Due 2022 [Member] | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt interest percentage	6.20%
Debt instrument maturity date	2022
Debt instrument, carrying value	$ 110	110
Total long-term debt	$ 110	110
3.60% Due 2024 [Member] | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt interest percentage	3.60%
Debt instrument maturity date	2024
Debt instrument, carrying value	$ 400	400
Total long-term debt	$ 400	400
5.75% Due 2034 [Member] | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt interest percentage	5.75%
Debt instrument maturity date	2034
Debt instrument, carrying value	$ 100	100
Total long-term debt	$ 100	100
5.40% Due 2035 [Member] | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt interest percentage	5.40%
Debt instrument maturity date	2035
Debt instrument, carrying value	$ 175	175
Total long-term debt	$ 175	175
6.50% Due 2037 [Member] | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt interest percentage	6.50%
Debt instrument maturity date	2037
Debt instrument, carrying value	$ 500	500
Total long-term debt	$ 500	500
7.90% Due 2038 [Member] | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt interest percentage	7.90%
Debt instrument maturity date	2038
Debt instrument, carrying value	$ 250	250
Total long-term debt	$ 250	250
4.15% Due 2043 [Member] | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt interest percentage	4.15%
Debt instrument maturity date	2043
Debt instrument, carrying value	$ 450	250
Total long-term debt	$ 450	250
4.95% Due 2043 [Member] | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt interest percentage	4.95%
Debt instrument maturity date	2043
Debt instrument, carrying value	$ 150	150
Total long-term debt	150	150
4.91% Due 2017 [Member] | Transition Bonds [Member]
Debt Instrument [Line Items]
Debt instrument, carrying value		17
Total long-term debt		17
5.05% Due 2020 [Member] | Transition Bonds [Member]
Debt Instrument [Line Items]
Debt instrument, carrying value	39	51
Total long-term debt	39	51
5.55% Due 2023 [Member] | Transition Bonds [Member]
Debt Instrument [Line Items]
Debt instrument, carrying value	132	147
Total long-term debt	$ 132	147
2.70% Due 2015 [Member] | Unsecured Notes [Member]
Debt Instrument [Line Items]
Debt interest percentage	2.70%
Debt instrument maturity date	2015
Debt instrument, carrying value		250
Total long-term debt		250
5.90% Due 2016 [Member] | Unsecured Notes [Member]
Debt Instrument [Line Items]
Debt interest percentage	5.90%
Debt instrument maturity date	2016
Debt instrument, carrying value	$ 190	190
Total long-term debt	$ 190	190
6.125% Due 2017 [Member] | Unsecured Notes [Member]
Debt Instrument [Line Items]
Debt interest percentage	6.125%
Debt instrument maturity date	2017
Debt instrument, carrying value	$ 81	81
Total long-term debt	$ 81	81
7.45% Due 2032 [Member] | Unsecured Notes [Member]
Debt Instrument [Line Items]
Debt interest percentage	7.45%
Debt instrument maturity date	2032
Debt instrument, carrying value	$ 185	185
Total long-term debt	185	185
Atlantic City Electric Co [Member]
Debt Instrument [Line Items]
Debt instrument, carrying value	1,039	904
Net unamortized discount	(1)	(1)
Unamortized debt issuance costs	(6)	(6)
Current portion of long-term debt	(2)	(15)
Total net long-term debt	1,030	882
Total long-term debt	1,039	904
Atlantic City Electric Co [Member] | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt instrument, carrying value	1,039	904
Total long-term debt	1,039	904
Atlantic City Electric Co [Member] | Transition Bonds [Member]
Debt Instrument [Line Items]
Debt instrument, carrying value	171	215
Unamortized debt issuance costs	(1)	(1)
Current portion of long-term debt	(46)	(44)
Total Net Long-Term Debt	124	170
Total long-term debt	$ 171	215
Atlantic City Electric Co [Member] | 7.68% Due 2015 - 2016 [Member] | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt interest percentage	7.68%
Debt instrument maturity date, start	2015
Debt instrument maturity date, end	2016
Debt instrument, carrying value	$ 2	17
Total long-term debt	$ 2	17
Atlantic City Electric Co [Member] | 7.75% Due 2018 [Member] | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt interest percentage	7.75%
Debt instrument maturity date	2018
Debt instrument, carrying value	$ 250	250
Total long-term debt	$ 250	250
Atlantic City Electric Co [Member] | 6.80% Due 2021 [Member] | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt interest percentage	6.80%
Debt instrument maturity date	2021
Debt instrument, carrying value	$ 39	39
Total long-term debt	$ 39	39
Atlantic City Electric Co [Member] | 4.35% Due 2021 [Member] | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt interest percentage	4.35%
Debt instrument maturity date	2021
Debt instrument, carrying value	$ 200	200
Total long-term debt	$ 200	200
Atlantic City Electric Co [Member] | 3.375% Due 2024 [Member] | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt interest percentage	3.375%
Debt instrument maturity date	2024
Debt instrument, carrying value	$ 150	150
Total long-term debt	$ 150	150
Atlantic City Electric Co [Member] | 3.50% Due 2025 [Member] | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt interest percentage	3.50%
Debt instrument maturity date	2025
Debt instrument, carrying value	$ 150
Total long-term debt	$ 150
Atlantic City Electric Co [Member] | 4.875% Due 2029 [Member] | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt interest percentage	4.875%
Debt instrument maturity date	2029
Debt instrument, carrying value	$ 23	23
Total long-term debt	$ 23	23
Atlantic City Electric Co [Member] | 5.80% Due 2034 [Member] | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt interest percentage	5.80%
Debt instrument maturity date	2034
Debt instrument, carrying value	$ 120	120
Total long-term debt	$ 120	120
Atlantic City Electric Co [Member] | 5.80% Due 2036 [Member] | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt interest percentage	5.80%
Debt instrument maturity date	2036
Debt instrument, carrying value	$ 105	105
Total long-term debt	$ 105	105
Atlantic City Electric Co [Member] | 4.91% Due 2017 [Member] | Transition Bonds [Member]
Debt Instrument [Line Items]
Debt interest percentage	4.91%
Debt instrument maturity date	2017
Debt instrument, carrying value		17
Total long-term debt		17
Atlantic City Electric Co [Member] | 5.05% Due 2020 [Member] | Transition Bonds [Member]
Debt Instrument [Line Items]
Debt interest percentage	5.05%
Debt instrument maturity date	2020
Debt instrument, carrying value	$ 39	51
Total long-term debt	$ 39	51
Atlantic City Electric Co [Member] | 5.55% Due 2023 [Member] | Transition Bonds [Member]
Debt Instrument [Line Items]
Debt interest percentage	5.55%
Debt instrument maturity date	2023
Debt instrument, carrying value	$ 132	147
Total long-term debt	$ 132	147
Atlantic City Electric Co [Member] | 3.5% Due 2025 [Member] | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt interest percentage	3.50%
Debt instrument maturity date	2025
Debt instrument, carrying value	$ 150
Total long-term debt	150
Delmarva Power & Light Co/De [Member]
Debt Instrument [Line Items]
Debt instrument, carrying value	1,168	1,068
Net unamortized discount	2	3
Unamortized debt issuance costs	(9)	(8)
Current portion of long-term debt	(100)	(100)
Total net long-term debt	1,061	963
Total long-term debt	1,168	1,068
Delmarva Power & Light Co/De [Member] | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt instrument, carrying value	1,050	850
Total long-term debt	1,050	850
Delmarva Power & Light Co/De [Member] | Unsecured Tax-Exempt Bonds [Member]
Debt Instrument [Line Items]
Debt instrument, carrying value	78	78
Total long-term debt	78	78
Delmarva Power & Light Co/De [Member] | Medium-Term Notes [Member]
Debt Instrument [Line Items]
Debt instrument, carrying value	40	40
Total long-term debt	$ 40	40
Delmarva Power & Light Co/De [Member] | Unsecured Notes [Member]
Debt Instrument [Line Items]
Debt instrument, carrying value		100
Total long-term debt		100
Delmarva Power & Light Co/De [Member] | 5.22% Due 2016 [Member] | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt interest percentage	5.22%
Debt instrument maturity date	2016
Debt instrument, carrying value	$ 100	100
Total long-term debt	$ 100	100
Delmarva Power & Light Co/De [Member] | 3.50% Due 2023 [Member] | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt interest percentage	3.50%
Debt instrument maturity date	2023
Debt instrument, carrying value	$ 500	500
Total long-term debt	$ 500	500
Delmarva Power & Light Co/De [Member] | 4.00% Due 2042 [Member] | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt interest percentage	4.00%
Debt instrument maturity date	2042
Debt instrument, carrying value	$ 250	250
Total long-term debt	$ 250	250
Delmarva Power & Light Co/De [Member] | 4.15% Due 2045 [Member] | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt interest percentage	4.15%
Debt instrument maturity date	2045
Debt instrument, carrying value	$ 200
Total long-term debt	$ 200
Delmarva Power & Light Co/De [Member] | 5.40% Due 2031 [Member] | Unsecured Tax-Exempt Bonds [Member]
Debt Instrument [Line Items]
Debt interest percentage	5.40%
Debt instrument maturity date	2031
Debt instrument, carrying value	$ 78	78
Total long-term debt	$ 78	78
Delmarva Power & Light Co/De [Member] | 7.56% - 7.58% Due 2017 [Member] | Medium-Term Notes [Member]
Debt Instrument [Line Items]
Debt instrument maturity date	2017
Debt instrument percentage, minimum	7.56%
Debt instrument percentage, maximum	7.58%
Debt instrument, carrying value	$ 14	14
Total long-term debt	$ 14	14
Delmarva Power & Light Co/De [Member] | 6.81% Due 2018 [Member] | Medium-Term Notes [Member]
Debt Instrument [Line Items]
Debt interest percentage	6.81%
Debt instrument maturity date	2018
Debt instrument, carrying value	$ 4	4
Total long-term debt	$ 4	4
Delmarva Power & Light Co/De [Member] | 7.61% Due 2019 [Member] | Medium-Term Notes [Member]
Debt Instrument [Line Items]
Debt interest percentage	7.61%
Debt instrument maturity date	2019
Debt instrument, carrying value	$ 12	12
Total long-term debt	$ 12	12
Delmarva Power & Light Co/De [Member] | 7.72% Due 2027 [Member] | Medium-Term Notes [Member]
Debt Instrument [Line Items]
Debt interest percentage	7.72%
Debt instrument maturity date	2027
Debt instrument, carrying value	$ 10	10
Total long-term debt	$ 10	10
Delmarva Power & Light Co/De [Member] | 5.00% Due 2015 [Member] | Unsecured Notes [Member]
Debt Instrument [Line Items]
Debt interest percentage	5.00%
Debt instrument maturity date	2015
Debt instrument, carrying value	$ 0	100
Total long-term debt	0	100
Potomac Electric Power Co [Member]
Debt Instrument [Line Items]
Debt instrument, carrying value	2,335	2,135
Net unamortized discount	(3)	(11)
Unamortized debt issuance costs	(31)	(28)
Total net long-term debt	2,301	2,096
Total long-term debt	$ 2,335	2,135
Potomac Electric Power Co [Member] | 3.05% Due 2022 [Member] | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt interest percentage	3.05%
Debt instrument maturity date	2022
Debt instrument, carrying value	$ 200	200
Total long-term debt	$ 200	200
Potomac Electric Power Co [Member] | 6.20% Due 2022 [Member] | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt interest percentage	6.20%
Debt instrument maturity date	2022
Debt instrument, carrying value	$ 110	110
Total long-term debt	$ 110	110
Potomac Electric Power Co [Member] | 3.60% Due 2024 [Member] | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt interest percentage	3.60%
Debt instrument maturity date	2024
Debt instrument, carrying value	$ 400	400
Total long-term debt	$ 400	400
Potomac Electric Power Co [Member] | 5.75% Due 2034 [Member] | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt interest percentage	5.75%
Debt instrument maturity date	2034
Debt instrument, carrying value	$ 100	100
Total long-term debt	$ 100	100
Potomac Electric Power Co [Member] | 5.40% Due 2035 [Member] | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt interest percentage	5.40%
Debt instrument maturity date	2035
Debt instrument, carrying value	$ 175	175
Total long-term debt	$ 175	175
Potomac Electric Power Co [Member] | 6.50% Due 2037 [Member] | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt interest percentage	6.50%
Debt instrument maturity date	2037
Debt instrument, carrying value	$ 500	500
Total long-term debt	$ 500	500
Potomac Electric Power Co [Member] | 7.90% Due 2038 [Member] | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt interest percentage	7.90%
Debt instrument maturity date	2038
Debt instrument, carrying value	$ 250	250
Total long-term debt	$ 250	250
Potomac Electric Power Co [Member] | 4.15% Due 2043 [Member] | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt interest percentage	4.15%
Debt instrument maturity date	2043
Debt instrument, carrying value	$ 450	250
Total long-term debt	$ 450	250
Potomac Electric Power Co [Member] | 4.95% Due 2043 [Member] | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt interest percentage	4.95%
Debt instrument maturity date	2043
Debt instrument, carrying value	$ 150	150
Total long-term debt	$ 150	150
Pepco Energy Services [Member] | 6.70% - 7.46% Due 2017-2018 [Member] | Secured Notes [Member]
Debt Instrument [Line Items]
Debt instrument maturity date, start	2015
Debt instrument maturity date, end	2018
Debt instrument percentage, minimum	6.70%
Debt instrument percentage, maximum	7.46%
Debt instrument, carrying value	$ 3	4
Total long-term debt	$ 3	$ 4

