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, 2011

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).  x

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, 2011	Number of Shares of Common Stock of the Registrant Outstanding at February 15, 2012
Pepco Holdings	$4,432,800,000 (a)	227,609,131 ($.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, 2011, its executive officers, directors and beneficial owners of more than 10% of its common stock, and (ii) such other persons who were, as of June 30, 2011, controlled by, or under common control with, 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

Portions of the Pepco Holdings, Inc. definitive proxy statement for the 2012 Annual Meeting of Stockholders to be filed with the Securities and Exchange Commission within 120 days after December 31, 2011 are incorporated by reference into Part III of this report.

TABLE OF CONTENTS
			Page
Glossary of Terms				i
Forward-Looking Statements				1
PART I
Item 1.	-	Business		3
Item 1A.	-	Risk Factors		23
Item 1B.	-	Unresolved Staff Comments		37
Item 2.	-	Properties		38
Item 3.	-	Legal Proceedings		39
Item 4.	-	Mine Safety Disclosures		39
PART II
Item 5.	-	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		40
Item 6.	-	Selected Financial Data		43
Item 7.	-	Management’s Discussion and Analysis of Financial Condition and Results of Operations		44
Item 7A.	-	Quantitative and Qualitative Disclosures About Market Risk		125
Item 8.	-	Financial Statements and Supplementary Data		128
Item 9.	-	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure		321
Item 9A.	-	Controls and Procedures		321
Item 9B.	-	Other Information		322
PART III
Item 10.	-	Directors, Executive Officers and Corporate Governance		323
Item 11.	-	Executive Compensation		323
Item 12.	-	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		323
Item 13.	-	Certain Relationships and Related Transactions, and Director Independence		323
Item 14.	-	Principal Accounting Fees and Services		324
PART IV
Item 15.	-	Exhibits and Financial Statement Schedules		324
Schedule I	-	Condensed Financial Information of Parent Company		326
Schedule II	-	Valuation and Qualifying Accounts		331
Signatures				349
Exhibit 12	-	Statements Re: Computation of Ratios
Exhibit 21	-	Subsidiaries of the Registrant
Exhibit 23	-	Consents of Independent Registered Public Accounting Firm
Exhibits 31.1-31.8	-	Rule 13a-14a/15d-14(a) Certifications
Exhibits 32.1-32.4	-	Section 1350 Certifications

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
ACE	Atlantic City Electric Company
ACE Funding	Atlantic City Electric Transition Funding LLC
ADITC	Accumulated deferred investment tax credits
AFUDC	Allowance for funds used during construction
AOCL	Accumulated other comprehensive loss
AMI	Advanced metering infrastructure
ASC	Accounting Standards Codification
BART	Best Available Retrofit Technology
BGS	Basic Generation Service
BGS-CIEP	BGS-Commercial and Industrial Energy Price
BGS-FP	BGS-Fixed Price
Bondable Transition Property	Principal and interest payments on the transition bonds and related taxes, expenses and fees
BSA	Bill Stabilization Adjustment
Budget Support Act	The Fiscal Year 2012 Budge Support Act of 2011, approved by the Council of the District of Columbia on June 14, 2011
CAIR	Clean Air Interstate Rule issued by EPA
Calpine	Calpine Corporation, the purchaser of Conectiv Energy’s wholesale power generation business
CERCLA	Comprehensive Environmental Response, Compensation, and Liability Act of 1980
Conectiv	Conectiv, LLC (formerly Conectiv), a wholly owned subsidiary of PHI and the parent of DPL and ACE
Conectiv Energy	Conectiv Energy Holding Company and its subsidiaries
CSAPR	Cross-State Air Pollution Rule
DCPSC	District of Columbia Public Service Commission
DDOE	District of Columbia Department of the Environment
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 SOS or BGS
DPL	Delmarva Power & Light Company
DEDA	Delaware Economic Development Authority
DOE	U.S. Department of Energy
DPSC	Delaware Public Service Commission
DRP	Shareholder Dividend Reinvestment Plan
Dynamic Pricing	A pricing mechanism that rewards SOS customers for lowering their energy use during those times when energy demand and, consequently, the cost of supplying electricity, are higher
EBITDA	Earnings before interest, taxes, depreciation, and amortization
EDC	Electricity Distribution Company
EDIT	Excess Deferred Income Taxes
EmPower Maryland	A DSM 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
FERC	Federal Energy Regulatory Commission
FHACA	Flood Hazard Area Control Act
FPA	Federal Power Act
GAAP	Accounting principles generally accepted in the United States of America

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Term	Definition
GCR	Gas Cost Rate
GWh	Gigawatt hour
HPS	Hourly Priced Service
IFRS	International Financial Reporting Standards
IIP	ACE’s Infrastructure Investment Program
IRS	Internal Revenue Service
ISDA	International Swaps and Derivatives Association
ISRA	Industrial Site Recovery Act
Line Losses	Estimates of electricity and gas expected to be lost in the process of its transmission and distribution to customers
LTIP	The Pepco Holdings, Inc. Long-Term Incentive Plan
MAPP	Mid-Atlantic Power Pathway
Market Transition Charge Tax	Revenue ACE receives, and pays to ACE Funding to recover income taxes associated with Transition Bond Charge revenue
Mcf	Thousand Cubic Feet
MDC	MDC Industries, Inc.
Medicare Act	Medicare Prescription Drug Improvement and Modernization Act of 2003
Medicare Part D	A prescription drug benefit under the Medicare Act
MFVRD	Modified fixed variable rate design
Mirant	Mirant Corporation
MMBtu	One Million British Thermal Units
MPSC	Maryland Public Service Commission
MSCG	Morgan Stanley Capital Group, Inc.
MWh	Megawatt hours
NAV	Net Asset Value
NERC	North American Electric Reliability Corporation
NYMEX	New York Mercantile Exchange
NJBPU	New Jersey Board of Public Utilities
NJDEP	New Jersey Department of Environmental Protection
NOx	Nitrogen oxide
NPCC	Northeast Power Coordinating Council
NPDES	National Pollutant Discharge Elimination System
NPL	National Priorities List
NUGs	Non-utility generators
OPEB	Other postretirement benefit
PARS	Performance accelerated restricted stock
PCBs	Polychlorinated biphenyls
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.
PJM	PJM Interconnection, LLC
PJM RTO	PJM regional transmission organization
Power Delivery	The operations of Pepco, DPL and ACE, engaged primarily in the transmission, distribution and default supply of electricity and the distribution and supply of natural gas
PPA	Power purchase agreement
PRP	Potentially responsible party