XML

Debt - Additional Information (Detail)				12 Months Ended
	Jan. 13, 2016 USD ($)	Jul. 30, 2015 USD ($)	May. 10, 2013 USD ($)	Dec. 31, 2015 USD ($) Sublimit	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)
Debt Instrument [Line Items]
Debt instrument, carrying value				$ 5,001,000,000	$ 4,817,000,000
Maturities of long term debt, 2016				340,000,000
Maturities of long term debt, 2017				131,000,000
Maturities of long term debt, 2018				285,000,000
Maturities of long term debt, 2019				30,000,000
Maturities of long term debt, 2020				20,000,000
Maturities of long term debt, thereafter				4,366,000,000
On-going commercial paper				875,000,000
Short-term debt				1,063,000,000	$ 729,000,000
Variable rate demand bonds maturing 2017				26,000,000
Variable rate demand bonds maturing 2024				33,000,000
Variable rate demand bonds maturing 2028				16,000,000
Variable rate demand bonds maturing 2029				$ 30,000,000
Variable rate demand bonds weighted average interest rate				0.13%	0.19%
Amended description of Change in Control				The Consent amends the definition of "Change in Control" in the credit agreement to mean, following consummation of the Merger, an event or series of events by which Exelon no longer owns, directly or indirectly, 100% of the outstanding shares of voting stock of Pepco Holdings.
Ownership percentage of outstanding voting stock for Change in Control				100.00%
Purchase price				$ 5,000,000	$ 12,000,000
Contract payment period				15 years	9 years
Pepco Energy Services [Member]
Debt Instrument [Line Items]
Maturities of long term debt, 2016				$ 1,000,000
Maturities of long term debt, 2017				1,000,000
Maturities of long term debt, 2018				0
Maturities of long term debt, 2019				1,000,000
Maturities of long term debt, 2020				1,000,000
Maturities of long term debt, thereafter				1,000,000
Total long-term project funding (including current maturities)				5,000,000	$ 10,000,000
Purchase price						$ 7,000,000
Contract payment period						23 years
Senior Medium Term Notes One [Member]
Debt Instrument [Line Items]
Debt instrument, face amount				885,000,000
Medium-Term Notes [Member]
Debt Instrument [Line Items]
Debt instrument, carrying value				40,000,000	40,000,000
First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt instrument, carrying value				4,424,000,000	3,889,000,000
Transition Bonds [Member]
Debt Instrument [Line Items]
Debt instrument, carrying value				171,000,000	215,000,000
Unsecured Notes [Member]
Debt Instrument [Line Items]
Debt instrument, carrying value				456,000,000	806,000,000
Commercial Paper [Member]
Debt Instrument [Line Items]
Short-term debt				$ 658,000,000	624,000,000
Unsecured Syndicated Credit Facility [Member]
Debt Instrument [Line Items]
Credit facility, termination date				Aug. 01, 2018
Line of credit facility maximum borrowing capacity				$ 1,500,000,000
Parent company credit facility letter of credit, maximum				$ 500,000,000
Same day borrowings maximum percentage amount				10.00%
Swingline loan repayment period				14 days
Credit facility borrowing capacity				$ 750,000,000
Maximum amount of credit available to parent				1,250,000,000
Subsidiary borrowing limit under parent's credit facility				$ 500,000,000
Maximum number of sublimit reallocations per year | Sublimit				8
Borrowing capacity under the credit facility				$ 851,000,000	875,000,000
Utility subsidiaries combined cash and borrowing capacity				$ 576,000,000	413,000,000
Unsecured Syndicated Credit Facility [Member] | Maximum [Member]
Debt Instrument [Line Items]
Ratio of indebtedness to total capitalization				65.00%
Ratio of deferrable interest subordinated debt to total capitalization				15.00%
Unsecured Syndicated Credit Facility [Member] | Federal Funds Effective Rate [Member]
Debt Instrument [Line Items]
Debt instrument, percentage added to reference rate				0.50%
Unsecured Syndicated Credit Facility [Member] | One Month London Interbank Offered Rate [Member]
Debt Instrument [Line Items]
Debt instrument, percentage added to reference rate				1.00%
Term Loan [Member]
Debt Instrument [Line Items]
Short-term debt				$ 300,000,000
4.15% Due 2043 [Member] | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt instrument, face amount				$ 200,000,000
Debt instruments maturity date				Mar. 15, 2043
Debt instrument, interest percentage				4.15%
Debt instrument, yield percentage				3.90%
Debt instrument, premium				$ 8,000,000
Debt instrument, carrying value				$ 450,000,000	250,000,000
2.70% Due 2015 [Member] | Unsecured Notes [Member]
Debt Instrument [Line Items]
Debt instrument, interest percentage				2.70%
Debt instrument, carrying value					250,000,000
Repayment of first mortgage bonds				$ 250,000,000
Delmarva Power & Light Co/De [Member]
Debt Instrument [Line Items]
Debt instrument, carrying value				1,168,000,000	1,068,000,000
Repayment of first mortgage bonds				100,000,000
Maturities of long term debt, 2016				100,000,000
Maturities of long term debt, 2017				14,000,000
Maturities of long term debt, 2018				4,000,000
Maturities of long term debt, 2019				12,000,000
Maturities of long term debt, 2020				0
Maturities of long term debt, thereafter				1,038,000,000
On-going commercial paper				500,000,000
Short-term debt				210,000,000	$ 211,000,000
Variable rate demand bonds amount				105,000,000
Variable rate demand bonds maturing 2024				33,000,000
Variable rate demand bonds maturing 2028				16,000,000
Variable rate demand bonds maturing 2029				$ 30,000,000
Variable rate demand bonds weighted average interest rate				0.13%	0.19%
Amended description of Change in Control				The Consent amends the definition of "Change in Control" in the credit agreement to mean, following consummation of the Merger, an event or series of events by which Exelon no longer owns, directly or indirectly, 100% of the outstanding shares of voting stock of Pepco Holdings.
Ownership percentage of outstanding voting stock for Change in Control				100.00%
Variable rate demand bonds maturing 2017				$ 26,000,000
Delmarva Power & Light Co/De [Member] | Medium-Term Notes [Member]
Debt Instrument [Line Items]
Debt instrument, face amount				100,000,000
Debt instrument, carrying value				40,000,000	$ 40,000,000
Delmarva Power & Light Co/De [Member] | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt instrument, carrying value				1,050,000,000	850,000,000
Variable rate demand bonds amount				72,000,000
Delmarva Power & Light Co/De [Member] | Unsecured Notes [Member]
Debt Instrument [Line Items]
Debt instrument, carrying value					100,000,000
Delmarva Power & Light Co/De [Member] | Commercial Paper [Member]
Debt Instrument [Line Items]
Short-term debt				$ 105,000,000	$ 106,000,000
Commercial paper weighted average interest rate				0.47%	0.26%
Weighted average maturity, in days				4 days	5 days
Delmarva Power & Light Co/De [Member] | Unsecured Syndicated Credit Facility [Member]
Debt Instrument [Line Items]
Credit facility, termination date				Aug. 01, 2018
Line of credit facility maximum borrowing capacity				$ 1,500,000,000
Parent company credit facility letter of credit, maximum				$ 500,000,000
Same day borrowings maximum percentage amount				10.00%
Swingline loan repayment period				14 days
Credit facility borrowing capacity				$ 250,000,000
Maximum amount of credit available to parent				1,250,000,000
Subsidiary borrowing limit under parent's credit facility				$ 500,000,000
Maximum number of sublimit reallocations per year | Sublimit				8
Utility subsidiaries combined cash and borrowing capacity				$ 576,000,000	$ 413,000,000
Delmarva Power & Light Co/De [Member] | Unsecured Syndicated Credit Facility [Member] | Maximum [Member]
Debt Instrument [Line Items]
Ratio of indebtedness to total capitalization				65.00%
Ratio of deferrable interest subordinated debt to total capitalization				15.00%
Delmarva Power & Light Co/De [Member] | Unsecured Syndicated Credit Facility [Member] | Federal Funds Effective Rate [Member]
Debt Instrument [Line Items]
Debt instrument, percentage added to reference rate				0.50%
Delmarva Power & Light Co/De [Member] | Unsecured Syndicated Credit Facility [Member] | One Month London Interbank Offered Rate [Member]
Debt Instrument [Line Items]
Debt instrument, percentage added to reference rate				1.00%
Delmarva Power & Light Co/De [Member] | 4.15% Due 2045 [Member] | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt instrument, face amount				$ 200,000,000
Debt instruments maturity date				May 15, 2045
Debt instrument, interest percentage				4.15%
Debt instrument, carrying value				$ 200,000,000
Delmarva Power & Light Co/De [Member] | 5.00% Due 2015 [Member] | Unsecured Notes [Member]
Debt Instrument [Line Items]
Debt instruments maturity date				Jun. 01, 2015
Debt instrument, interest percentage				5.00%
Debt instrument, carrying value				$ 0	100,000,000
Atlantic City Electric Co [Member]
Debt Instrument [Line Items]
Debt instrument, carrying value				1,039,000,000	904,000,000
Maturities of long term debt, 2016				2,000,000
Maturities of long term debt, 2017				0
Maturities of long term debt, 2018				250,000,000
Maturities of long term debt, 2019				0
Maturities of long term debt, 2020				0
Maturities of long term debt, thereafter				787,000,000
On-going commercial paper				350,000,000
Short-term debt				$ 5,000,000	127,000,000
Variable rate demand bonds amount					$ 18,000,000
Variable rate demand bonds weighted average interest rate					0.05%
Amended description of Change in Control				The Consent amends the definition of "Change in Control" in the credit agreement to mean, following consummation of the Merger, an event or series of events by which Exelon no longer owns, directly or indirectly, 100% of the outstanding shares of voting stock of Pepco Holdings.
Ownership percentage of outstanding voting stock for Change in Control				100.00%
Atlantic City Electric Co [Member] | Senior Medium Term Notes One [Member]
Debt Instrument [Line Items]
Debt instrument, face amount				$ 227,000,000
Atlantic City Electric Co [Member] | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt instrument, carrying value				1,039,000,000	$ 904,000,000
Atlantic City Electric Co [Member] | Tax-Exempt Bonds [Member]
Debt Instrument [Line Items]
Debt instrument, face amount				62,000,000
Atlantic City Electric Co [Member] | Transition Bonds [Member]
Debt Instrument [Line Items]
Debt instrument, carrying value				171,000,000	215,000,000
Maturities of long term debt, 2016				46,000,000
Maturities of long term debt, 2017				35,000,000
Maturities of long term debt, 2018				31,000,000
Maturities of long term debt, 2019				18,000,000
Maturities of long term debt, 2020				20,000,000
Maturities of long term debt, thereafter				21,000,000
Atlantic City Electric Co [Member] | Commercial Paper [Member]
Debt Instrument [Line Items]
Short-term debt				$ 5,000,000	$ 127,000,000
Commercial paper weighted average interest rate				0.46%	0.27%
Weighted average maturity, in days				6 days	5 days
Atlantic City Electric Co [Member] | Unsecured Syndicated Credit Facility [Member]
Debt Instrument [Line Items]
Credit facility, termination date				Aug. 01, 2018
Line of credit facility maximum borrowing capacity				$ 1,500,000,000
Parent company credit facility letter of credit, maximum				$ 500,000,000
Same day borrowings maximum percentage amount				10.00%
Swingline loan repayment period				14 days
Credit facility borrowing capacity				$ 250,000,000
Maximum amount of credit available to parent				1,250,000,000
Subsidiary borrowing limit under parent's credit facility				$ 500,000,000
Maximum number of sublimit reallocations per year | Sublimit				8
Utility subsidiaries combined cash and borrowing capacity				$ 576,000,000	$ 413,000,000
Atlantic City Electric Co [Member] | Unsecured Syndicated Credit Facility [Member] | Maximum [Member]
Debt Instrument [Line Items]
Ratio of indebtedness to total capitalization				65.00%
Ratio of deferrable interest subordinated debt to total capitalization				15.00%
Atlantic City Electric Co [Member] | Unsecured Syndicated Credit Facility [Member] | Federal Funds Effective Rate [Member]
Debt Instrument [Line Items]
Debt instrument, percentage added to reference rate				0.50%
Atlantic City Electric Co [Member] | Unsecured Syndicated Credit Facility [Member] | One Month London Interbank Offered Rate [Member]
Debt Instrument [Line Items]
Debt instrument, percentage added to reference rate				1.00%
Atlantic City Electric Co [Member] | Term Loan [Member]
Debt Instrument [Line Items]
Debt instrument, face amount			$ 100,000,000
Debt instrument, percentage added to reference rate			0.75%
Atlantic City Electric Co [Member] | 3.50% Due 2025 [Member] | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt instrument, face amount				$ 150,000,000
Debt instruments maturity date				Dec. 01, 2025
Debt instrument, interest percentage				3.50%
Debt instrument, carrying value				$ 150,000,000
Atlantic City Electric Co [Member] | 7.68% Due 2015 [Member] | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt instruments maturity date				Aug. 24, 2015
Debt instrument, interest percentage				7.68%
Repayment of medium term notes				$ 15,000,000
Atlantic City Electric Co [Member] | Medium Term Notes Series C [Member]
Debt Instrument [Line Items]
Debt instruments maturity date				Aug. 24, 2015
Debt instrument, interest percentage				7.68%
Repayment of secured medium-term notes				$ 15,000,000
Potomac Electric Power Co [Member]
Debt Instrument [Line Items]
Debt instrument, carrying value				2,335,000,000	2,135,000,000
Maturities of long term debt, 2016				0
Maturities of long term debt, 2017				0
Maturities of long term debt, 2018				0
Maturities of long term debt, 2019				0
Maturities of long term debt, 2020				0
Maturities of long term debt, thereafter				2,335,000,000
On-going commercial paper				500,000,000
Short-term debt				$ 64,000,000	104,000,000
Amended description of Change in Control				The Consent amends the definition of "Change in Control" in the credit agreement to mean, following consummation of the Merger, an event or series of events by which Exelon no longer owns, directly or indirectly, 100% of the outstanding shares of voting stock of Pepco Holdings.
Ownership percentage of outstanding voting stock for Change in Control				100.00%
Purchase price				$ 5,000,000	$ 12,000,000
Contract payment period				15 years	9 years
Potomac Electric Power Co [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Debt instrument, face amount				$ 885,000,000
Potomac Electric Power Co [Member] | Tax-Exempt Bonds [Member]
Debt Instrument [Line Items]
Debt instrument, face amount				110,000,000
Potomac Electric Power Co [Member] | Commercial Paper [Member]
Debt Instrument [Line Items]
Short-term debt				$ 64,000,000	$ 104,000,000
Commercial paper weighted average interest rate				0.44%	0.28%
Weighted average maturity, in days				4 days	6 days
Potomac Electric Power Co [Member] | Unsecured Syndicated Credit Facility [Member]
Debt Instrument [Line Items]
Credit facility, termination date				Aug. 01, 2018
Line of credit facility maximum borrowing capacity				$ 1,500,000,000
Parent company credit facility letter of credit, maximum				$ 500,000,000
Same day borrowings maximum percentage amount				10.00%
Swingline loan repayment period				14 days
Credit facility borrowing capacity				$ 250,000,000
Maximum amount of credit available to parent				1,250,000,000
Subsidiary borrowing limit under parent's credit facility				$ 500,000,000
Maximum number of sublimit reallocations per year | Sublimit				8
Utility subsidiaries combined cash and borrowing capacity				$ 576,000,000	$ 413,000,000
Potomac Electric Power Co [Member] | Unsecured Syndicated Credit Facility [Member] | Maximum [Member]
Debt Instrument [Line Items]
Ratio of indebtedness to total capitalization				65.00%
Ratio of deferrable interest subordinated debt to total capitalization				15.00%
Potomac Electric Power Co [Member] | Unsecured Syndicated Credit Facility [Member] | Federal Funds Effective Rate [Member]
Debt Instrument [Line Items]
Debt instrument, percentage added to reference rate				0.50%
Potomac Electric Power Co [Member] | Unsecured Syndicated Credit Facility [Member] | One Month London Interbank Offered Rate [Member]
Debt Instrument [Line Items]
Debt instrument, percentage added to reference rate				1.00%
Potomac Electric Power Co [Member] | 4.15% Due 2043 [Member] | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Debt instrument, face amount				$ 200,000,000
Debt instruments maturity date				Mar. 15, 2043
Debt instrument, interest percentage				4.15%
Debt instrument, yield percentage				3.90%
Debt instrument, premium				$ 8,000,000
Debt instrument, carrying value				450,000,000	250,000,000
PHI [Member] | Commercial Paper [Member]
Debt Instrument [Line Items]
Short-term debt				$ 484,000,000	$ 287,000,000
Commercial paper weighted average interest rate				0.80%	0.57%
Weighted average maturity, in days				10 days	6 days
PHI [Member] | Term Loan [Member] | Term Loan One [Member]
Debt Instrument [Line Items]
Debt instruments maturity date				Jul. 28, 2016
Debt instrument, carrying value		$ 300,000,000
Debt instrument, percentage added to reference rate		0.95%
PHI [Member] | Term Loan [Member] | $500 Million Term Loan [Member]
Debt Instrument [Line Items]
Debt instruments maturity date				Jul. 13, 2016
PHI [Member] | Term Loan [Member] | Subsequent Event [Member] | $500 Million Term Loan [Member]
Debt Instrument [Line Items]
Debt instrument, carrying value	$ 500,000,000
Debt instrument, percentage added to reference rate	0.90%