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Term	Definition
PUHCA 2005	Public Utility Holding Company Act of 2005
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
Reporting Company	Each of PHI, Pepco, DPL and 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
RFC	ReliabilityFirst Corporation
RFP	Request for proposals
RI/FS	Remedial investigation and feasibility study
RIM	Reliability investment recovery mechanism
ROE	Return on equity
RPM	Reliability Pricing Model
RPS	Renewable Energy Portfolio Standards
SEC	Securities and Exchange Commission
SO2	Sulfur dioxide
SOCA	Standard Offer Capacity Agreement
SOS	Standard Offer Service (the supply of electricity by Pepco in the District of Columbia, by Pepco and DPL in Maryland and by DPL in Delaware to retail customers who have not elected to purchase electricity from a competitive supplier)
SPCC	Spill Prevention, Control, and Countermeasure plans, required pursuant to federal regulations requiring plans for facilities using oil-containing equipment in proximity to surface waters
T&D	Transmission and distribution
Transition Bonds	Transition Bonds issued by ACE Funding
VADEQ	Virginia Department of Environmental Quality
VaR	Value at Risk
VRDBs	Variable Rate Demand Bonds
WACC	Weighted average cost of capital

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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 and by the Private Securities Litigation Reform Act of 1995. These statements include declarations regarding the intents, beliefs, estimates and current expectations of one or more Reporting Companies 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 Company’s 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 their subsidiaries’ control and may cause actual results to differ materially from those contained in forward-looking statements:

• Changes in governmental policies and regulatory actions affecting the energy industry, 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;

• The outcome of pending and future rate cases, including the possible disallowance of costs and expenses;

• 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 PHI’s regulated utilities;

• Weather conditions affecting usage and emergency restoration costs;

• Population growth rates and changes in demographic patterns;

• Changes in customer energy demand due to conservation measures and the use of more energy-efficient products;

• General economic conditions, including the impact of an economic downturn or recession on energy usage;

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

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• 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 their 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 events, including the threat of domestic terrorism 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” in this Annual Report on Form 10-K, and investors should refer to such risk factors in evaluating the forward-looking statements contained in this Form 10-K.

Any forward-looking statements speak only as to the date of this Form 10-K for each Reporting Company 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, nor can the impact of any such factor be assessed 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.

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Part I

Item 1. BUSINESS

Overview

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:

• Potomac Electric Power Company, which was incorporated in Washington, D.C. in 1896 and became a domestic Virginia corporation in 1949,

• Delmarva Power & Light Company, which was incorporated in Delaware in 1909 and became a domestic Virginia corporation in 1979, and

• Atlantic City Electric Company, which was incorporated in New Jersey in 1924.

Through Pepco Energy Services, Inc. and its subsidiaries (collectively, Pepco Energy Services), PHI also provides energy efficiency and renewable energy services primarily to government and institutional customers. Pepco Energy Services is in the process of winding down its competitive electricity and natural gas retail supply business and preparing for the retirement of its two oil-fired generating facilities.

In addition, through Potomac Capital Investment Corporation (PCI), PHI holds several cross-border energy lease investments as described below under the heading “Other Business Operations.”

The following chart shows, in simplified form, the corporate structure of PHI and its principal subsidiaries:

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PHI Service Company, a 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 a service agreement 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 methods set forth in the service agreement.

Pepco Holdings’ management has identified its operating segments at December 31, 2011 as (i) Power Delivery, consisting of the operations of Pepco, DPL and ACE, engaged primarily in the transmission, distribution and default supply of electricity and the distribution and supply of natural gas, (ii) Pepco Energy Services and (iii) Other Non-Regulated, consisting primarily of the operations of PCI. For financial information relating to PHI’s segments, see Note (5), “Segment Information,” to the consolidated financial statements of PHI.

Discontinued Operations

In April 2010, the Board of Directors approved a plan for the disposition of PHI’s competitive wholesale power generation, marketing and supply business, which had been conducted through subsidiaries of Conectiv Energy Holding Company (Conectiv Energy). On July 1, 2010, PHI completed the sale of Conectiv Energy’s wholesale power generation business to Calpine Corporation (Calpine) for $1.64 billion. The disposition of Conectiv Energy’s remaining assets and businesses not included in the Calpine sale, including its load service supply contracts, energy hedging portfolio and certain tolling agreements, has been substantially completed. The operations of Conectiv Energy, which previously comprised a separate segment for financial reporting purposes, are being accounted for as a discontinued operation. For further information on the former Conectiv Energy segment and the disposition of its assets, operations and obligations, see Note (20), “Discontinued Operations,” to the consolidated financial statements of PHI.

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 of PHI, Pepco, DPL and ACE files reports with the Securities and Exchange Commission (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 made available free of charge on PHI’s Internet Web site as soon as reasonably practicable after such documents are electronically filed with or furnished to the SEC. Copies of these reports may be found at http://www.pepcoholdings.com/investors. The information contained on the web sites listed above is not a part of this Form 10-K, and any web site references are not intended to be made through active hyperlinks.

Business Strategy

PHI’s business strategy is to become a top-performing, regulated power delivery company focused on:

• investing in transmission and distribution infrastructure to improve reliability of electric service;

• building a smarter grid to automate certain functions on the electric system, restore power more efficiently and provide customers detailed energy information to help them control their energy costs;

• investing in advanced technologies, new processes and personnel to enhance the customer experience during power restoration, including delivering enhanced customer communications;

• pursuing a regulatory strategy that results in earning reasonable rates of return and timely cost recovery of PHI’s investments;

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• growing PHI’s energy services business by providing comprehensive energy management solutions and developing, installing and operating renewable energy solutions; and

• demonstrating PHI’s core values of safety, diversity and environmental stewardship through PHI’s business approaches and tangible business practices and outcomes.

To further its business strategy, PHI may examine transactions involving its existing businesses, including entering into joint ventures, disposing of businesses or making acquisitions. PHI also may refine components of its business strategy as it deems necessary or appropriate in response to business factors and conditions, including regulatory requirements.

Description of Business

Power Delivery

PHI’s primary business is Power Delivery. Power Delivery in 2011, 2010 and 2009, produced 79%, 73%, and 67%, respectively, of PHI’s consolidated operating revenues and 78%, 81%, and 78%, respectively, of PHI’s consolidated operating income.

Each utility comprising Power Delivery is regulated in the jurisdictions that encompass its electricity distribution service territory and is regulated by FERC for its electricity transmission facilities. DPL also is a regulated natural gas utility serving portions of Delaware. In the aggregate, Power Delivery distributes electricity to more than 1.8 million customers in the mid-Atlantic region and delivers natural gas to approximately 124,000 customers in Delaware. None of PHI’s three utilities owns any electric generation facilities.

Distribution and Default Supply of Electricity

Pepco, DPL and ACE each 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, or across, the utility’s service territory. Distribution facilities carry electricity from the transmission facilities to the end-use customers located in the utility’s service territory.

Each utility is responsible for the distribution of electricity 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 retail supplier. The regulatory term for this default supply service is Standard Offer Service (SOS) in Delaware, the District of Columbia and Maryland, and Basic Generation Service (BGS) in New Jersey. In this Form 10-K, these supply services are referred to generally as Default Electricity Supply.

Transmission of Electricity and Relationship with PJM

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 the mid-Atlantic portion of the United States and parts of the Midwest. Pepco, DPL and ACE each is a member of the PJM Regional Transmission Organization (PJM RTO), the regional transmission organization designated by the Federal Energy Regulatory Commission (FERC) to coordinate the movement of wholesale electricity within a region consisting of all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia.

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PJM, the FERC-approved independent grid operator, manages the transmission grid and the wholesale electricity market in the PJM RTO region. Any entity that wishes to have wholesale electricity delivered at any point within the PJM RTO region must obtain transmission services from PJM. In accordance with FERC-approved rules, Pepco, DPL, ACE and the other transmission-owning utilities in the region make their transmission facilities available to the PJM RTO, and PJM directs and controls the operation of these transmission facilities. For transmission services, transmission owners are paid rates proposed by the transmission owner and approved by FERC. 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 the PJM RTO region. The PJM Board of Managers reviews and approves each PJM regional transmission expansion plan, including whether to include new construction of transmission facilities proposed by PJM RTO members in the plan and, if so, the target in-service date for those facilities.

Seasonality

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 long standing practice by which the applicable public service commissions set distribution rates based on a fixed charge per kilowatt-hour of electricity used by the customer. 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 BSA for retail customers of Pepco and DPL in Maryland in June 2007 and for customers of Pepco in the District of Columbia in November 2009, distribution revenues 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. Distribution revenues are not decoupled for the distribution of electricity and natural gas by DPL in Delaware or 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.

Regulated Utility Subsidiaries

The following is a more detailed description of the business of each of PHI’s three regulated utility subsidiaries:

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Pepco

Pepco is engaged in the transmission, distribution and default supply of electricity in the District of Columbia and major portions of Prince George’s County and Montgomery County in Maryland. Pepco’s service territory covers approximately 640 square miles and has a population of approximately 2.2 million. As of December 31, 2011, Pepco distributed electricity to 788,000 customers (of which 257,000 were located in the District of Columbia and 531,000 were located in Maryland), as compared to 787,000 customers as of December 31, 2010 (of which 256,000 were located in the District of Columbia and 531,000 were located in Maryland). As of December 31, 2009, Pepco distributed electricity to 778,000 customers (of which 252,000 were located in the District of Columbia and 526,000 were located in Maryland).

In 2011, Pepco distributed a total of 26,895,000 megawatt hours of electricity, of which 57% was distributed within its Maryland territory and 43% within the District of Columbia. Of this amount, 30% of the total megawatt hours were delivered to residential customers, 50% to commercial customers, and 20% to United States and District of Columbia government customers. In 2010, Pepco distributed a total of 27,665,000 megawatt hours of electricity, of which 57% was distributed within its Maryland territory and 43% within the District of Columbia. Of this amount, 30% of the total megawatt hours were distributed to residential customers, 49% to commercial customers, and 21% to United States and District of Columbia government customers. In 2009, Pepco distributed a total of 26,549,000 megawatt hours of electricity, of which 57% was distributed within its Maryland territory and 43% within the District of Columbia. Of this amount, 29% of the total megawatt hours were distributed to residential customers, 50% to commercial customers, and 21% to United States and District of Columbia government customers.

Pepco has been providing SOS in Maryland since July 2004. Pursuant to orders issued by the Maryland Public Service Commission (MPSC), Pepco is obligated to provide SOS (i) to residential and small commercial customers until further action of the Maryland General Assembly and (ii) to medium-sized commercial customers through November 2012. Pepco purchases the electricity required to satisfy these SOS obligations from wholesale suppliers under contracts entered into in accordance with competitive bid procedures approved and supervised by the MPSC. Pepco also is obligated to provide Standard Offer Service, known as Hourly Priced Service (HPS), for large Maryland customers. Power to supply HPS customers is acquired in next-day and other short-term PJM RTO markets. Pepco is entitled to recover from its SOS customers the cost of acquiring the SOS supply, plus an administrative charge that is intended to allow Pepco to recover the administrative costs incurred to provide the SOS and a modest margin. Because the margin varies by customer class, the actual average margin over any given time period depends on the number of Maryland SOS customers in each customer class and the electricity used by such customers. Pepco is paid tariff rates for the distribution of electricity over its transmission and distribution facilities to all electricity customers in its Maryland service territory regardless of whether the customer receives SOS or purchases electricity from another supplier.

Pepco has been providing SOS in the District of Columbia since February 2005. Pursuant to orders issued by the District of Columbia Public Service Commission (DCPSC), Pepco is obligated to provide SOS to residential and small, medium-sized and large commercial customers indefinitely. Pepco purchases the electricity required to satisfy its SOS obligations from wholesale suppliers under contracts entered into in accordance with a competitive bid procedure approved and supervised by the DCPSC. Pepco is entitled to recover from its SOS customers the costs of acquiring the SOS supply, plus an administrative charge that is intended to allow Pepco to recover the administrative costs incurred to provide the SOS and a modest margin. Because the margin varies by customer class, the actual average margin over any given time period depends on the number of District of Columbia SOS customers in each customer class and the amount of electricity used by such customers. Pepco is paid tariff rates for the distribution of electricity over its transmission and distribution facilities to all electricity customers in its District of Columbia service territory regardless of whether the customer receives SOS or purchases electricity from another supplier.

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For the year ended December 31, 2011, 43% of Pepco’s Maryland distribution sales (measured by megawatt hours) were to SOS customers, as compared to 46% and 49% in 2010 and 2009, respectively, and 27% of its District of Columbia distribution sales (measured by megawatt hours) were to SOS customers in 2011, as compared to 29% and 31% in 2010 and 2009, respectively.

DPL

DPL is engaged in the transmission, distribution and default supply of electricity in Delaware and portions of 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.

Distribution and Supply of Electricity

DPL’s electricity distribution service territory consists 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 has a population of approximately 1.4 million. As of December 31, 2011, DPL delivered electricity to 501,000 customers (of which 301,000 were located in Delaware and 200,000 were located in Maryland), as compared to 500,000 customers as of December 31, 2010 (of which 301,000 were located in Delaware and 199,000 were located in Maryland). As of December 31, 2009, DPL delivered electricity to 498,000 customers (of which 299,000 were located in Delaware and 199,000 were located in Maryland).