XML

Debt - Components of Short-Term Debt (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Short-term Debt [Line Items]
Short-term debt	$ 1,063	$ 729
Delmarva Power & Light Co/De [Member]
Short-term Debt [Line Items]
Short-term debt	210	211
Atlantic City Electric Co [Member]
Short-term Debt [Line Items]
Short-term debt	5	127
Potomac Electric Power Co [Member]
Short-term Debt [Line Items]
Short-term debt	64	104
Term Loan [Member]
Short-term Debt [Line Items]
Short-term debt	300
Commercial Paper [Member]
Short-term Debt [Line Items]
Short-term debt	658	624
Commercial Paper [Member] | Delmarva Power & Light Co/De [Member]
Short-term Debt [Line Items]
Short-term debt	105	106
Commercial Paper [Member] | Atlantic City Electric Co [Member]
Short-term Debt [Line Items]
Short-term debt	5	127
Commercial Paper [Member] | Potomac Electric Power Co [Member]
Short-term Debt [Line Items]
Short-term debt	64	104
Variable Rate Demand Bonds [Member]
Short-term Debt [Line Items]
Short-term debt	105	105
Variable Rate Demand Bonds [Member] | Delmarva Power & Light Co/De [Member]
Short-term Debt [Line Items]
Short-term debt	$ 105	$ 105

XML

Income Taxes - Provision for Consolidated Income Taxes from Continuing Operations (Detail) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Current Tax (Benefit) Expense
Federal									$ (3)	$ (137)	$ (128)
State and local									12	(26)	(9)
Total Current Tax Expense (Benefit)									9	(163)	(137)
Deferred Tax Expense (Benefit)
Federal									92	261	393
State and local									30	41	65
Investment tax credit amortization									(2)	(1)	(2)
Total Deferred Tax Expense									120	301	456
Consolidated Income Tax Expense Related to Continuing Operations	$ 23	$ 49	$ 27	$ 30	$ 13	$ 34	$ 45	$ 46	129	138	319
Potomac Electric Power Co [Member]
Current Tax (Benefit) Expense
Federal									(57)	(79)	(39)
State and local									6	(3)	(1)
Total Current Tax Expense (Benefit)									(51)	(82)	(40)
Deferred Tax Expense (Benefit)
Federal									125	150	96
State and local									24	24	24
Investment tax credit amortization											(1)
Total Deferred Tax Expense									149	174	119
Consolidated Income Tax Expense Related to Continuing Operations	36	32	18	12	10	38	28	16	98	92	79
Delmarva Power & Light Co/De [Member]
Current Tax (Benefit) Expense
Federal									(26)	(45)	(8)
State and local									2
Total Current Tax Expense (Benefit)									(24)	(45)	(8)
Deferred Tax Expense (Benefit)
Federal									73	99	53
State and local									1	12	12
Investment tax credit amortization									(1)	(1)	(1)
Total Deferred Tax Expense									73	110	64
Consolidated Income Tax Expense Related to Continuing Operations	14	9	5	21	14	13	13	25	49	65	56
Atlantic City Electric Co [Member]
Current Tax (Benefit) Expense
Federal									(2)	(7)	(23)
State and local									3	(2)	(10)
Total Current Tax Expense (Benefit)									1	(9)	(33)
Deferred Tax Expense (Benefit)
Federal									25	30	28
State and local									5	7	25
Investment tax credit amortization											(1)
Total Deferred Tax Expense									30	37	52
Consolidated Income Tax Expense Related to Continuing Operations	$ 15	$ 7	$ 7	$ 2	$ 4	$ 14	$ 4	$ 6	$ 31	$ 28	$ 19

XML

Income Taxes - Reconciliation of Consolidated Income Tax Expense from Continuing Operations (Detail) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Rate Reconciliation [Line Items]
Income tax at Federal statutory rate									$ 156,000,000	$ 133,000,000	$ 150,000,000
State income taxes, net of federal effect									27,000,000	23,000,000	27,000,000
Asset removal costs									(14,000,000)	(12,000,000)	(14,000,000)
Change in estimates and interest related to uncertain and effectively settled tax positions									(46,000,000)		56,000,000
Deferred tax basis adjustments									7,000,000
Establishment of valuation allowances related to deferred tax assets											101,000,000
Merger related costs									4,000,000	7,000,000
Other, net									(5,000,000)	(13,000,000)	(1,000,000)
Consolidated Income Tax Expense Related to Continuing Operations	$ 23,000,000	$ 49,000,000	$ 27,000,000	$ 30,000,000	$ 13,000,000	$ 34,000,000	$ 45,000,000	$ 46,000,000	$ 129,000,000	$ 138,000,000	$ 319,000,000
Income tax at Federal statutory rate, percentage									35.00%	35.00%	35.00%
State income taxes, net of federal effect, percentage									6.00%	6.10%	6.30%
Asset removal costs, percentage									(3.10%)	(3.20%)	(3.30%)
Change in estimates and interest related to uncertain and effectively settled tax positions, percentage									(10.30%)		13.10%
Deferred tax basis adjustments, percentage									1.60%
Establishment of valuation allowances related to deferred tax assets, percentage											23.50%
Merger related costs, percentage									0.90%	1.80%
Other, net, percentage									(1.20%)	(3.40%)	(0.20%)
Consolidated income tax expense related to continuing operations, percentage									28.90%	36.30%	74.40%
Potomac Electric Power Co [Member]
Income Tax Rate Reconciliation [Line Items]
Income tax at Federal statutory rate									$ 100,000,000	$ 92,000,000	$ 80,000,000
State income taxes, net of federal effect									15,000,000	15,000,000	13,000,000
Asset removal costs									(14,000,000)	(12,000,000)	(14,000,000)
Change in estimates and interest related to uncertain and effectively settled tax positions									(6,000,000)	(1,000,000)	(3,000,000)
Deferred tax basis adjustments									6,000,000
Establishment of valuation allowances related to deferred tax assets									0	0
Other, net									(3,000,000)	(2,000,000)	3,000,000
Consolidated Income Tax Expense Related to Continuing Operations	36,000,000	32,000,000	18,000,000	12,000,000	10,000,000	38,000,000	28,000,000	16,000,000	$ 98,000,000	$ 92,000,000	$ 79,000,000
Income tax at Federal statutory rate, percentage									35.00%	35.00%	35.00%
State income taxes, net of federal effect, percentage									5.30%	5.70%	5.70%
Asset removal costs, percentage									(4.90%)	(4.60%)	(6.10%)
Change in estimates and interest related to uncertain and effectively settled tax positions, percentage									(2.10%)	(0.40%)	(1.30%)
Deferred tax basis adjustments, percentage									2.10%
Other, net, percentage									(1.00%)	(0.70%)	1.20%
Consolidated income tax expense related to continuing operations, percentage									34.40%	35.00%	34.50%
Delmarva Power & Light Co/De [Member]
Income Tax Rate Reconciliation [Line Items]
Income tax at Federal statutory rate									$ 44,000,000	$ 59,000,000	$ 51,000,000
State income taxes, net of federal effect									7,000,000	9,000,000	8,000,000
Change in estimates and interest related to uncertain and effectively settled tax positions									3,000,000		(1,000,000)
Establishment of valuation allowances related to deferred tax assets									0	0
Other, net									(5,000,000)	(3,000,000)	(2,000,000)
Consolidated Income Tax Expense Related to Continuing Operations	14,000,000	9,000,000	5,000,000	21,000,000	14,000,000	13,000,000	13,000,000	25,000,000	$ 49,000,000	$ 65,000,000	$ 56,000,000
Income tax at Federal statutory rate, percentage									35.00%	35.00%	35.00%
State income taxes, net of federal effect, percentage									5.60%	5.30%	5.50%
Change in estimates and interest related to uncertain and effectively settled tax positions, percentage									2.40%		(0.70%)
Other, net, percentage									(3.80%)	(1.80%)	(1.20%)
Consolidated income tax expense related to continuing operations, percentage									39.20%	38.50%	38.60%
Atlantic City Electric Co [Member]
Income Tax Rate Reconciliation [Line Items]
Income tax at Federal statutory rate									$ 24,000,000	$ 26,000,000	$ 24,000,000
State income taxes, net of federal effect									4,000,000	4,000,000	5,000,000
Change in estimates and interest related to uncertain and effectively settled tax positions									3,000,000	(1,000,000)	(9,000,000)
Deferred tax basis adjustments									2,000,000		(2,000,000)
Establishment of valuation allowances related to deferred tax assets									0	0
Investment tax credit amortization											(1,000,000)
Other, net									(2,000,000)	(1,000,000)	2,000,000
Consolidated Income Tax Expense Related to Continuing Operations	$ 15,000,000	$ 7,000,000	$ 7,000,000	$ 2,000,000	$ 4,000,000	$ 14,000,000	$ 4,000,000	$ 6,000,000	$ 31,000,000	$ 28,000,000	$ 19,000,000
Income tax at Federal statutory rate, percentage									35.00%	35.00%	35.00%
State income taxes, net of federal effect, percentage									5.80%	5.50%	7.20%
Change in estimates and interest related to uncertain and effectively settled tax positions, percentage									4.30%	(1.40%)	(13.00%)
Deferred tax basis adjustments, percentage									2.90%		(2.90%)
Investment tax credit amortization, percentage											(1.40%)
Other, net, percentage									(3.10%)	(0.70%)	2.60%
Consolidated income tax expense related to continuing operations, percentage									44.90%	38.40%	27.50%

XML

Income Taxes - Additional Information (Detail) - USD ($)		3 Months Ended									12 Months Ended
	Feb. 26, 2015	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Schedule of Income Tax [Line Items]
Tax expense (benefit)		$ 23,000,000	$ 49,000,000	$ 27,000,000	$ 30,000,000	$ 13,000,000	$ 34,000,000	$ 45,000,000	$ 46,000,000		$ 129,000,000	$ 138,000,000	$ 319,000,000
Change in estimates and interest related to uncertain tax positions													56,000,000
Establishment of valuation allowances on deferred tax assets		63,000,000				61,000,000					$ 63,000,000	61,000,000	101,000,000
PCI future deferred tax asset													101,000,000
Federal and state net operating losses, years											20 years
Federal and state net operating losses, expiration start period											2029
Federal and state net operating losses, expiration end period											2034
Unrecognized tax benefits that would impact effective tax rate		22,000,000									$ 22,000,000
Uncertain tax position pre-tax interest income (expense) recognized											35,000,000	1,000,000	(125,000,000)
Uncertain tax position after-tax interest income (expense) recognized											21,000,000		(75,000,000)
Accrued interest payable		49,000,000				47,000,000					49,000,000	47,000,000
Reduction in deferred tax liabilities		2,000,000			23,000,000
Other taxes for continuing operations											421,000,000	407,000,000	422,000,000
Uncertain tax positions settled in Global Tax Settlement											628,000,000		6,000,000
After-tax effect of revised lease rerun										$ 377,000,000
Valuation allowance for deferred tax assets													101,000,000
Change in estimates and interest related to uncertain and effectively settled tax positions											(46,000,000)		56,000,000
District of Columbia [Member]
Schedule of Income Tax [Line Items]
Corporate tax rate	9.975%
District of Columbia [Member] | 2019 [Member]
Schedule of Income Tax [Line Items]
Corporate tax rate	8.25%
District of Columbia [Member] | 2015 [Member]
Schedule of Income Tax [Line Items]
Corporate tax rate	9.40%
District of Columbia [Member] | 2016 [Member]
Schedule of Income Tax [Line Items]
Corporate tax rate	9.20%
Potomac Electric Power Co [Member]
Schedule of Income Tax [Line Items]
Tax expense (benefit)		36,000,000	32,000,000	18,000,000	12,000,000	10,000,000	38,000,000	28,000,000	16,000,000		$ 98,000,000	92,000,000	79,000,000
Federal and state net operating losses, years											20 years
Federal and state net operating losses, expiration start period											2029
Federal and state net operating losses, expiration end period											2034
Unrecognized tax benefits that would impact effective tax rate		8,000,000									$ 8,000,000
Uncertain tax position pre-tax interest income (expense) recognized											5,000,000	2,000,000	5,000,000
Uncertain tax position after-tax interest income (expense) recognized											3,000,000	1,000,000	3,000,000
Accrued interest receivable		0				9,000,000					0	9,000,000	9,000,000
Accrued interest payable		22,000,000				19,000,000					22,000,000	19,000,000
Reduction in deferred tax liabilities		2,000,000			23,000,000
Uncertain tax positions settled in Global Tax Settlement											40,000,000
Interest expense on uncertain tax positions		3,000,000
After-tax effect of revised lease rerun										377,000,000
After-tax non-cash charge										54,000,000
Additional interest income										5,000,000
Valuation allowance for deferred tax assets											0	0
Change in estimates and interest related to uncertain and effectively settled tax positions											(6,000,000)	(1,000,000)	(3,000,000)
Potomac Electric Power Co [Member] | District of Columbia [Member]
Schedule of Income Tax [Line Items]
Corporate tax rate	9.975%
Potomac Electric Power Co [Member] | District of Columbia [Member] | 2019 [Member]
Schedule of Income Tax [Line Items]
Corporate tax rate	8.25%
Potomac Electric Power Co [Member] | District of Columbia [Member] | 2015 [Member]
Schedule of Income Tax [Line Items]
Corporate tax rate	9.40%
Potomac Electric Power Co [Member] | District of Columbia [Member] | 2016 [Member]
Schedule of Income Tax [Line Items]
Corporate tax rate	9.20%
Delmarva Power & Light Co/De [Member]
Schedule of Income Tax [Line Items]
Tax expense (benefit)		14,000,000	9,000,000	5,000,000	21,000,000	14,000,000	13,000,000	13,000,000	25,000,000		$ 49,000,000	65,000,000	56,000,000
Federal and state net operating losses, years											20 years
Federal and state net operating losses, expiration start period											2029
Federal and state net operating losses, expiration end period											2034
Unrecognized tax benefits that would impact effective tax rate		3,000,000									$ 3,000,000
Uncertain tax position pre-tax interest income (expense) recognized											1,000,000	1,000,000	1,000,000
Accrued interest receivable		0				2,000,000					0	2,000,000	2,000,000
Accrued interest payable		7,000,000				7,000,000					7,000,000	7,000,000
Uncertain tax positions settled in Global Tax Settlement											9,000,000
After-tax effect of revised lease rerun										377,000,000
After-tax non-cash charge										54,000,000
Additional interest income										1,000,000
Valuation allowance for deferred tax assets											0	0
Change in estimates and interest related to uncertain and effectively settled tax positions											3,000,000		(1,000,000)
Atlantic City Electric Co [Member]
Schedule of Income Tax [Line Items]
Tax expense (benefit)		15,000,000	$ 7,000,000	$ 7,000,000	$ 2,000,000	4,000,000	$ 14,000,000	$ 4,000,000	$ 6,000,000		$ 31,000,000	28,000,000	19,000,000
Federal and state net operating losses, years											20 years
Federal and state net operating losses, expiration start period											2029
Federal and state net operating losses, expiration end period											2032
Unrecognized tax benefits that would impact effective tax rate		0									$ 0
Uncertain tax position pre-tax interest income (expense) recognized											1,000,000	1,000,000	12,000,000
Uncertain tax position after-tax interest income (expense) recognized											1,000,000	1,000,000	7,000,000
Accrued interest receivable		0				14,000,000					0	14,000,000	14,000,000
Accrued interest payable		13,000,000				13,000,000					13,000,000	13,000,000
Uncertain tax positions settled in Global Tax Settlement											3,000,000		6,000,000
After-tax effect of revised lease rerun										377,000,000
After-tax non-cash charge										54,000,000
Additional interest income										$ 6,000,000
Valuation allowance for deferred tax assets											0	0
Change in estimates and interest related to uncertain and effectively settled tax positions											3,000,000	(1,000,000)	(9,000,000)
Tax Settlement [Member]
Schedule of Income Tax [Line Items]
Total income tax benefit		(56,000,000)
Tax expense (benefit)		(47,000,000)
Income tax benefit discontinued operations		(9,000,000)
After-tax interest benefit		(21,000,000)
Uncertain tax positions settled in Global Tax Settlement		(26,000,000)
Deferred tax basis adjustments		7,000,000
Tax Settlement [Member] | Potomac Electric Power Co [Member]
Schedule of Income Tax [Line Items]
Tax expense (benefit)		(9,000,000)
After-tax interest benefit		(21,000,000)
Deferred tax basis adjustments		6,000,000
Uncertain tax positions, after-tax interest benefit		3,000,000
Uncertain tax positions settled in Global Tax Settlement		6,000,000
Tax Settlement [Member] | Delmarva Power & Light Co/De [Member]
Schedule of Income Tax [Line Items]
Tax expense (benefit)		3,000,000									3,000,000
After-tax interest benefit		(21,000,000)
Change in estimates and interest related to uncertain and effectively settled tax positions		3,000,000
Uncertain tax positions, after-tax interest benefit		1,000,000
Tax Settlement [Member] | Atlantic City Electric Co [Member]
Schedule of Income Tax [Line Items]
Tax expense (benefit)		3,000,000
After-tax interest benefit		(21,000,000)
Deferred tax basis adjustments		2,000,000
Change in estimates and interest related to uncertain and effectively settled tax positions		3,000,000
Uncertain tax positions, after-tax interest expense		1,000,000
Interest and Penalties [Member]
Schedule of Income Tax [Line Items]
Accrued interest receivable						$ 2,000,000						2,000,000	$ 2,000,000
Accrued interest payable		2,000,000									2,000,000
Pepco Energy Services' Energy Savings Performance Contract [Member]
Schedule of Income Tax [Line Items]
Tax benefit related to certain energy efficiency tax deductions											6,000,000	$ 5,000,000
Minimum [Member]
Schedule of Income Tax [Line Items]
Estimated possible decrease in unrecognized tax benefit		6,000,000									6,000,000
Minimum [Member] | Potomac Electric Power Co [Member]
Schedule of Income Tax [Line Items]
Estimated possible decrease in unrecognized tax benefit		3,000,000									3,000,000
Minimum [Member] | Delmarva Power & Light Co/De [Member]
Schedule of Income Tax [Line Items]
Estimated possible decrease in unrecognized tax benefit		0									0
Minimum [Member] | Atlantic City Electric Co [Member]
Schedule of Income Tax [Line Items]
Estimated possible decrease in unrecognized tax benefit		0									0
Maximum [Member]
Schedule of Income Tax [Line Items]
Estimated possible decrease in unrecognized tax benefit		10,000,000									10,000,000
Maximum [Member] | Potomac Electric Power Co [Member]
Schedule of Income Tax [Line Items]
Estimated possible decrease in unrecognized tax benefit		5,000,000									5,000,000
Maximum [Member] | Delmarva Power & Light Co/De [Member]
Schedule of Income Tax [Line Items]
Estimated possible decrease in unrecognized tax benefit		0									0
Maximum [Member] | Atlantic City Electric Co [Member]
Schedule of Income Tax [Line Items]
Estimated possible decrease in unrecognized tax benefit		$ 0									$ 0

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Income Taxes - Components of Consolidated Deferred Tax Liabilities (Assets) (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Schedule Of Deferred Income Tax Assets And Liabilities [Line Items]
Depreciation and other basis differences related to plant and equipment	$ 3,273	$ 2,962
Deferred electric service and electric restructuring liabilities	43	67
Federal and state net operating losses	(446)	(400)
Valuation allowances on state net operating losses	63	61	$ 101
Pension and other postretirement benefits	92	116
Deferred taxes on amounts to be collected through future rates	86	94
Other	267	325
Total Consolidated Deferred Tax Liabilities, net	3,378	3,225
Deferred tax assets included in Other Assets	0	0
Total Consolidated Deferred Tax Liabilities, net	3,393	3,242
Potomac Electric Power Co [Member]
Schedule Of Deferred Income Tax Assets And Liabilities [Line Items]
Depreciation and other basis differences related to plant and equipment	1,541	1,423
Federal and state net operating losses	(141)	(186)
Pension and other postretirement benefits	95	103
Deferred taxes on amounts to be collected through future rates	55	59
Other	171	180
Total Consolidated Deferred Tax Liabilities, net	1,721	1,579
Total Consolidated Deferred Tax Liabilities, net	1,721	1,579
Delmarva Power & Light Co/De [Member]
Schedule Of Deferred Income Tax Assets And Liabilities [Line Items]
Depreciation and other basis differences related to plant and equipment	899	797
Deferred electric service and electric restructuring liabilities	(4)	(4)
Federal and state net operating losses	(122)	(115)
Pension and other postretirement benefits	75	80
Deferred taxes on amounts to be collected through future rates	15	19
Other	78	101
Total Consolidated Deferred Tax Liabilities, net	941	878
Total Consolidated Deferred Tax Liabilities, net	941	878
Atlantic City Electric Co [Member]
Schedule Of Deferred Income Tax Assets And Liabilities [Line Items]
Depreciation and other basis differences related to plant and equipment	773	691
Deferred electric service and electric restructuring liabilities	47	71
Federal and state net operating losses	(9)	(26)
Pension and other postretirement benefits	20	25
Deferred taxes on amounts to be collected through future rates	17	16
Payment for termination of purchased power contracts with NUGs	34	38
Other	6	40
Total Consolidated Deferred Tax Liabilities, net	888	855
Total Consolidated Deferred Tax Liabilities, net	$ 888	$ 855

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Income Taxes - Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Unrecognized Tax Benefits [Line Items]
Unrecognized Tax Benefits, Beginning balance	$ 850	$ 831	$ 200
Tax positions related to current year, Additions		4	3
Tax positions related to current year, Reductions		(2)
Tax positions related to prior years, Additions	13	27	646
Tax positions related to prior years, Reductions	(201)	(10)	(12)
Settlements	(628)		(6)
Unrecognized Tax Benefits, Ending balance	34	850	831
Potomac Electric Power Co [Member]
Unrecognized Tax Benefits [Line Items]
Unrecognized Tax Benefits, Beginning balance	97	101	91
Tax positions related to current year, Additions		1	1
Tax positions related to current year, Reductions		(2)
Tax positions related to prior years, Additions	10	1	12
Tax positions related to prior years, Reductions	(55)	(4)	(3)
Settlements	(40)
Unrecognized Tax Benefits, Ending balance	12	97	101
Delmarva Power & Light Co/De [Member]
Unrecognized Tax Benefits [Line Items]
Unrecognized Tax Benefits, Beginning balance	22	9	9
Tax positions related to current year, Additions		1
Tax positions related to current year, Reductions			0
Tax positions related to prior years, Additions	3	13
Tax positions related to prior years, Reductions	(13)	(1)
Settlements	(9)
Unrecognized Tax Benefits, Ending balance	3	22	9
Atlantic City Electric Co [Member]
Unrecognized Tax Benefits [Line Items]
Unrecognized Tax Benefits, Beginning balance	13	9	17
Tax positions related to current year, Additions		1	2
Tax positions related to prior years, Additions		5	1
Tax positions related to prior years, Reductions	(10)	(2)	(5)
Settlements	$ (3)		(6)
Unrecognized Tax Benefits, Ending balance		$ 13	$ 9

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Income Taxes - Other Taxes (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Schedule of Income Tax [Line Items]
Gross Receipts/Delivery	$ 124	$ 123	$ 133
Property	92	84	77
County Fuel and Energy	143	143	153
Environmental, Use and Other	68	63	65
Total	427	413	428
Potomac Electric Power Co [Member]
Schedule of Income Tax [Line Items]
Gross Receipts/Delivery	107	107	108
Property	55	51	45
County Fuel and Energy	143	143	153
Environmental, Use and Other	64	62	62
Total	369	363	368
Delmarva Power & Light Co/De [Member]
Schedule of Income Tax [Line Items]
Gross Receipts/Delivery	17	16	15
Property	28	24	24
Environmental, Use and Other	2	2	1
Total	47	42	40
Atlantic City Electric Co [Member]
Schedule of Income Tax [Line Items]
Gross Receipts/Delivery			10
Property	4	3	3
Environmental, Use and Other	1	(1)	1
Total	$ 5	$ 2	$ 14

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Stock-Based Compensation, Dividend Restrictions, and Calculations of Earnings Per Share of Common Stock - Additional Information (Detail)		12 Months Ended
	Feb. 27, 2013 USD ($) $ / EquityUnit	Dec. 31, 2015 USD ($) shares	Dec. 31, 2014 USD ($) shares	Dec. 31, 2013 USD ($) shares	Dec. 31, 2012 $ / shares shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares of common stock authorized for issuance | shares		10,000,000
Capitalized stock-based compensation expense		$ 0	$ 0	$ 0
Eligible percentage of common stock over the performance period target award minimum		25.00%
Eligible percentage of common stock over the performance period target award maximum		200.00%
Requisite service period (years)		3 years
Vesting Period		1 year	1 year
Unrecognized compensation expense		$ 12,000,000
Costs recognized, weighted average period (years)		2 years
Stock option expiration (years)		10 years
Stock options outstanding | shares		0
Recognized compensation expense		$ 0	$ 1,000,000	$ 0
Deferred compensation balance		$ 2,000,000	2,000,000
Ratio of equity to total capitalization		30.00%
Retained earnings		$ 617,000,000	$ 565,000,000
Restricted net assets for consolidated subsidiaries		2,633,000,000
Shares of PHI common stock | shares					17,922,077
Public offering price | $ / shares					$ 19.25
Underwriting discount | $ / shares					0.67375
Initial pricing of equity forward instruments | $ / shares					$ 18.57625
Forward sale price | $ / EquityUnit	17.39
Proceeds from equity forward transaction	$ 312,000,000
Purchases of common stock minimum per calendar month		25
Purchases of common stock maximum per calendar year		$ 300,000
Shares issued and sold under the DRP | shares		1,000,000	1,000,000	2,000,000
2012 LTIP [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares of common stock authorized for issuance | shares		8,000,000
Performance Based Restricted Stock Award [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense		$ 13,000,000	$ 18,000,000	$ 12,000,000
Time-Based Restricted Stock Units were Granted to Each Non-Employee Director [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted stock units were granted to each non-employee director | shares		22,901	21,138
Vesting Period		3 years

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Stock-Based Compensation, Dividend Restrictions, and Calculations of Earnings Per Share of Common Stock - Schedule of Restricted Stock and Restricted Stock Units (Detail)	12 Months Ended
	Dec. 31, 2015 $ / shares shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares outstanding, beginning balance	1,421,380
Granted, number of shares	504,738
Forfeited, number of shares	(3,044)
Vested, number of shares	(807,040)
Number of shares outstanding, ending balance	1,116,034
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares outstanding, beginning balance	54,165
Number of shares outstanding, ending balance	54,165
Weighted average grant date fair value, beginning of period | $ / shares	$ 26.80
Weighted average grant date fair value, ending of period | $ / shares	$ 26.80
Performance-Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares outstanding, beginning balance	70,276
Granted, number of shares	48,347
Vested, number of shares	(93,906)
Number of shares outstanding, ending balance	24,717
Weighted average grant date fair value, beginning of period | $ / shares	$ 27.01
Granted, weighted average grant date fair value | $ / shares	26.10
Vested, weighted average grant date fair value | $ / shares	26.78
Weighted average grant date fair value, ending of period | $ / shares	$ 26.10
Time-Based Restricted Stock Units Award [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares outstanding, beginning balance	468,958
Granted, number of shares	450,203
Forfeited, number of shares	(2,218)
Vested, number of shares	(288,429)
Number of shares outstanding, ending balance	628,514
Weighted average grant date fair value, beginning of period | $ / shares	$ 19.61
Granted, weighted average grant date fair value | $ / shares	27.40
Forfeited, weighted average grant date fair value | $ / shares	27.00
Vested, weighted average grant date fair value | $ / shares	20.61
Weighted average grant date fair value, ending of period | $ / shares	$ 24.71
Performance Based Restricted Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares outstanding, beginning balance	827,981
Granted, number of shares	6,188
Forfeited, number of shares	(826)
Vested, number of shares	(424,705)
Number of shares outstanding, ending balance	408,638
Weighted average grant date fair value, beginning of period | $ / shares	$ 17.73
Granted, weighted average grant date fair value | $ / shares	26.08
Forfeited, weighted average grant date fair value | $ / shares	19.33
Vested, weighted average grant date fair value | $ / shares	17.05
Weighted average grant date fair value, ending of period | $ / shares	$ 18.56

XML

Stock-Based Compensation, Dividend Restrictions, and Calculations of Earnings Per Share of Common Stock - Schedule of Restricted Stock and Restricted Stock Units (Parenthetical) (Detail)	Dec. 31, 2014 shares
Executive Officer [Member] | Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares vested but not yet settled	36,110
Executive Officer [Member] | Time-Based Restricted Stock Units Award [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares vested but not yet settled	113,385
Executive Officer [Member] | Performance Based Restricted Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares vested but not yet settled	104,628
Director [Member] | Time-Based Restricted Stock Units Award [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares vested but not yet settled	30,784

XML

Stock-Based Compensation, Dividend Restrictions, and Calculations of Earnings Per Share of Common Stock - Weighted Average Grant Date Fair Value Per Share (Detail) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant-date fair value per share of award granted during the year		$ 26.80
Performance-Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant-date fair value per share of award granted during the year	$ 26.10	27.01
Time-Based Restricted Stock Units Award [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant-date fair value per share of award granted during the year	27.40	19.77	$ 19.70
Performance Based Restricted Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant-date fair value per share of award granted during the year	$ 26.08	$ 18.53	$ 17.03

XML

Stock-Based Compensation, Dividend Restrictions, and Calculations of Earnings Per Share of Common Stock - Dividends Received from Subsidiaries (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Dividends received from subsidiaries	$ 250	$ 212	$ 136
Potomac Electric Power Co [Member]
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Dividends received from subsidiaries	146	86	46
Delmarva Power & Light Co/De [Member]
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Dividends received from subsidiaries	92	100	30
Atlantic City Electric Co [Member]
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Dividends received from subsidiaries	$ 12	$ 26	$ 60