In 2011, DPL distributed a total of 12,688,000 megawatt hours of electricity to its customers, of which 66% was distributed within its Delaware territory and 34% within Maryland. Of this amount, 41% of the total megawatt hours were distributed to residential customers, 42% to commercial customers and 17% to industrial customers. In 2010, DPL distributed a total of 12,853,000 megawatt hours of electricity, of which 66% was distributed within its Delaware territory and 34% within Maryland. Of this amount, 42% of the total megawatt hours were distributed to residential customers, 41% to commercial customers and 17% to industrial customers. In 2009, DPL distributed a total of 12,494,000 megawatt hours of electricity, of which 67% was distributed within its Delaware territory and 33% within Maryland. Of this amount, 39% of the total megawatt hours were distributed to residential customers, 41% to commercial customers and 20% to industrial customers.

DPL has been providing SOS in Delaware since May 2006. Pursuant to orders issued by the Delaware Public Service Commission (DPSC), DPL is obligated to provide SOS to residential, small commercial and industrial customers through May 2014, and to medium, large and general service commercial customers through May 2012. DPL purchases the electricity required to satisfy these SOS obligations from wholesale suppliers under contracts entered into in accordance with competitive bid procedures approved and supervised by the DPSC. DPL also has an obligation to provide SOS, known as HPS, for the largest Delaware customers. Power to supply the HPS customers is acquired in next-day and other short-term PJM RTO markets. DPL’s rates for supplying SOS and HPS reflect the associated capacity, energy (including satisfaction of renewable energy requirements), transmission and ancillary services costs and an amount referred to as a Reasonable Allowance for Retail Margin. Components of the Reasonable Allowance for Retail Margin include a fixed annual margin of approximately $2.75 million, plus estimated incremental expenses, a cash working capital allowance, and recovery, with a return over five years ending 2011, of the capitalized costs of the billing system used for billing HPS customers. DPL is paid tariff rates for the distribution of electricity over its transmission and distribution facilities to all electricity customers in its Delaware service territory regardless of whether the customer receives SOS or purchases electricity from another supplier.

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DPL has been providing SOS in Maryland since June 2004. Pursuant to orders issued by the MPSC, DPL is obligated to provide SOS to residential and small commercial customers until further action of the Maryland General Assembly, and to medium-sized commercial customers through May 2014. DPL purchases the electricity required to satisfy these SOS obligations from wholesale suppliers under contracts entered into in accordance with a competitive bid procedure approved and supervised by the MPSC. DPL also is obligated to provide HPS for large Maryland customers. Power to supply the HPS customers is acquired in next-day and other short-term PJM RTO markets. DPL is entitled to recover from its SOS customers the costs of acquiring the SOS supply, plus an administrative charge that is intended to allow DPL to recover the administrative costs incurred to provide the SOS and a modest margin. Because the margin varies by customer class, the actual average margin over any given time period depends on the number of Maryland SOS customers in each customer class and the electricity used by such customers. DPL is paid tariff rates for the distribution of electricity over its transmission and distribution facilities to all electricity customers in its Maryland service territory regardless of whether the customer receives SOS or purchases electricity from another supplier.

For the year ended December 31, 2011, 51% of DPL’s Delaware distribution sales (measured by megawatt hours) were to SOS customers, as compared to 53% and 51% in 2010 and 2009, respectively, and 58% of its Maryland distribution sales (measured by megawatt hours) were to SOS customers in 2011, as compared to 63% in 2010 and 2009.

Supply and Distribution 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 has a population of approximately 500,000. Large volume commercial, institutional, and industrial natural gas customers may purchase natural gas either from DPL or from other suppliers. DPL uses its natural gas distribution facilities to deliver natural gas to customers that choose to purchase natural gas from another supplier. Intrastate transportation customers pay DPL distribution service rates approved by the DPSC. 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. For the year ended December 31, 2011, DPL supplied 64% of the natural gas that it delivered, compared to 65% in 2010 and 68% in 2009.

As of December 31, 2011, DPL delivered natural gas to 124,000 customers as compared to 123,000 customers as of December 31, 2010 and 2009. In 2011, DPL delivered 19,000,000 Mcf (thousand cubic feet) of natural gas to customers in its Delaware service territory, of which 40% were sales to residential customers, 23% to commercial customers, 1% to industrial customers and 36% to customers receiving a transportation-only service. In 2010, DPL delivered 19,000,000 Mcf of natural gas, of which 41% were sales to residential customers, 23% were sales to commercial customers, 1% were sales to industrial customers and 35% were sales to customers receiving a transportation-only service. In 2009, DPL delivered 19,000,000 Mcf of natural gas, of which 42% were sales to residential customers, 25% were sales to commercial customers, 1% were sales to industrial customers and 32% were sales to customers receiving a transportation-only service.

ACE

ACE is primarily engaged in the transmission, distribution and default supply of electricity in a service territory consisting of Gloucester, Camden, Burlington, Ocean, Atlantic, Cape May, Cumberland and Salem counties in southern New Jersey. ACE’s service territory covers approximately 2,700 square miles and has a population of approximately 1.1 million. As of December 31, 2011, ACE distributed electricity to 547,000 customers in its service territory, as compared to 548,000 and 547,000 customers as of December 31, 2010 and 2009, respectively.

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In 2011, ACE distributed a total of 9,683,000 megawatt hours of electricity to its customers, of which 46% of the total was distributed to residential customers, 45% to commercial customers and 9% to industrial customers. In 2010, ACE distributed a total of 10,185,000 megawatt hours of electricity to its customers, of which 46% of the total was distributed to residential customers, 44% to commercial customers, and 10% to industrial customers. In 2009, ACE distributed a total of 9,659,000 megawatt hours of electricity to its customers, of which 45% was distributed to residential customers, 45% to commercial customers, and 10% to industrial customers.

Electric customers in New Jersey who do not choose another supplier receive BGS from their electric distribution company. New Jersey’s electric distribution companies, including ACE, jointly obtain the electricity to meet their BGS obligations from competitive suppliers selected through auctions authorized by the New Jersey Board of Public Utilities (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.

ACE provides two types of BGS:

• BGS-Fixed Price (BGS-FP), which is supplied to smaller commercial and residential customers at seasonally-adjusted fixed prices. BGS-FP rates change annually on June 1 and are based on the average BGS price obtained at auction in the current year and the two prior years. As of December 31, 2011, ACE’s BGS-FP peak load was approximately 1,500 megawatts, which represents approximately 98% of ACE’s total BGS load.