XML

Stock-Based Compensation, Dividend Restrictions, and Calculations of Earnings Per Share of Common Stock - Calculation of Earnings Per Share of Common Stock (Detail) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Earnings Per Share [Abstract]
Net Income from Continuing Operations	$ 121	$ 91	$ 53	$ 53					$ 318	$ 242	$ 110
Net income (loss) from discontinued operations	9								9		(322)
Net Income (Loss)	$ 130	$ 91	$ 53	$ 53	$ 35	$ 79	$ 53	$ 75	$ 327	$ 242	$ (212)
Average shares outstanding									253	251	246
Adjustment to shares outstanding									0	0	0
Weighted Average Shares Outstanding for Computation of Basic Earnings Per Share of Common Stock									253	251	246
Net effect of potentially dilutive shares									1	1
Weighted Average Shares Outstanding for Computation of Diluted Earnings Per Share of Common Stock									254	252	246
Basic earnings per share of common stock from continuing operations									$ 1.25	$ 0.96	$ 0.45
Basic earnings (loss) per share of common stock from discontinued operations									0.04		(1.31)
Basic earnings (loss) per share									1.29	0.96	(0.86)
Diluted earnings per share of common stock from continuing operations									1.25	0.96	0.45
Diluted earnings (loss) per share of common stock from discontinued operations									0.04		(1.31)
Diluted earnings (loss) per share									$ 1.29	$ 0.96	$ (0.86)

XML

Stock-Based Compensation, Dividend Restrictions, and Calculations of Earnings Per Share of Common Stock - Calculation of Earnings Per Share of Common Stock (Parenthetical) (Detail) - shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Earnings Per Share [Abstract]
Antidilutive securities excluded from computation of earnings per share, amount	0	0	0

XML

Stock-Based Compensation, Dividend Restrictions, and Calculations of Earnings Per Share of Common Stock - Common Stock Reserved and Unissued (Detail)	Dec. 31, 2015 shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares	22,123,913
DRP [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares	4,584,077
Pepco Holdings Long-Term Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares	6,946,614
Pepco Holdings 2012 Long-Term Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares	7,136,961
Pepco Holdings Retirement Savings Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares	3,456,261

XML

Preferred Stock - Additional Information (Detail) - USD ($)							3 Months Ended	12 Months Ended
	Jul. 24, 2015	Apr. 27, 2015	Jan. 26, 2015	Oct. 27, 2014	Jul. 29, 2014	Apr. 30, 2014	Sep. 30, 2015	Dec. 31, 2015	Dec. 31, 2014	Apr. 29, 2014
Class of Stock [Line Items]
Amount of Non Voting Series A Preferred Stock Purchase price								$ 54,000,000	$ 126,000,000
Redemption of issued and outstanding Preferred Stock, par value								$ 0.01	$ 0.01
Increase in fair value of preferred stock derivative							$ 15,000,000	$ 15,000,000
Non-Voting Series A Preferred Stock [Member]
Class of Stock [Line Items]
Issuance of non-voting Series A Preferred Stock, shares issued						9,000
Non-voting Series A Preferred Stock, maximum number of shares issued	1,800	1,800	1,800	1,800	1,800
Non-voting Series A Preferred Stock, shares purchased price						$ 90,000,000
Amount of Non Voting Series A Preferred Stock Purchase price	$ 18,000,000	$ 18,000,000	$ 18,000,000	$ 18,000,000	$ 18,000,000
Non-voting Series A Preferred Stock, maximum aggregate consideration										$ 180,000,000
Non-voting Series A Preferred Stock, cumulative, non-participating cash dividend						0.10%
Redemption of preferred stock at purchase price								$ 10,000
Redemption of issued and outstanding Preferred Stock, par value								$ 0.01
Non-Voting Series A Preferred Stock [Member] | Maximum [Member]
Class of Stock [Line Items]
Non-voting Series A Preferred Stock, maximum number of shares issued										18,000
Preferred Stock [Member]
Class of Stock [Line Items]
Derivative instruments, assets								$ 18,000,000	$ 3,000,000

XML

Derivative Instruments and Hedging Activities - Fair Values of Derivative Instruments by Balance Sheet Location (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Gross Derivative Instruments [Member]
Derivative [Line Items]
Derivative assets (current assets)	$ 18	$ 3
Derivative liabilities (current liabilities)	(2)	(4)
Net derivative (liability) asset	16	(1)
Net Derivative Instruments [Member]
Derivative [Line Items]
Derivative assets (current assets)	18	3
Net derivative (liability) asset	18	3
Other Derivative Instruments [Member]
Derivative [Line Items]
Derivative assets (current assets)	18	3
Derivative liabilities (current liabilities)	(2)	(4)
Net derivative (liability) asset	16	(1)
Delmarva Power & Light Co/De [Member] | Gross Derivative Instruments [Member]
Derivative [Line Items]
Derivative liabilities (current liabilities)	(2)	(4)
Delmarva Power & Light Co/De [Member] | Other Derivative Instruments [Member]
Derivative [Line Items]
Derivative liabilities (current liabilities)	(2)	(4)
Effects of Cash Collateral and Netting [Member]
Derivative [Line Items]
Derivative liabilities (current liabilities)	2	4
Net derivative (liability) asset	2	4
Effects of Cash Collateral and Netting [Member] | Delmarva Power & Light Co/De [Member]
Derivative [Line Items]
Derivative liabilities (current liabilities)	$ 2	$ 4

XML

Derivative Instruments and Hedging Activities - Schedule of Cash Collateral Offset Against Derivative Positions (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Derivative [Line Items]
Cash collateral pledged to counterparties with the right to reclaim	$ 2	$ 4
Delmarva Power & Light Co/De [Member]
Derivative [Line Items]
Cash collateral pledged to counterparties with the right to reclaim	$ 2	$ 4

XML

Derivative Instruments and Hedging Activities - Cash Flow Hedges Included in Accumulated Other Comprehensive Loss (Detail) - Interest Rate [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Derivative Instruments, Gain (Loss) [Line Items]
Accumulated Other Comprehensive Loss After-tax	$ 8	$ 9
Portion Expected to be Reclassified to Income during the Next 12 Months	$ 1	$ 1
Maximum Term	200 months	212 months

XML

Derivative Instruments and Hedging Activities - Net Unrealized and Realized Derivative Gains (Losses) Deferred as Regulatory Liabilities and Regulatory Assets (Detail) - Other Derivative Activity [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative Instruments, Gain (Loss) [Line Items]
Net unrealized (loss) gain arising during the period	$ (3)	$ (3)	$ 4
Net realized (loss) gain recognized during the period	(5)	2	(4)
Delmarva Power & Light Co/De [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Net unrealized (loss) gain arising during the period	(3)	(3)	1
Net realized (loss) gain recognized during the period	$ (5)	$ 2	$ (4)

XML

Derivative Instruments and Hedging Activities - Net Outstanding Commodity Forward Contracts That Did Not Qualify For Hedge Accounting (Detail) - Natural Gas [Member] - Long [Member] - Other Derivative Instruments [Member] - MMBTU	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Derivative [Line Items]
Quantity	4,190,000	3,892,500
Delmarva Power & Light Co/De [Member]
Derivative [Line Items]
Quantity	4,190,000	3,892,500

XML

Derivative Instruments and Hedging Activities - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Net unrealized gain on derivative assets	$ 15	$ 15

XML

Fair Value Disclosures - Fair Value of Financial Assets and Liabilities Measured on Recurring Basis (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial instruments, assets	$ 133	$ 122
Financial instruments, liabilities	32	34
Preferred Stock [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, assets	18	3
Treasury Funds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash equivalents and restricted cash equivalents	42
Restricted cash equivalents		38
Money Market Funds and Short-term Investments [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan assets	27	35
Life Insurance Contracts [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan assets	46	46
Executive deferred compensation plan liabilities	30	30
Natural Gas [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, liabilities	2	4
Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial instruments, assets	54	52
Financial instruments, liabilities	2	4
Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member] | Treasury Funds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash equivalents and restricted cash equivalents	42
Restricted cash equivalents		38
Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member] | Money Market Funds and Short-term Investments [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan assets	12	14
Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member] | Natural Gas [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, liabilities	2	4
Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial instruments, assets	42	48
Financial instruments, liabilities	30	30
Significant Other Observable Inputs (Level 2) [Member] | Money Market Funds and Short-term Investments [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan assets	15	21
Significant Other Observable Inputs (Level 2) [Member] | Life Insurance Contracts [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan assets	27	27
Executive deferred compensation plan liabilities	30	30
Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial instruments, assets	37	22
Significant Unobservable Inputs (Level 3) [Member] | Preferred Stock [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, assets	18	3
Significant Unobservable Inputs (Level 3) [Member] | Life Insurance Contracts [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan assets	19	19
Potomac Electric Power Co [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial instruments, assets	70	80
Financial instruments, liabilities	6	7
Potomac Electric Power Co [Member] | Treasury Funds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash equivalents and restricted cash equivalents	2
Restricted cash equivalents		5
Potomac Electric Power Co [Member] | Money Market Funds and Short-term Investments [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan assets	26	34
Potomac Electric Power Co [Member] | Life Insurance Contracts [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan assets	42	41
Executive deferred compensation plan liabilities	6	7
Potomac Electric Power Co [Member] | Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial instruments, assets	13	18
Potomac Electric Power Co [Member] | Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member] | Treasury Funds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash equivalents and restricted cash equivalents	2
Restricted cash equivalents		5
Potomac Electric Power Co [Member] | Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member] | Money Market Funds and Short-term Investments [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan assets	11	13
Potomac Electric Power Co [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial instruments, assets	38	44
Financial instruments, liabilities	6	7
Potomac Electric Power Co [Member] | Significant Other Observable Inputs (Level 2) [Member] | Money Market Funds and Short-term Investments [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan assets	15	21
Potomac Electric Power Co [Member] | Significant Other Observable Inputs (Level 2) [Member] | Life Insurance Contracts [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan assets	23	23
Executive deferred compensation plan liabilities	6	7
Potomac Electric Power Co [Member] | Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial instruments, assets	19	18
Potomac Electric Power Co [Member] | Significant Unobservable Inputs (Level 3) [Member] | Life Insurance Contracts [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan assets	19	18
Delmarva Power & Light Co/De [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial instruments, assets		7
Financial instruments, liabilities	3	5
Delmarva Power & Light Co/De [Member] | Treasury Funds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Restricted cash equivalents		5
Delmarva Power & Light Co/De [Member] | Life Insurance Contracts [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan assets		1
Executive deferred compensation plan liabilities	1	1
Delmarva Power & Light Co/De [Member] | Natural Gas [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, liabilities	2	4
Delmarva Power & Light Co/De [Member] | Money Market Funds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan assets		1
Delmarva Power & Light Co/De [Member] | Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial instruments, assets		6
Financial instruments, liabilities	2	4
Delmarva Power & Light Co/De [Member] | Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member] | Treasury Funds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Restricted cash equivalents		5
Delmarva Power & Light Co/De [Member] | Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member] | Natural Gas [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, liabilities	2	4
Delmarva Power & Light Co/De [Member] | Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member] | Money Market Funds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan assets		1
Delmarva Power & Light Co/De [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial instruments, liabilities	1	1
Delmarva Power & Light Co/De [Member] | Significant Other Observable Inputs (Level 2) [Member] | Life Insurance Contracts [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan liabilities	1	1
Delmarva Power & Light Co/De [Member] | Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial instruments, assets		1
Delmarva Power & Light Co/De [Member] | Significant Unobservable Inputs (Level 3) [Member] | Life Insurance Contracts [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan assets		1
Atlantic City Electric Co [Member] | Treasury Funds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash equivalents and restricted cash equivalents	30	24
Atlantic City Electric Co [Member] | Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member] | Treasury Funds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash equivalents and restricted cash equivalents	$ 30	$ 24

XML

Fair Value Disclosures - Reconciliations of Fair Value Measurements Using Significant Unobservable Inputs (Level 3) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Preferred Stock [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance	$ 3
Included in income	15
Included in accumulated other comprehensive loss	0	$ 0
Included in regulatory liabilities	0	0
Purchases	0	0
Issuances		3
Transfers in (out) of Level 3	0	0
Ending balance	18	3
Life Insurance Contracts [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance	19	19
Included in income	5	3
Included in accumulated other comprehensive loss	0	0
Included in regulatory liabilities	0	0
Purchases	0	0
Issuances	(3)	(3)
Settlements	(2)
Transfers in (out) of Level 3	0	0
Ending balance	19	19
Life Insurance Contracts [Member] | Potomac Electric Power Co [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance	18	18
Included in income	5	3
Included in accumulated other comprehensive loss	0	0
Purchases	0	0
Issuances	(3)	(3)
Settlements	(1)
Transfers in (out) of Level 3	0	0
Ending balance	19	18
Life Insurance Contracts [Member] | Delmarva Power & Light Co/De [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance	1	1
Included in accumulated other comprehensive loss	0	0
Included in regulatory liabilities	0	0
Purchases	0	0
Settlements	(1)
Transfers in (out) of Level 3	$ 0	0
Ending balance		$ 1

XML

Fair Value Disclosures - Gains on Level 3 Instruments Included in Income (Detail) - Other Income [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total gains included in income for the period	$ 20	$ 3
Change in unrealized gains relating to assets still held at reporting date	18	3
Potomac Electric Power Co [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total gains included in income for the period	5	3
Change in unrealized gains relating to assets still held at reporting date	$ 3	$ 3

XML

Fair Value Disclosures - Fair Value of Financial Liabilities Measured on Recurring Basis (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, Fair Value	$ 5,523	$ 5,583
Transition Bonds, Fair Value	185	235
Long-term project funding, Fair Value	5	28
Total Liabilities, Fair Value	5,713	5,846
Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, Fair Value	4,941	5,136
Transition Bonds, Fair Value	185	235
Total Liabilities, Fair Value	5,126	5,371
Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, Fair Value	582	447
Long-term project funding, Fair Value	5	28
Total Liabilities, Fair Value	587	475
Potomac Electric Power Co [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, Fair Value	2,673	2,624
Total Liabilities, Fair Value		2,636
Short-term project funding, Fair Value		12
Potomac Electric Power Co [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, Fair Value	2,673	2,624
Total Liabilities, Fair Value		2,624
Potomac Electric Power Co [Member] | Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total Liabilities, Fair Value		12
Short-term project funding, Fair Value		12
Delmarva Power & Light Co/De [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, Fair Value	1,183	1,123
Delmarva Power & Light Co/De [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, Fair Value	1,080	1,016
Delmarva Power & Light Co/De [Member] | Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, Fair Value	103	107
Atlantic City Electric Co [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, Fair Value	1,140	1,035
Transition Bonds, Fair Value	185	235
Total Liabilities, Fair Value	1,325	1,270
Atlantic City Electric Co [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, Fair Value	860	903
Transition Bonds, Fair Value	185	235
Total Liabilities, Fair Value	1,045	1,138
Atlantic City Electric Co [Member] | Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, Fair Value	280	132
Total Liabilities, Fair Value	$ 280	$ 132

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Fair Value Disclosures - Fair Value of Financial Liabilities Measured on Recurring Basis (Parenthetical) (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, carrying amount	$ 4,999	$ 4,807
Transition bonds, carrying amount	171	215
Potomac Electric Power Co [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, carrying amount	2,332	2,124
Delmarva Power & Light Co/De [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, carrying amount	1,170	1,071
Atlantic City Electric Co [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, carrying amount	1,038	903
Transition bonds, carrying amount	$ 171	$ 215