• BGS-Commercial and Industrial Energy Price (BGS-CIEP), which is supplied to large customers at hourly PJM RTO real-time market prices for a term of 12 months. As of December 31, 2011, ACE’s peak BGS-CIEP load was approximately 20 megawatts, which represents approximately 2% of ACE’s BGS load.

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 on the supply component of the BGS it supplies to customers. ACE is paid tariff rates for the distribution of electricity over its transmission and distribution facilities to all electricity customers in its service territory regardless of whether the customer receives BGS or purchases electricity from another supplier.

For the year ended December 31, 2011, 56% of ACE’s total distribution sales (measured by megawatt hours) were to BGS customers, as compared to 65% and 73% in 2010 and 2009, respectively.

ACE has contracts with three unaffiliated non-utility generators (NUGs) under which ACE is obligated to purchase capacity and the entire generation output of the facilities. One of the contracts expires in 2016 and the other two expire in 2024. In 2011, ACE purchased 1.9 million megawatt hours of power from the NUGs. ACE sells this electricity into the wholesale market administered by PJM.

In 2001, ACE established Atlantic City Electric Transitional 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 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.

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Other Power Delivery Initiatives and Activities

Reliability Enhancement and Emergency Restoration Improvement Plans

In 2010, PHI announced comprehensive reliability enhancement plans for Pepco in Maryland and the District of Columbia. These reliability enhancement plans include various initiatives such as enhanced vegetation management, the identification and upgrading of under-performing feeder lines, the addition of new facilities to support load, the installation of distribution automation systems on both the overhead and underground network system, the rejuvenation and replacement of underground residential cables, improvements to substation supply lines and selective undergrounding of portions of existing above ground primary feeder lines, where appropriate to improve reliability and enhance customer satisfaction. During 2011, Pepco continued to execute on its plans to improve reliability which it believes have contributed to its progress in reducing both the frequency and duration of power outages. During 2011, Pepco invested $120 million in capital expenditures on these reliability enhancement activities. Since initiating the reliability enhancement plans, Pepco trimmed trees along nearly 3,500 miles of power lines, completed 48 expansion projects to meet growth in customer demand for electricity, upgraded more than 340 miles of aging underground lines, and added 125 automated switches that will reroute power more effectively during outages. PHI has extended its reliability enhancement efforts to DPL and ACE.

In 2011 PHI initiated an accelerated emergency restoration improvement program prior to the start of the 2011 summer storm season. As part of this program, Pepco:

• more than doubled the number of telephone trunk lines to its Washington, D.C. regional call center;

• developed mobile applications to report and track outages;

• improved outage information on its Web site to enhance communications with its customers;

• implemented regional storm centers for more efficient crew dispatch;

• implemented better methodologies for estimating times for restoration of power;

• employed technology, including smart meters, to obtain real-time information from the field on power outages and to assist restoration planning efforts by providing data needed to conduct real-time damage assessments;

• augmented training of its emergency response personnel; and

• installed a backup crisis call center.

These and other emergency restoration improvements implemented as a part of this program were tested during Hurricane Irene in August 2011. Although nearly 500,000 customers across all three utilities were without power at the peak of the storm, nearly 98% of outages were restored within a little more than two days.

PHI’s capital expenditures for continuing reliability enhancement efforts are included in the table of projected capital expenditures, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations —Capital Resources and Liquidity – Capital Expenditures.”

Blueprint for the Future

Each of PHI’s utility subsidiaries is participating in a PHI initiative referred to as “Blueprint for the Future,” which is designed to meet the challenges of rising energy costs, respond to concerns about the environment, improve reliability and address government energy reduction goals. The initiative includes the implementation of various programs to help customers better manage their energy use, reduce the total cost of energy and provide other benefits. These programs also enhance the ability of PHI’s utilities to better manage and operate their electrical and natural gas distribution systems.

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One of the primary initiatives of Blueprint for the Future is the installation of smart meters (also known as Advanced Metering Infrastructure (AMI)) for electric and natural gas customers, which are subject to the approval of applicable state regulators. These smart meters allow the utilities, among other capabilities, to remotely read meters, significantly reduce the number of customer bills that are based on usage estimates, improve outage management and detection, and provide customers with more detailed information about their energy consumption. In addition to the replacement of existing meters, the AMI system involves the construction of a wireless network across the service territories of PHI’s utility subsidiaries and the implementation and integration of new and existing information technology systems to collect and manage data made available by the advanced meters. The implementation of the AMI system involves a combination of technologies provided by multiple vendors. Meter installation is substantially complete for DPL electric customers in Delaware, with meter activation expected to be completed in the first quarter of 2012. Meter installation is progressing for Pepco customers in both the District of Columbia and Maryland, with installation expected to be complete in the second and fourth quarters of 2012, respectively. The respective public service commissions have approved the creation of a regulatory asset to defer AMI costs between rate cases, as well as the accrual of a return on the deferred costs. Thus, these costs will be recovered through base rates in the future.

Approval of AMI is still pending for electric customers in DPL’s Maryland service territory, and has been deferred for ACE in New Jersey.

On December 20, 2011, the Delaware Public Service Commission approved DPL’s request to implement dynamic pricing for its Delaware customers. Dynamic pricing will reward SOS customers for lowering their energy use during those times when energy demand and, consequently, the cost of supplying electricity, are higher. Implementation for residential customers will be phased in commencing in 2012 through 2013. Implementation of dynamic pricing for commercial and industrial SOS customers in Delaware will be phased in commencing in 2013 through 2014.

Dynamic pricing has been approved in concept for Pepco customers in Maryland, with phase-in for residential customers beginning in 2012. Pepco has dynamic pricing proposals pending in the District of Columbia jurisdiction with the proposed phase-in for residential customers anticipated to begin in 2012. Dynamic pricing has been approved in concept pending AMI deployment authorization for DPL’s Maryland customers and has been deferred for ACE’s customers in New Jersey.

For a discussion of the capital expenditures associated with Blueprint for the Future, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations —Capital Resources and Liquidity – Capital Requirements – Blueprint for the Future.”

MAPP Project

In October 2007, the PJM Board of Managers approved PHI’s proposal to construct a new 230-mile, 500-kilovolt interstate transmission line referred to as the Mid-Atlantic Power Pathway (MAPP), as part of PJM’s regional transmission expansion plan to address the reliability objectives of the PJM RTO system. Since that time, there have been various modifications to the proposal that have redefined the length and route of the MAPP project. PJM has approved the use of advanced direct current technology for segments of the project, including the portion of the line that will traverse under the Chesapeake Bay. The direct current portion of the line will be 640 kilovolts and the remainder of the line will be 500 kilovolts. As currently approved by the PJM Board of Managers, MAPP is approximately 152 miles in length originating at the Possum Point substation in Virginia and ending at the Indian River substation in Delaware. The cost of the MAPP project for Pepco and DPL is currently estimated to be $1.2 billion.