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Commitments and Contingencies - Retained Environmental Exposures - Additional Information (Detail)	1 Months Ended
	Jul. 31, 2010 USD ($) Facility	Dec. 31, 2015 USD ($)
Other Commitments [Line Items]
Loss contingency liabilities		$ 12,000,000
Conectiv Energy [Member]
Other Commitments [Line Items]
Third party maximum and seller floor for environmental remediation costs	$ 10,000,000
Number of facility locations | Facility	9
Environmental remediation expense minimum	$ 7,000,000
Environmental remediation expense maximum	18,000,000
PHI [Member]
Other Commitments [Line Items]
Third party maximum and seller floor for environmental remediation costs	$ 10,000,000
Potomac Electric Power Co [Member]
Other Commitments [Line Items]
Loss contingency liabilities		4,000,000
Delmarva Power & Light Co/De [Member]
Other Commitments [Line Items]
Loss contingency liabilities		3,000,000
Atlantic City Electric Co [Member]
Other Commitments [Line Items]
Loss contingency liabilities		$ 5,000,000

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Commitments and Contingencies - Schedule of Accrued Liabilities for Environmental Exposures (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2015
Other Commitments [Line Items]
Beginning balance	$ 28
Accruals	10
Payments	(5)
Ending balance	33
Less amounts in Other Current Liabilities		$ 4
Amounts in Other Deferred Credits		29
Total accrued liabilities for environmental contingencies	28	33
Legacy Generation Regulated [Member]
Other Commitments [Line Items]
Beginning balance	6
Accruals	3
Payments	(1)
Ending balance	8
Less amounts in Other Current Liabilities		1
Amounts in Other Deferred Credits		7
Total accrued liabilities for environmental contingencies	6	8
Legacy Generation Non-Regulated [Member]
Other Commitments [Line Items]
Beginning balance	5
Accruals	0
Ending balance	5
Amounts in Other Deferred Credits		5
Total accrued liabilities for environmental contingencies	5	5
Potomac Electric Power Co [Member]
Other Commitments [Line Items]
Beginning balance	19
Accruals	7
Payments	(2)
Ending balance	24
Less amounts in Other Current Liabilities		2
Amounts in Other Deferred Credits		22
Total accrued liabilities for environmental contingencies	19	24
Potomac Electric Power Co [Member] | Legacy Generation Regulated [Member]
Other Commitments [Line Items]
Beginning balance	3
Accruals	3
Ending balance	6
Amounts in Other Deferred Credits		6
Total accrued liabilities for environmental contingencies	3	6
Delmarva Power & Light Co/De [Member]
Other Commitments [Line Items]
Beginning balance	3
Accruals	3
Payments	(3)
Ending balance	3
Less amounts in Other Current Liabilities		2
Amounts in Other Deferred Credits		1
Total accrued liabilities for environmental contingencies	3	3
Delmarva Power & Light Co/De [Member] | Legacy Generation Regulated [Member]
Other Commitments [Line Items]
Beginning balance	2
Payments	(1)
Ending balance	1
Less amounts in Other Current Liabilities		1
Total accrued liabilities for environmental contingencies	2	1
Atlantic City Electric Co [Member] | Legacy Generation Regulated [Member]
Other Commitments [Line Items]
Beginning balance	1
Accruals	0
Payments	0
Ending balance	1
Amounts in Other Deferred Credits		1
Total accrued liabilities for environmental contingencies	1	1
Transmission and Distribution [Member]
Other Commitments [Line Items]
Beginning balance	17
Accruals	7
Payments	(4)
Ending balance	20
Less amounts in Other Current Liabilities		3
Amounts in Other Deferred Credits		17
Total accrued liabilities for environmental contingencies	17	20
Transmission and Distribution [Member] | Potomac Electric Power Co [Member]
Other Commitments [Line Items]
Beginning balance	16
Accruals	4
Payments	(2)
Ending balance	18
Less amounts in Other Current Liabilities		2
Amounts in Other Deferred Credits		16
Total accrued liabilities for environmental contingencies	16	18
Transmission and Distribution [Member] | Delmarva Power & Light Co/De [Member]
Other Commitments [Line Items]
Beginning balance	1
Accruals	3
Payments	(2)
Ending balance	2
Less amounts in Other Current Liabilities		1
Amounts in Other Deferred Credits		1
Total accrued liabilities for environmental contingencies	$ 1	$ 2

XML

Commitments and Contingencies - Environmental Matters - Additional Information (Detail)	1 Months Ended					3 Months Ended	12 Months Ended
	Aug. 31, 2015 gal	Mar. 31, 2014 USD ($)	Jul. 31, 2013 USD ($)	Jan. 31, 2011 USD ($) gal	Nov. 30, 2008 USD ($)	Mar. 31, 2013 USD ($)	Dec. 31, 2015 USD ($)
Other Commitments [Line Items]
Estimated costs remaining to remediate the site					$ 6,000,000
Quantity of mineral oil spill | gal				4,500
Cost of litigation		$ 875,000
Civil penalty payment		250,000
Donation for training fund		25,000
Fund provided for installation and operation of the trash collection SEP		600,000
Tax payment made				$ 74,000,000		$ 74,000,000
Income tax penalties				1,000,000		0
Interest expense assessed relating to disallowed deductions				$ 28,000,000
Non-cash charge (after-tax)						$ 377,000,000
Maximum tax penalty percentage						20.00%
Percentage of disallowed tax benefits associated with leases						100.00%
Federal income tax benefits						$ 192,000,000
Potential interest on potential tax liability related to disallowed tax benefits						50,000,000
Deposit of additional taxes and related interest						242,000,000
U.S. Environmental Protection Agency [Member]
Other Commitments [Line Items]
Costs to date to clean up site					6,000,000
Minimum [Member]
Other Commitments [Line Items]
Cost of implementation of a closure plan and cap							$ 9,000,000
Maximum [Member]
Other Commitments [Line Items]
Cost of implementation of a closure plan and cap							13,000,000
PHI [Member]
Other Commitments [Line Items]
Mineral oil released | gal	6,100
Released mineral oil recovered through remediation efforts, percentage	80.00%
PHI [Member] | Minimum [Member]
Other Commitments [Line Items]
Cost of implementation of a closure plan and cap							3,000,000
Proposed compensation for damages			$ 106,000
PHI [Member] | Maximum [Member]
Other Commitments [Line Items]
Cost of implementation of a closure plan and cap							6,000,000
Proposed compensation for damages			161,000
Potomac Electric Power Co [Member]
Other Commitments [Line Items]
Quantity of mineral oil spill | gal				4,500
Cost of litigation		875,000
Civil penalty payment		250,000
Donation for training fund		25,000
Fund provided for installation and operation of the trash collection SEP		$ 600,000
Mineral oil released | gal	6,100
Released mineral oil recovered through remediation efforts, percentage	80.00%
Non-cash charge (after-tax)						377,000,000
Potomac Electric Power Co [Member] | Minimum [Member]
Other Commitments [Line Items]
Cost of implementation of a closure plan and cap							3,000,000
Proposed compensation for damages			106,000
Potomac Electric Power Co [Member] | Minimum [Member] | Environmental Protection Agency [Member]
Other Commitments [Line Items]
Cost of implementation of a closure plan and cap							8,000,000
Potomac Electric Power Co [Member] | Maximum [Member]
Other Commitments [Line Items]
Cost of implementation of a closure plan and cap							6,000,000
Proposed compensation for damages			$ 161,000
Potomac Electric Power Co [Member] | Maximum [Member] | Environmental Protection Agency [Member]
Other Commitments [Line Items]
Cost of implementation of a closure plan and cap							$ 12,000,000
Atlantic City Electric Co [Member]
Other Commitments [Line Items]
Estimated costs remaining to remediate the site					6,000,000
Non-cash charge (after-tax)						$ 377,000,000
Atlantic City Electric Co [Member] | U.S. Environmental Protection Agency [Member]
Other Commitments [Line Items]
Costs to date to clean up site					$ 6,000,000

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Commitments and Contingencies - Schedule of Commitments and Obligations (Detail) $ in Millions	Dec. 31, 2015 USD ($)
Other Commitments [Line Items]
Guarantees associated with disposal of Conectiv Energy assets	$ 13
Guaranteed lease residual values	19
Total	32
PHI [Member]
Other Commitments [Line Items]
Guarantees associated with disposal of Conectiv Energy assets	13
Guaranteed lease residual values	3
Total	16
Potomac Electric Power Co [Member]
Other Commitments [Line Items]
Guaranteed lease residual values	5
Total	5
Delmarva Power & Light Co/De [Member]
Other Commitments [Line Items]
Guaranteed lease residual values	6
Total	6
Atlantic City Electric Co [Member]
Other Commitments [Line Items]
Guaranteed lease residual values	5
Total	$ 5

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Commitments and Contingencies - Schedule of Commitments and Obligations (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2015 USD ($)
Other Commitments [Line Items]
Derivative portfolio guarantee	$ 13,000,000
Obligations under guarantee	$ 52,000,000
Minimum [Member]
Other Commitments [Line Items]
Lease term range	1 year
Lease term range	3 years
Maximum [Member]
Other Commitments [Line Items]
Lease term range	4 years
Lease term range	8 years
PHI [Member]
Other Commitments [Line Items]
Obligations under guarantee	$ 9,000,000
Potomac Electric Power Co [Member]
Other Commitments [Line Items]
Obligations under guarantee	13,000,000
Delmarva Power & Light Co/De [Member]
Other Commitments [Line Items]
Obligations under guarantee	16,000,000
Atlantic City Electric Co [Member]
Other Commitments [Line Items]
Obligations under guarantee	14,000,000
Leased Equipment and Fleet Vehicles [Member]
Other Commitments [Line Items]
Fair value of leased equipment and vehicles	$ 0

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Commitments and Contingencies - Tax Legislation, Guarantees, Indemnifications, and Performance Contracts - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Other Commitments [Line Items]
Contractual obligations due in 2016	$ 268
Contractual obligations due in 2017 to 2018	469
Contractual obligations due in 2019 to 2020	472
Contractual obligations due, thereafter	993
Rental expense for operating leases	60	$ 59	$ 54
Future minimum operating lease payments, 2016	52
Future minimum operating lease payments, 2017	48
Future minimum operating lease payments, 2018	47
Future minimum operating lease payments, 2019	34
Future minimum operating lease payments, 2020	37
Future minimum operating lease payments, thereafter	$ 304
Pepco Energy Services [Member] | Energy Savings or Combined Heat and Power Performance [Member]
Other Commitments [Line Items]
Contract life, maximum remaining term	20 years
Value of guarantees under construction projects	$ 15
Accrued liability on contracts	1
Pepco Energy Services [Member] | Completed Performance Contracts Associated With Savings Guarantees [Member]
Other Commitments [Line Items]
Value of guarantees completed projects	$ 221
Contract life, maximum remaining term	23 years
Pepco Energy Services [Member] | Uncompleted Performance Contracts Associated With Savings Guarantees [Member]
Other Commitments [Line Items]
Value of guarantees on projects under construction	$ 55
Maximum term of project under construction	19 years
Potomac Electric Power Co [Member]
Other Commitments [Line Items]
Rental expense for operating leases	$ 7	8	7
Future minimum operating lease payments, 2016	7
Future minimum operating lease payments, 2017	6
Future minimum operating lease payments, 2018	5
Future minimum operating lease payments, 2019	4
Future minimum operating lease payments, 2020	3
Future minimum operating lease payments, thereafter	7
Delmarva Power & Light Co/De [Member]
Other Commitments [Line Items]
Contractual obligations due in 2016	64
Contractual obligations due in 2017 to 2018	127
Contractual obligations due in 2019 to 2020	128
Contractual obligations due, thereafter	296
Rental expense for operating leases	14	14	13
Future minimum operating lease payments, 2016	13
Future minimum operating lease payments, 2017	12
Future minimum operating lease payments, 2018	16
Future minimum operating lease payments, 2019	6
Future minimum operating lease payments, 2020	9
Future minimum operating lease payments, thereafter	$ 118
Ownership interest	11.90%
Present value of future minimum lease payments	$ 75
Atlantic City Electric Co [Member]
Other Commitments [Line Items]
Contractual obligations due in 2016	203
Contractual obligations due in 2017 to 2018	341
Contractual obligations due in 2019 to 2020	344
Contractual obligations due, thereafter	697
Rental expense for operating leases	13	$ 12	$ 12
Future minimum operating lease payments, 2016	8
Future minimum operating lease payments, 2017	8
Future minimum operating lease payments, 2018	7
Future minimum operating lease payments, 2019	6
Future minimum operating lease payments, 2020	6
Future minimum operating lease payments, thereafter	$ 30

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Variable Interest Entities - Additional Information (Detail) $ in Millions		12 Months Ended
	Oct. 18, 2011 MW	Dec. 31, 2015 USD ($) MWh Agreement MW	Dec. 31, 2014 USD ($) MWh MW	Dec. 31, 2013 USD ($)
Delmarva Power & Light Co/De [Member]
Variable Interest Entity [Line Items]
Power produced by fuel cell facility	30
Power produced by fuel cell facility | MWh		227,113	222,948
Delmarva Power & Light Co/De [Member] | Fuel Cell Facility [Member]
Variable Interest Entity [Line Items]
Term of agreement		Through 2033
Amount billed to distribution customers, respect to energy produced by these facilities | $		$ 37	$ 36	$ 23
Delmarva Power & Light Co/De [Member] | Wind PPA [Member]
Variable Interest Entity [Line Items]
Purchased energy | $		$ 29	$ 31	30
Delmarva Power & Light Co/De [Member] | Wind PPA [Member] | Wind Facility One [Member]
Variable Interest Entity [Line Items]
Energy purchase maximum to be purchased		50
Delmarva Power & Light Co/De [Member] | Wind PPA [Member] | Wind Facility Two [Member]
Variable Interest Entity [Line Items]
Energy purchase maximum to be purchased		40
Delmarva Power & Light Co/De [Member] | Wind PPA [Member] | Wind Facility Three [Member]
Variable Interest Entity [Line Items]
Energy purchase maximum to be purchased		38
Delmarva Power & Light Co/De [Member] | Solar PPA [Member]
Variable Interest Entity [Line Items]
Megawatts received from power purchase agreements (PPAs)		10
Number of purchase power agreements | Agreement		1
Energy purchase maximum to be purchased		28	19
Term of agreement		Through 2030
Term of agreement, years		20 years
Obligated purchase amount of energy produced at the facility		70.00%
Solar energy purchases | $		$ 6	$ 6	3
Delmarva Power & Light Co/De [Member] | Land-Based Wind PPA [Member]
Variable Interest Entity [Line Items]
Megawatts received from power purchase agreements (PPAs)		128
Number of purchase power agreements | Agreement		3
Delmarva Power & Light Co/De [Member] | 2015 PPA [Member] | Maximum [Member]
Variable Interest Entity [Line Items]
Expected time frame for facilities to be operational		1 year
Atlantic City Electric Co [Member]
Variable Interest Entity [Line Items]
Purchase activities with non utility generators per power purchase agreements | $		$ 198	208	206
Equity ownership percentage		100.00%
Atlantic City Electric Co [Member] | Non-Utility Generators [Member]
Variable Interest Entity [Line Items]
Megawatts received from power purchase agreements (PPAs)		459
Number of purchase power agreements | Agreement		3
Purchased energy | $		$ 208	$ 233	$ 221