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In connection with the MAPP project, FERC has authorized for each of Pepco and DPL a 150 basis point adder to its return on equity, resulting in a FERC-approved rate of return on the MAPP project of 12.8%, along with full recovery of construction work-in-progress and prudently incurred abandoned plant costs.

On August 18, 2011, PJM notified PHI that the scheduled in-service date for MAPP has been delayed from June 1, 2015 to the 2019 to 2021 time period, after taking into account changes in demand response, generation retirements and additions, and a revised load forecast for the PJM region that is lower than the load that was forecasted in prior PJM studies. A more recent load forecast continues to support this trend. PJM has retained the MAPP project in its 2011 Regional Transmission Expansion Plan. In light of the delayed in-service date for MAPP, substantially all of the anticipated capital expenditures associated with MAPP have been delayed until at least 2016 based on current projections.

The exact revised in-service date of MAPP will be evaluated as part of PJM’s 2012 Regional Transmission Expansion Plan review process. Until PJM’s evaluation is concluded, PJM has directed PHI to limit further development efforts with respect to the MAPP project and to proceed with only those development efforts reasonably necessary to allow the MAPP project to be quickly restarted if and when deemed necessary. Based on PJM’s direction, PHI intends to continue to complete the right-of-way acquisition for the proposed route, and some environmental and other preparatory activities.

For a discussion of the capital expenditures associated with the MAPP Project, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations —Capital Resources and Liquidity – Capital Requirements – MAPP Project.”

Pepco Energy Services

Pepco Energy Services is engaged in the following businesses:

• providing energy efficiency services principally to federal, state and local government customers, and designing, constructing, and operating combined heat and power and central energy plants.

• providing high voltage electric construction and maintenance services to customers throughout the United States and low voltage electric construction and maintenance services and streetlight construction and asset management services to utilities, municipalities and other customers in the Washington, D.C. area.

Most of Pepco Energy Services’ contracts with federal, state and local governments, as well as 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 contain explicit mechanisms that, 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.

From time to time, PHI is required to guarantee the obligations of Pepco Energy Services under certain of its construction contracts. At December 31, 2011, PHI’s guarantees of Pepco Energy Services’ projects totaled $65 million.

Pepco Energy Services has historically been engaged in the business of providing retail energy supply services, consisting of the sale of electricity, including electricity from renewable resources, primarily to commercial, industrial and government customers located primarily in the mid-Atlantic and northeastern regions of the United States, as well as Texas and Illinois, and the sale of natural gas to customers located primarily in the mid-Atlantic region. In December 2009, PHI announced that it would wind-down the retail energy supply business. Pepco Energy Services is implementing this wind-down by not entering into any new supply contracts, while continuing to perform under its existing supply contracts through their expiration dates. As of December 31, 2011, Pepco Energy Services’ estimated retail electricity backlog was approximately 3.9 million megawatts for distribution through 2014, a decrease of approximately 5.8 million megawatts and 16.2 million megawatts when compared to December 31, 2010 and 2009, respectively. For additional information on the Pepco Energy Services wind-down, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations – General Overview – Pepco Energy Services.”

Pepco Energy Services’ retail natural gas sales volumes and revenues are seasonally dependent. Colder weather from November through March of each year generally translates into increased sales volumes, which, when coupled with higher natural gas prices during these months, allows Pepco Energy Services to recognize generally higher revenues as compared to other months of the year. Retail electricity sales volumes are also seasonally dependent, with sales in the summer and winter months being generally higher than other months of the year, which, when coupled with higher electricity prices during these periods, allows Pepco Energy Services to recognize generally higher revenues as compared to other periods during the year. However, as Pepco Energy Services is in the process of winding down its retail energy supply business, this effect of seasonality will likely decrease as such wind-down is completed. The energy services business is not seasonal.

Pepco Energy Services owns and operates two oil-fired generating facilities. The facilities are located in Washington, D.C. and have a combined generating capacity of approximately 790 megawatts. Pepco Energy Services sells the output of these facilities into the wholesale market administered by PJM. In February 2007, Pepco Energy Services provided notice to PJM of its intention to deactivate these facilities by the end of May 2012. PJM has informed Pepco

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Energy Services that these facilities will not be needed for reliability after May 2012; therefore decommissioning plans are currently underway and on schedule. It is not expected that deactivation of these facilities will have a material impact on PHI’s financial condition, results of operations or cash flows.

Pepco Energy Services also owns three landfill gas-fired electricity facilities that have a total generating capacity rating of ten megawatts, the output of which is sold into the wholesale market administered by PJM. Pepco Energy Services also owns a solar photovoltaic facility that has a generating capacity rating of two megawatts, the output of which is sold to its host facility.

Pepco Energy Services’ continuing lines of business will not be significantly affected by the wind-down of the retail energy supply business.

PJM Capacity Markets

Historically, Pepco Energy Services has earned revenue from the sale of capacity associated with its generating facilities. PJM is responsible for ensuring that within its transmission control area there is sufficient generating capacity available to meet the load requirements plus a reserve margin and locates and prices electricity capacity by holding annual auctions covering capacity to be supplied over consecutive 12-month periods. Pepco Energy Services has been exposed to deficiency charges payable to PJM when their generation units failed to meet certain reliability levels.

Since Pepco Energy Services intends to deactivate its two oil-fired generating facilities by May 2012, Pepco Energy Services has not included the facilities’ capacity in any auctions for periods after May 2012.

Competition

Pepco Energy Services’ energy services business is highly competitive. 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 construction or utility holding companies (as is the case with Pepco Energy Services). Among the factors as to which the energy services business competes are the amount and duration of the guarantees provided in energy savings performance contracts and the quality and value of service provided to customers. The energy services business is impacted by new entrants into the market, energy prices, and general economic conditions.

Other Business Operations

Between 1994 and 2002, PCI, a subsidiary of PHI, entered into eight cross-border energy lease investments involving public utility assets (primarily consisting of hydroelectric generation and coal-fired electric generation facilities and natural gas distribution networks) located outside of the United States. Each of these investments is structured as a sale and leaseback transaction commonly referred to as a sale-in, lease-out, or SILO, transaction. During the second quarter of 2011, PHI entered into early termination agreements with two lessees involving all of the leases comprising one of the eight lease investments and a small portion of the leases comprising a second lease investment. The early termination of the leases were negotiated at the request of the lessees and were completed in June 2011. As of December 31, 2011, PHI’s equity investment in its cross-border energy leases was approximately $1.3 billion. For additional information concerning these cross-border energy lease investments, see Note (8), “Leasing Activities,” and Note (17), “Commitments and Contingencies,” to the consolidated financial statements of PHI.