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Accumulated Other Comprehensive Loss - Schedule of Components of Other Comprehensive Loss (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance at beginning of period	$ (46)	$ (34)	$ (48)
Amount of amortization of net prior service cost and actuarial loss reclassified to Other operation and maintenance expense	15	(20)	13
Amount of net pre-tax loss reclassified to Income (loss) from discontinued operations before income tax	1	1	1
Balance at end of period	(36)	(46)	(34)
Pension and Other Postretirement Benefits [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance at beginning of period	(37)	(25)	(32)
Amount of amortization of net prior service cost and actuarial loss reclassified to Other operation and maintenance expense	6	5	5
Amount of net prior service cost and actuarial gain (loss) arising during the year	9	(25)	8
Income tax (benefit) expense	6	(8)	6
Balance at end of period	(28)	(37)	(25)
Treasury Lock [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance at beginning of period	(9)	(9)	(10)
Amount of pre-tax loss reclassified to Interest expense	1	1	1
Income tax (benefit) expense		1
Balance at end of period	$ (8)	$ (9)	(9)
Commodity Derivatives [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance at beginning of period			(6)
Amount of net pre-tax loss reclassified to Income (loss) from discontinued operations before income tax			10
Income tax (benefit) expense			$ 4

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Quarterly Financial Information - Schedule of Quarterly Financial Information (Detail) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Financial Information [Line Items]
Total Operating Revenue	$ 1,150	$ 1,362	$ 1,140	$ 1,371	$ 1,118	$ 1,313	$ 1,117	$ 1,330	$ 5,023	$ 4,878	$ 4,666
Total operating expenses	941	1,179	1,001	1,229	1,004	1,147	966	1,157	4,350	4,274	3,998
Operating Income (Loss)	209	183	139	142	114	166	151	173	673	604	668
Other Expenses	(65)	(43)	(59)	(59)	(66)	(53)	(53)	(52)	(226)	(224)	(239)
Income Before Income Tax Expense	144	140	80	83	48	113	98	121	447	380	429
Income Tax Expense	23	49	27	30	13	34	45	46	129	138	319
Net Income from Continuing Operations	121	91	53	53					318	242	110
Income from Discontinued Operations, net of taxes	9								9		(322)
Net Income	$ 130	$ 91	$ 53	$ 53	$ 35	$ 79	$ 53	$ 75	$ 327	$ 242	$ (212)
Earnings Per Share of Common Stock from Continuing Operations	$ 0.48	$ 0.36	$ 0.21	$ 0.21					$ 1.25
Earnings Per Share of Common Stock from Discontinued Operations	0.03								0.04
Basic and Diluted Earnings Per Share of	0.51	0.36	0.21	0.21	$ 0.14	$ 0.31	$ 0.21	$ 0.30	1.29	$ 0.96
Cash Dividends Per Share of Common Stock	$ 0.27	$ 0.27	$ 0.27	$ 0.27	$ 0.27	$ 0.27	$ 0.27	$ 0.27	$ 1.08	$ 1.08	$ 1.08
Atlantic City Electric Co [Member]
Quarterly Financial Information [Line Items]
Total operating expenses	$ 252	$ 349	$ 254	$ 313	$ 246	$ 295	$ 228	$ 309	$ 1,168	$ 1,078	$ 1,066
Operating Income (Loss)	40	38	32	20	27	52	25	31	130	135	136
Other Expenses	(15)	(17)	(15)	(14)	(17)	(15)	(15)	(15)	(61)	(62)	(67)
Income Before Income Tax Expense	25	21	17	6	10	37	10	16	69	73	69
Income Tax Expense	15	7	7	2	4	14	4	6	31	28	19
Net Income	10	14	10	4	6	23	6	10	38	45	50
Total Operating Revenue	292	387	286	333	273	347	253	340	1,298	1,213	1,202
Potomac Electric Power Co [Member]
Quarterly Financial Information [Line Items]
Total operating expenses	379	497	435	493	408	462	414	469	1,804	1,753	1,705
Operating Income (Loss)	124	115	83	63	63	125	94	66	385	348	321
Other Expenses	(29)	(23)	(23)	(25)	(27)	(20)	(20)	(18)	(100)	(85)	(92)
Income Before Income Tax Expense	95	92	60	38	36	105	74	48	285	263	229
Income Tax Expense	36	32	18	12	10	38	28	16	98	92	79
Net Income	59	60	42	26	26	67	46	32	187	171	150
Total Operating Revenue	503	612	518	556	471	587	508	535	2,189	2,101	2,026
Delmarva Power & Light Co/De [Member]
Quarterly Financial Information [Line Items]
Total operating expenses	256	285	251	361	257	264	239	326	1,153	1,086	1,059
Operating Income (Loss)	47	32	24	62	51	45	40	71	165	207	185
Other Expenses	(12)	(8)	(11)	(9)	(12)	(9)	(8)	(9)	(40)	(38)	(40)
Income Before Income Tax Expense	35	24	13	53	39	36	32	62	125	169	145
Income Tax Expense	14	9	5	21	14	13	13	25	49	65	56
Net Income	21	15	8	32	25	23	19	37	76	104	89
Total Operating Revenue	$ 303	$ 317	$ 275	$ 423	$ 308	$ 309	$ 279	$ 397	$ 1,318	$ 1,293	$ 1,244

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Quarterly Financial Information - Schedule of Quarterly Financial Information (Parenthetical) (Detail) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Financial Information [Line Items]
Increase in fair value of preferred stock derivative		$ 15							$ 15
Increase in fair value of preferred stock derivative, after-tax		10
Pretax gains on sales of land	$ 46								46
Aftertax gains on sales of land	27
Income tax benefit	23	49	$ 27	$ 30	$ 13	$ 34	$ 45	$ 46	129	$ 138	$ 319
Charge to correct prior period error after-tax	7
Tax Settlement [Member]
Quarterly Financial Information [Line Items]
Income tax benefit	(47)
Income tax benefit discontinued operations	(9)
Pepco Energy Services [Member]
Quarterly Financial Information [Line Items]
Impairment losses, pre-tax					28	53
Impairment losses, after-tax					16	32
Atlantic City Electric Co [Member]
Quarterly Financial Information [Line Items]
Income tax benefit	15	7	7	2	4	14	4	6	31	28	19
Charge to correct prior period error after-tax	2				2
Reversed unbilled revenue, pre-tax					3
Reversed unbilled revenue, after-tax					2
Charge to correct prior period error before tax					3
Atlantic City Electric Co [Member] | Tax Settlement [Member]
Quarterly Financial Information [Line Items]
Income tax benefit	3
Potomac Electric Power Co [Member]
Quarterly Financial Information [Line Items]
Pretax gains on sales of land	46								46
Aftertax gains on sales of land	27
Income tax benefit	36	32	18	12	10	38	28	16	98	92	79
Charge to correct prior period error after-tax	6
Interest expense on uncertain tax positions	3
Potomac Electric Power Co [Member] | Tax Settlement [Member]
Quarterly Financial Information [Line Items]
Income tax benefit	(9)
Delmarva Power & Light Co/De [Member]
Quarterly Financial Information [Line Items]
Income tax benefit	14	$ 9	$ 5	$ 21	$ 14	$ 13	$ 13	$ 25	49	$ 65	$ 56
Delmarva Power & Light Co/De [Member] | Tax Settlement [Member]
Quarterly Financial Information [Line Items]
Income tax benefit	$ 3								$ 3

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Discontinued Operations - Income (Loss) from Discontinued Operations, Net of Income Taxes (Detail) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2015	Dec. 31, 2013
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Income (Loss) from Discontinued Operations, net of Income Taxes	$ 9	$ 9	$ (322)
Cross-Border Energy Lease Investments [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Income (Loss) from Discontinued Operations, net of Income Taxes		$ 9	(327)
Pepco Energy Services' Retail Electric and Natural Gas Supply Businesses [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Income (Loss) from Discontinued Operations, net of Income Taxes			$ 5

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Discontinued Operations - Additional Information (Detail) - USD ($)	1 Months Ended	3 Months Ended			9 Months Ended	12 Months Ended
	Jan. 31, 2011	Dec. 31, 2015	Jun. 30, 2013	Mar. 31, 2013	Sep. 30, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
After-tax non-cash charges				$ 377,000,000
After-tax effect of revised lease rerun				313,000,000
Penalties on tax settlement	$ 1,000,000			0
Pre-tax loss reclassified into Income from Discontinued operations, Before Taxes						$ (1,000,000)	$ (1,000,000)	$ (1,000,000)
Cross-Border Energy Lease Investments [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Income tax benefit, income from operations of discontinued operations		$ (9,000,000)				9,000,000		44,000,000
Non-cash pre-tax charge								373,000,000
Corporate and Other [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Interest expense on uncertain tax positions								66,000,000
Pepco Energy Services [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Derivatives		0				0	$ 0	$ 0
Discontinued Operations [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
After-tax non-cash charges			$ 6,000,000	323,000,000
Non-cash pre-tax charge				373,000,000
After-tax effect of revised lease rerun				313,000,000
After-tax non-cash charge				16,000,000
Penalties associated with re-assessment of tax positions		$ 0				0
Penalties on tax settlement						$ 0
Amount of net pre-tax loss arising during the period included in Accumulated Other Comprehensive Loss									$ (10,000,000)
Amount of net tax loss arising during the period included in Accumulated Other Comprehensive Loss									$ (6,000,000)
Pre-tax loss reclassified into Income from Discontinued operations, Before Taxes			$ (6,000,000)	(4,000,000)
Net of tax loss reclassified into Income from Discontinued operations, Net of Income Taxes				(2,000,000)
Discontinued Operations [Member] | PHI [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net pre-tax gain / loss					$ (3,000,000)
Loss on early termination of finance leases held in trust, after-tax					(2,000,000)
After-tax non-cash charge				70,000,000
Discontinued Operations [Member] | PHI [Member] | Proceeds From Early Termination [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Aggregate of net cash proceeds (payments) of lease investments					873,000,000
Discontinued Operations [Member] | PHI [Member] | Payment Paid From Early Termination [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Aggregate of net cash proceeds (payments) of lease investments					$ 2,000,000,000
Discontinued Operations [Member] | Power Delivery [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Interest benefit on uncertain tax positions				12,000,000
Discontinued Operations [Member] | Other Non-Regulated [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Interest expense on uncertain tax positions				16,000,000
Discontinued Operations [Member] | Corporate and Other [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Interest expense on uncertain tax positions				$ 66,000,000

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Discontinued Operations - Operating Results for Cross-Border Energy Lease Investments (Detail) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2015	Dec. 31, 2013
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Income (loss) from discontinued operations, net of income taxes	$ 9	$ 9	$ (322)
Cross-Border Energy Lease Investments [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Operating revenue from PHI's cross-border energy lease investments			7
Non-cash charge to reduce carrying value of PHI's cross-border energy lease investments			(373)
Total operating revenue			(366)
Income (loss) from operations of discontinued operations, net of income taxes		9	(325)
Net losses associated with the early termination of the cross-border energy lease investments, net of income taxes			(2)
Income (loss) from discontinued operations, net of income taxes		$ 9	$ (327)

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Discontinued Operations - Operating Results for Cross-Border Energy Lease Investments (Parenthetical) (Detail) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2015	Dec. 31, 2013
Cross-Border Energy Lease Investments [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Income tax benefit, income from operations of discontinued operations	$ (9)	$ 9	$ 44

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Discontinued Operations - Operating Results for Retail Electric and Natural Gas Supply Businesses (Detail) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2015	Dec. 31, 2013
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Income from discontinued operations, net of income taxes	$ 9	$ 9	$ (322)
Discontinued Operations [Member] | Pepco Energy Services [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Operating revenue			84
Income from operations of discontinued operations, net of income taxes			4
Net gains associated with accelerated disposition of retail electric and natural gas contracts, net of income taxes			1
Income from discontinued operations, net of income taxes			$ 5

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Discontinued Operations - Operating Results for Retail Electric and Natural Gas Supply Businesses (Parenthetical) (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2013 USD ($)
Pepco Energy Services [Member] | Discontinued Operations [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Income tax expense (benefit) from discontinued operations	$ 3

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Discontinued Operations - Derivative Gain (Loss) for Retail Electric and Natural Gas Supply Businesses (Detail) - Discontinued Operations [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative Instruments, Gain (Loss) [Line Items]
Reclassification of mark-to-market to realized on settlement of contracts			$ 10
Unrealized mark-to-market loss	$ 0	$ 0	0
Total net gain			$ 10

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Segment Information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2015 Segment
Potomac Electric Power Co [Member]
Segment Reporting Information [Line Items]
Number of operating segments	1
Delmarva Power & Light Co/De [Member]
Segment Reporting Information [Line Items]
Number of operating segments	1
Atlantic City Electric Co [Member]
Segment Reporting Information [Line Items]
Number of operating segments	1

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Related Party Transactions - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Potomac Electric Power Co [Member] | PHI Service Company [Member]
Related Party Transaction [Line Items]
Costs directly charged or allocated	$ 240	$ 220	$ 209
Potomac Electric Power Co [Member] | Pepco Energy Services [Member]
Related Party Transaction [Line Items]
Maintenance services	26	30	20
Delmarva Power & Light Co/De [Member] | PHI Service Company [Member]
Related Party Transaction [Line Items]
Costs directly charged or allocated	179	163	154
Delmarva Power & Light Co/De [Member] | Pepco Energy Services [Member]
Related Party Transaction [Line Items]
Maintenance services	3	0	0
Atlantic City Electric Co [Member] | PHI Service Company [Member]
Related Party Transaction [Line Items]
Costs directly charged or allocated	$ 143	$ 124	$ 115

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Related Party Transactions - Schedule of Related Party Transactions Included in Balance Sheet (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Potomac Electric Power Co [Member]
Related Party Transaction [Line Items]
Payable to Related Party, Total	$ (30)	$ (30)
Potomac Electric Power Co [Member] | PHI Service Company [Member]
Related Party Transaction [Line Items]
Payable to Related Party, Total	(25)	(27)
Potomac Electric Power Co [Member] | Pepco Energy Services [Member]
Related Party Transaction [Line Items]
Payable to Related Party, Total	(4)	(2)
Potomac Electric Power Co [Member] | Other [Member]
Related Party Transaction [Line Items]
Payable to Related Party, Total	(1)	(1)
Delmarva Power & Light Co/De [Member]
Related Party Transaction [Line Items]
Payable to Related Party, Total	(20)	(17)
Delmarva Power & Light Co/De [Member] | PHI Service Company [Member]
Related Party Transaction [Line Items]
Payable to Related Party, Total	(19)	(18)
Delmarva Power & Light Co/De [Member] | Other [Member]
Related Party Transaction [Line Items]
Payable to Related Party, Total	(1)	1
Atlantic City Electric Co [Member]
Related Party Transaction [Line Items]
Payable to Related Party, Total	(16)	(15)
Atlantic City Electric Co [Member] | PHI Service Company [Member]
Related Party Transaction [Line Items]
Payable to Related Party, Total	(15)	(14)
Atlantic City Electric Co [Member] | Other [Member]
Related Party Transaction [Line Items]
Payable to Related Party, Total	$ (1)	$ (1)

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Related Party Transactions - Schedule of Related Party Transactions Included in Income Statement (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Delmarva Power & Light Co/De [Member] | PHI Service Company [Member]
Related Party Transaction [Line Items]
Intercompany lease transactions	$ 4	$ 5	$ 4
Atlantic City Electric Co [Member] | Millennium Account Services LLC (ACE Affiliate) [Member]
Related Party Transaction [Line Items]
Meter reading services provided by Millennium Account Services LLC (an ACE affiliate)	(4)	(4)	(4)
Atlantic City Electric Co [Member] | PHI Service Company [Member]
Related Party Transaction [Line Items]
Intercompany lease transactions	(1)	(1)	(1)
Intercompany use revenue	$ 1	$ 2	$ 3

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Schedule I - Condensed Financial Information of Parent Company (Statements of Income (Loss)) (Detail) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Condensed Income Statements, Captions [Line Items]
Operating Revenue	$ 1,150	$ 1,362	$ 1,140	$ 1,371	$ 1,118	$ 1,313	$ 1,117	$ 1,330	$ 5,023	$ 4,878	$ 4,666
Operating Expenses
Other operation and maintenance									1,016	924	851
Total operating expenses	941	1,179	1,001	1,229	1,004	1,147	966	1,157	4,350	4,274	3,998
Operating Income (Loss)	209	183	139	142	114	166	151	173	673	604	668
Other Income (Expenses)
Interest expense									(280)	(268)	(273)
Income from equity investments											2
Other income									54	44	32
Total Other Income (Expenses)	(65)	(43)	(59)	(59)	(66)	(53)	(53)	(52)	(226)	(224)	(239)
Income from Continuing Operations Before Income Tax	144	140	80	83	48	113	98	121	447	380	429
Income Tax Expense Related to Continuing Operations	23	49	27	30	13	34	45	46	129	138	319
Net Income from Continuing Operations	121	91	53	53					318	242	110
Income (Loss) from Discontinued Operations, net of Income Taxes	9								9		(322)
Net Income (Loss)	$ 130	$ 91	$ 53	$ 53	$ 35	$ 79	$ 53	$ 75	327	242	(212)
Comprehensive Income (Loss)									$ 337	$ 230	$ (198)
Earnings Per Share
Basic earnings per share of common stock from continuing operations									$ 1.25	$ 0.96	$ 0.45
Basic earnings (loss) per share of common stock from discontinued operations									0.04		(1.31)
Basic earnings (loss) per share of common stock									1.29	0.96	(0.86)
Diluted earnings per share of common stock from continuing operations									1.25	0.96	0.45
Diluted earnings (loss) per share of common stock from discontinued operations									0.04		(1.31)
Diluted earnings (loss) per share of common stock									$ 1.29	$ 0.96	$ (0.86)
Parent Company [Member]
Condensed Income Statements, Captions [Line Items]
Operating Revenue									$ 0	$ 0	$ 0
Operating Expenses
Other operation and maintenance									20	31	1
Total operating expenses									20	31	1
Operating Income (Loss)									(20)	(31)	(1)
Other Income (Expenses)
Interest expense									(47)	(43)	(42)
Income from equity investments									312	291	204
Other income									15
Total Other Income (Expenses)									280	248	162
Income from Continuing Operations Before Income Tax									260	217	161
Income Tax Expense Related to Continuing Operations									(58)	(25)	51
Net Income from Continuing Operations									318	242	110
Income (Loss) from Discontinued Operations, net of Income Taxes									9		(322)
Net Income (Loss)									327	242	(212)
Comprehensive Income (Loss)									$ 337	$ 230	$ (198)
Earnings Per Share
Basic earnings per share of common stock from continuing operations									$ 1.25	$ 0.96	$ 0.45
Basic earnings (loss) per share of common stock from discontinued operations									0.04		(1.31)
Basic earnings (loss) per share of common stock									1.29	0.96	(0.86)
Diluted earnings per share of common stock from continuing operations									1.25	0.96	0.45
Diluted earnings (loss) per share of common stock from discontinued operations									0.04		(1.31)
Diluted earnings (loss) per share of common stock									$ 1.29	$ 0.96	$ (0.86)

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Schedule I - Condensed Financial Information of Parent Company (Balance Sheets) (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
CURRENT ASSETS
Cash and cash equivalents	$ 25	$ 14	$ 23	$ 25
Total Current Assets	1,202	1,034
INVESTMENTS AND OTHER ASSETS
Goodwill	1,406	1,407
Other	129	121
TOTAL ASSETS	16,326	15,589	14,778
CURRENT LIABILITIES
Short-term debt	1,063	729
Current portion of long-term debt	294	366
Total Current Liabilities	2,308	2,056
DEFERRED CREDITS
Long-term debt	$ 4,656	$ 4,397
COMMITMENTS AND CONTINGENCIES (NOTE 4)
PREFERRED STOCK
Series A preferred stock, $.01 par value, 18,000 shares authorized, 18,000 and 12,600 shares outstanding, respectively	$ 183	$ 129
EQUITY
Common stock, $.01 par value - 400,000,000 shares authorized, 254,289,261 and 252,728,684 shares outstanding, respectively	3	3
Premium on stock and other capital contributions	3,829	3,800
Accumulated other comprehensive loss	(36)	(46)	$ (34)	(48)
Retained earnings	617	565
TOTAL LIABILITIES AND EQUITY	16,326	15,589
Parent Company [Member]
CURRENT ASSETS
Cash and cash equivalents		65		$ 262
Prepayments of income taxes	171	152
Accounts receivable and other	18	9
Total Current Assets	189	226
INVESTMENTS AND OTHER ASSETS
Goodwill	1,398	1,398
Investment in consolidated companies	4,636	4,256
Other	127	82
Total Investments and Other Assets	6,161	5,736
TOTAL ASSETS	6,350	5,962
CURRENT LIABILITIES
Short-term debt	784	287
Current portion of long-term debt	190	250
Interest and taxes accrued	10	9
Accounts payable due to associated companies	8	13
Total Current Liabilities	992	559
DEFERRED CREDITS
Notes payable due to subsidiary companies	498	494
Liabilities and accrued interest related to uncertain tax positions		4
Total Deferred Credits	498	498
Long-term debt	$ 264	$ 454
COMMITMENTS AND CONTINGENCIES (NOTE 4)
PREFERRED STOCK
Series A preferred stock, $.01 par value, 18,000 shares authorized, 18,000 and 12,600 shares outstanding, respectively	$ 183	$ 129
EQUITY
Common stock, $.01 par value - 400,000,000 shares authorized, 254,289,261 and 252,728,684 shares outstanding, respectively	3	3
Premium on stock and other capital contributions	3,829	3,800
Accumulated other comprehensive loss	(36)	(46)
Retained earnings	617	565
Total Equity	4,413	4,322
TOTAL LIABILITIES AND EQUITY	$ 6,350	$ 5,962

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Schedule I - Condensed Financial Information of Parent Company (Balance Sheets) (Parenthetical) (Detail) - $ / shares	Dec. 31, 2015	Dec. 31, 2014	Apr. 29, 2014
Condensed Balance Sheet Statements, Captions [Line Items]
Series A preferred stock, par value	$ 0.01	$ 0.01
Series A preferred stock, shares authorized	18,000	18,000
Series A preferred stock, shares outstanding	18,000	12,600
Common stock, par value	$ 0.01	$ 0.01	$ 0.01
Common stock, shares authorized	400,000,000	400,000,000
Common stock, shares outstanding	254,289,261	252,728,684
Parent Company [Member]
Condensed Balance Sheet Statements, Captions [Line Items]
Series A preferred stock, par value	$ 0.01	$ 0.01
Series A preferred stock, shares authorized	18,000	18,000
Series A preferred stock, shares outstanding	18,000	12,600
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	400,000,000	400,000,000
Common stock, shares outstanding	254,289,261	252,728,684

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Schedule I - Condensed Financial Information of Parent Company (Statements of Cash Flows) (Detail) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
OPERATING ACTIVITIES
Net Income (Loss)	$ 130	$ 91	$ 53	$ 53	$ 35	$ 79	$ 53	$ 75	$ 327	$ 242	$ (212)
(Income) loss from discontinued operations, net of income taxes	(9)								(9)		322
Adjustments to reconcile net income to net cash from operating activities:
Deferred income taxes									122	302	458
Increase in fair value of preferred stock derivative		$ (15)							(15)
Other									(2)	(6)	(13)
Changes in:
Other assets and liabilities									8	10	9
Net Cash From (Used By) Operating Activities									939	854	497
FINANCING ACTIVITIES
Dividends paid on common stock									(275)	(272)	(270)
Common stock issued for the Direct Stock Purchase and Dividend Reinvestment Plan and employee-related compensation									18	34	50
Issuances of common stock											324
Issuances of Series A preferred stock									54	126
Reacquisitions of long-term debt									(420)	(334)	(558)
Issuances (repayments) of short-term debt, net									34	164	(200)
Borrowings under term loans									300		250
Repayments of term loans										(100)	(450)
Costs of issuances									(7)	(10)	(23)
Net Cash From (Used By) Financing Activities									233	363	(88)
Net Increase (Decrease) In Cash and Cash Equivalents									11	(9)	(2)
Cash and Cash Equivalents at Beginning of Year				14				$ 23	14	23	25
CASH AND CASH EQUIVALENTS AT END OF YEAR	$ 25				14				25	14	23
Parent Company [Member]
OPERATING ACTIVITIES
Net Income (Loss)									327	242	(212)
(Income) loss from discontinued operations, net of income taxes									(9)		322
Adjustments to reconcile net income to net cash from operating activities:
Distributions from related parties less than earnings									(74)	(149)	(127)
Deferred income taxes									(33)	(5)	(7)
Increase in fair value of preferred stock derivative									(15)
Other									13	18
Changes in:
Prepaid and other									6	13	2
Accounts payable									(1)	1	6
Interest and taxes									(23)		(141)
Other assets and liabilities									(22)	1	3
Net Cash From (Used By) Operating Activities									169	121	(154)
FINANCING ACTIVITIES
Dividends paid on common stock									(275)	(272)	(270)
Common stock issued for the Direct Stock Purchase and Dividend Reinvestment Plan and employee-related compensation									18	34	50
Issuances of common stock											324
Issuances of Series A preferred stock									54	126
Capital contributions to subsidiaries, net									(282)	(210)	(250)
Increase in notes payable due to associated companies									4	3	491
Reacquisitions of long-term debt									(250)
Issuances (repayments) of short-term debt, net									197	263	(240)
Borrowings under term loans									300		250
Repayments of term loans											(450)
Costs of issuances											(13)
Net Cash From (Used By) Financing Activities									(234)	(56)	(108)
Net Increase (Decrease) In Cash and Cash Equivalents									(65)	65	(262)
Cash and Cash Equivalents at Beginning of Year				$ 65					$ 65		$ 262
CASH AND CASH EQUIVALENTS AT END OF YEAR					$ 65					$ 65

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Schedule I - Condensed Financial Information of Parent Company - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Condensed Financial Statements, Captions [Line Items]
Ownership percentage of significant subsidiaries	100.00%
Ratio of equity to total capitalization	30.00%
Retained earnings	$ 617	$ 565
Restricted net assets for consolidated subsidiaries	2,633
Surety Bond [Member]
Condensed Financial Statements, Captions [Line Items]
Guarantee obligations amount	56
Pepco Energy Services [Member] | Performance Guarantee [Member]
Condensed Financial Statements, Captions [Line Items]
Guarantee obligations amount	269
Pepco Energy Services [Member] | Surety Bond [Member]
Condensed Financial Statements, Captions [Line Items]
Guarantee obligations amount	177
Potomac Capital Investment Corporation (PCI) [Member]
Condensed Financial Statements, Captions [Line Items]
Guarantee obligations amount	$ 725

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Schedule I - Condensed Financial Information of Parent Company - Presentation of Debt Issuance Costs (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Debt Issuance Costs [Line Items]
Other (within investments and other assets)	$ 129	$ 121
Long-term debt	4,656	4,397
Parent Company [Member]
Debt Issuance Costs [Line Items]
Other (within investments and other assets)	127	82
Long-term debt	$ 264	454
As Filed [Member]
Debt Issuance Costs [Line Items]
Other (within investments and other assets)		166
Long-term debt		4,441
As Filed [Member] | Parent Company [Member]
Debt Issuance Costs [Line Items]
Other (within investments and other assets)		84
Long-term debt		456
Scenario, Adjustment [Member]
Debt Issuance Costs [Line Items]
Other (within investments and other assets)		(45)
Long-term debt		(44)
Scenario, Adjustment [Member] | Parent Company [Member]
Debt Issuance Costs [Line Items]
Other (within investments and other assets)		(2)
Long-term debt		$ (2)

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Schedule I - Condensed Financial Information of Parent Company - Investment in Consolidated Companies (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Schedule of Equity Method Investments [Line Items]
Total investment in consolidated companies	$ 4,636	$ 4,256
Conectiv, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Total investment in consolidated companies	2,198	1,984
Potomac Electric Power Co [Member]
Schedule of Equity Method Investments [Line Items]
Total investment in consolidated companies	2,240	2,087
Potomac Capital Investment Corporation (PCI) [Member]
Schedule of Equity Method Investments [Line Items]
Total investment in consolidated companies	40	30
Pepco Energy Services [Member]
Schedule of Equity Method Investments [Line Items]
Total investment in consolidated companies	155	153
PHI Service Company [Member]
Schedule of Equity Method Investments [Line Items]
Total investment in consolidated companies	$ 3	$ 2

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Schedule I - Condensed Financial Information of Parent Company - Related Party Transactions (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Related Party Transaction [Line Items]
(Payable to) Receivable from Related Party, Total	$ (8)	$ (13)
Money Pool Balance (included in cash and cash equivalents)		65
Conectiv Communications, Inc. [Member]
Related Party Transaction [Line Items]
(Payable to) Receivable from Related Party, Total	(4)	(4)
PHI Service Company [Member]
Related Party Transaction [Line Items]
(Payable to) Receivable from Related Party, Total	(4)	(10)
Other [Member]
Related Party Transaction [Line Items]
(Payable to) Receivable from Related Party, Total		1
Potomac Capital Investment Corporation (PCI) [Member]
Related Party Transaction [Line Items]
Payable to Related Party (non-current)	$ (498)	$ (494)

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Schedule II - Valuation and Qualifying Accounts (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Valuation and Qualifying Accounts Disclosure [Line Items]
Balance at Beginning of Period	$ 40	$ 38	$ 34
Charged to Costs and Expenses	59	46	37
Charged to Other Accounts	5	9	5
Deductions	(48)	(53)	(38)
Balance at End of Period	56	40	38
Potomac Electric Power Co [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Balance at Beginning of Period	16	16	13
Charged to Costs and Expenses	20	17	15
Charged to Other Accounts	1	2	1
Deductions	(20)	(19)	(13)
Balance at End of Period	17	16	16
Delmarva Power & Light Co/De [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Balance at Beginning of Period	11	12	9
Charged to Costs and Expenses	20	13	11
Charged to Other Accounts	2	4	1
Deductions	(16)	(18)	(9)
Balance at End of Period	17	11	12
Atlantic City Electric Co [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Balance at Beginning of Period	9	10	11
Charged to Costs and Expenses	18	12	11
Charged to Other Accounts	2	3	3
Deductions	(12)	(16)	(15)
Balance at End of Period	$ 17	$ 9	$ 10