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Regulation

The operations of PHI’s utility subsidiaries, including the rates and tariffs they are permitted to charge customers for the distribution and transmission 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 follows:

• Pepco’s electricity distribution operations are regulated in Maryland by the MPSC and in the District of Columbia by the DCPSC.

• DPL’s electricity distribution operations are regulated in Maryland by the MPSC and in Delaware by the DPSC.

• DPL’s natural gas distribution and intrastate transportation operations in Delaware are regulated by the DPSC.

• ACE’s electricity distribution operations are regulated by the NJBPU.

• Each utility subsidiary’s transmission facilities are regulated by FERC.

• DPL’s interstate transportation and wholesale sale of natural gas are regulated by FERC.

• Each utility subsidiary’s and Pepco Energy Services’ bulk power system is subject to reliability standards established by NERC.

Rates and tariffs are established by these regulatory commissions. PHI’s utility subsidiaries have filed rate cases which are pending in each of its jurisdictions as further described in Note (7), “Regulatory Matters – Regulatory Proceedings – Rate Proceedings,” to the consolidated financial statements of PHI.

The rates and tariffs established by these regulatory commissions are intended to balance the interests of the utilities’ customers and those of its investors by reflecting costs incurred during the period in which the rates are in effect, and giving each utility the opportunity to generate revenues sufficient to recover its costs, including a reasonable rate of return on investor supplied capital during such period. In establishing a utility’s rates, an important factor in the ability of each of Pepco, DPL and ACE to earn its authorized rate of return is the willingness of applicable public service commissions to adequately recognize forward-looking costs in the utility’s rate structure in order to minimize the shortfall in revenues 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.” Each of Pepco, DPL and ACE is currently experiencing significant regulatory lag because their investment in the rate base and operating expenses is outpacing revenue growth.

Higher operating and construction costs, including labor, material, depreciation, taxes and financing costs, as well as costs associated with enhanced distribution system reliability and environmental compliance, are expected at each of PHI’s utility subsidiaries for several years into the future. At the same time, low usage growth and customer growth is expected to limit the growth in revenues. This mismatch between high expense growth and low revenue growth exacerbates regulatory lag for each of PHI’s utility subsidiaries, making it more difficult for each utility to earn equity returns that are allowed by regulators without higher rates or other regulatory relief. See “Risk Factors – The failure of PHI to obtain timely recognition of costs in its rates may have a negative effect on PHI’s results of operations and financial condition.”

Pepco, DPL and ACE anticipate that they will continue to face regulatory lag. In their most recent rate cases, Pepco (in the District of Columbia and Maryland) and DPL (in Delaware and Maryland) each has proposed mechanisms that would track reliability and other expenses and permit the utility between rate cases to make adjustments in its rates for prudent investments as made, thereby seeking to reduce the magnitude of regulatory lag. In New Jersey, the NJBPU has approved certain rate recovery mechanisms

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in connection with ACE’s Infrastructure Investment Program (IIP), which ACE has proposed to extend and expand. There can be no assurance that these proposals or any other attempts by Pepco, DPL and ACE to mitigate regulatory lag will be approved, or that even if approved, the rate recovery mechanisms or any base rate cases will fully ameliorate the effects of regulatory lag. Until such time as these proposed mechanisms are approved, if necessary to address the problem of regulatory lag, the utilities plan to file rate cases at least annually in an effort to align more closely their revenue and related cash flow levels with other operation and maintenance spending and capital investments. In future rate cases, Pepco, DPL and ACE, as applicable, would also continue to seek cost recovery and tracking mechanisms from applicable regulatory commissions to reduce the effects of regulatory lag.

Maryland Reliability Investigation

In August 2010, following major storm events that occurred in July and August 2010, an investigation was initiated in Maryland into the reliability of Pepco’s distribution system and the quality of distribution service Pepco provided to its customers. As a result of that investigation, the MPSC imposed sanctions on Pepco in December 2011, including a fine of $1 million, which Pepco has paid. In accordance with the order, Pepco has filed a detailed work plan for the next five years, which provided a comprehensive description of Pepco’s reliability enhancement plan, its emergency response improvement project, and other communication and service restoration improvements. Pepco is also required to file quarterly updates and a year-end status report with the MPSC providing, among other things, detailed information about its reliability and emergency response improvement objectives, progress and spending (and explanations for any inability to meet such objectives), together with an analysis of trends concerning the measured duration and frequency of customer interruptions. In the required reports, Pepco will be required to demonstrate that its reliability enhancement plan costs were prudently spent and produced a significant improvement in reliability, and if it is unable to do so, the MPSC may deny Pepco reimbursement for future reliability enhancement investments or impose additional fines. In addition to the sanctions, the MPSC stated its intent to review the recovery of reliability costs in Pepco’s pending rate case and to disallow incremental costs it determines to be the result of imprudent management. Pepco believes its reliability costs have been prudently incurred. Furthermore, Pepco expects its reliability enhancement plan to enable Pepco to meet the MPSC’s requirements. For more information about the MPSC’s ruling in this proceeding, see Note (7), “Regulatory Matters – Regulatory Proceedings,” to the consolidated financial statements of PHI.

District of Columbia and Maryland Reliability and Customer Service Rulemakings

In December 2011, the MPSC approved proposed rules establishing reliability and customer service regulations, compliance with which is anticipated to be mandated as early as the second quarter of 2012. 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 thereafter and are intended to require Pepco to achieve a reliability level in the first quartile of all utilities in the nation by 2020. Pepco and DPL each expect to incur significant operation and maintenance spending and capital investments to comply with these requirements. Pepco believes that the DCPSC’s standards are achievable in the short term, but continues to believe that the standards may not be realistically achievable at an acceptable cost over the longer term. 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.

Maryland New Generation RFP Issuance Requirement

In September 2009, the MPSC initiated an investigation into whether Maryland’s regulated electric distribution companies (EDCs) should be required to enter into long-term contracts with entities that construct, acquire or lease, and operate, new electric generation facilities in Maryland. In September 2011, the MPSC issued a notice in which it stated that it had not made a final determination at this time whether new generation in Maryland is needed, but directed each of the four Maryland EDCs, including Pepco and DPL, to issue a request for proposal (RFP) for new generation resources by October 7, 2011. On that date, Pepco and DPL issued the RFP and sought additional information from the MPSC on

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several aspects of the process established in the notice, including whether the MPSC will consider a utility-owned generation option. Hearings were held on January 31, 2012, to obtain further input on whether the EDCs should be ordered to proceed with the RFP. Pepco and DPL have filed a request for rehearing of the notice. The MPSC has stated its intent to select generators and execute long-term contracts between the generators and selected EDCs in April 2012. PHI opposes the requirement to enter into such long-term contracts, which would be viewed as debt by the credit rating agencies and would have an adverse effect on PHI’s, Pepco’s and DPL’s credit metrics.

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. The SOCAs were established under a New Jersey law enacted to promote the construction of qualified electric generation facilities in New Jersey. The SOCAs are 15-year, financially settled transactions approved by the NJBPU that allow generators to receive payments from, or make payments to, ACE based on the difference between the fixed price in the SOCAs and the price for capacity that clears PJM. Each of the other EDCs in New Jersey has entered into SOCAs having the same terms with the same generation companies. The annual share of payments or receipts for ACE and the other EDCs is based upon each company’s annual proportion of the total New Jersey load attributable to all EDCs. The NJBPU has approved full recovery from distribution customers of payments made by ACE and the other EDCs, and distribution customers would be entitled to any payments received by ACE and the other EDCs.

ACE and the other EDCs entered the SOCAs under protest based on concerns about the potential cost to distribution customers and the negative credit rating agency implications and have filed lawsuits challenging the constitutionality of the New Jersey law. For more information about the New Jersey law and associated regulatory and legal proceedings, see Note (2), “Significant Accounting Policies – Consolidation of Variable Interest Entities – ACE Standard Offer Capacity Agreements,” to the consolidated financial statements of PHI.

Delaware Renewable Energy Portfolio Standards

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. In July 2011, the Governor of the State of Delaware signed legislation that expands DPL’s RPS obligations beginning in 2012. Before this legislation, DPL was required to obtain RECs for energy delivered only to SOS customers in Delaware; the legislation expands that requirement to energy delivered to all of DPL’s distribution customers in Delaware. DPL’s costs associated with obtaining RECs to fulfill its RPS obligations are recoverable from its distribution customers by law.

The legislation also establishes that the energy output from fuel cells manufactured in Delaware capable of running on renewable fuels is an eligible resource for RECs under the Renewable Portfolio Standards Act. The legislation requires that the DPSC adopt a tariff under which DPL would be an agent that collects payments from its customers and disburses the amounts collected to a qualified fuel cell provider that deploys Delaware-manufactured fuel cells as part of a 30-megawatt generation facility. The legislation also provides for a reduction in DPL’s REC and solar REC requirements based upon the actual energy output of the 30-megawatt generation facility. In October 2011, the DPSC approved the tariff submitted by DPL in response to the legislation. For more information on the tariff, see Note (2), “Significant Accounting Policies – Consolidation of Variable Interest Entities – DPL Renewable Energy Transactions,” to the consolidated financial statements of PHI.

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NERC Reliability Standards

NERC has 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. There are eight NERC regional oversight entities, including ReliabilityFirst Corporation (RFC), of which Pepco, DPL, ACE and Pepco Energy Services are members, and Northeast Power Coordinating Council (NPCC), of which Pepco Energy Services is a member. These oversight entities are charged with the day-to-day implementation and enforcement of NERC’s reliability standards, which impose certain operating, planning and cyber security requirements on the bulk power systems of Pepco, DPL, ACE and Pepco Energy Services. RFC and NPCC perform compliance audits on entities registered with NERC based on reliability standards and criteria established by NERC. NERC, RFC and NPCC also conduct compliance investigations in response to a system disturbance, complaint, or possible violation of a reliability standard identified by other means. Each of PHI’s utility subsidiaries and Pepco Energy Services are subject to routine audits and monitoring for compliance with applicable NERC reliability standards, including standards requested by FERC to increase the number of assets designated as “critical assets” (including cyber security assets) subject to NERC’s cyber security standards. NERC is empowered to impose financial penalties, fines and other sanctions for non-compliance with certain rules and regulations.

Employees

At December 31, 2011, PHI had the following number of employees:

			In Collective Bargaining Agreements
	Non-union		International Brotherhood of Electrical Workers		International Union of Operating Engineers		Other		Total
Pepco		354		1,094		—		—		1,448
DPL		228		688		—		—		916
ACE		174		384		—		—		558
Pepco Energy Services		273		199		56		27		555
PHI Service Company and Other		1,261		366		—		—		1,627
Total PHI Employees		2,290		2,731		56		27		5,104

PHI’s subsidiaries are parties to five collective bargaining agreements with four local unions. All five collective bargaining agreements will expire within the next four years, including one agreement that will expire on June 1, 2012. Collective bargaining agreements are generally renegotiated every three to five years.

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 (17), “Commitments and Contingencies – Environmental Matters – Conectiv Energy Wholesale Power Generation Sites,” to the consolidated financial statements of PHI.

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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 $6 million in 2012 and $3 million in each of 2013, 2014 and 2015. This projection 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 the Conectiv Energy wholesale power generation business in 2010, PHI is no longer subject to environmental regulations prospectively applicable to electricity generating facilities, except insofar as such regulations affect the operation of the two generating facilities located in the District of Columbia owned by Pepco Energy Services. Moreover, PHI anticipates that these regulations will cease to apply to PHI electricity generating facilities altogether after May 2012, assuming the two generating facilities are deactivated by Pepco Energy Services as planned.

Air Quality Regulation

The generating facilities owned by Pepco Energy Services are subject to federal, state and local laws and regulations, including the Federal Clean Air Act, which limit emissions of air pollutants, require permits for operation of facilities and impose recordkeeping and reporting requirements.

Sulfur Dioxide and Nitrogen Oxide Emissions

The acid rain provisions of the Clean Air Act regulate total Sulfur dioxide (SO₂) emissions from affected generating units and allocate “allowances” to each affected unit that permit the unit to emit a specified amount of SO₂. The generating facilities of Pepco Energy Services that require allowances use allocated allowances or allowances acquired, as necessary, in the open market to satisfy the applicable regulatory requirements.

In 2005, the U.S. Environmental Protection Agency (EPA) issued the Clean Air Interstate Rule (CAIR), which imposes further reductions of SO₂ and limits nitrogen oxide (NOx) emissions from electric generating units in 28 eastern states and the District of Columbia. CAIR uses an allowance system to cap state-wide emissions (and emissions within the District of Columbia) of SO₂ (using acid rain allowances) and NOx allowances, as described below, in two stages. NOx reductions were required beginning in 2009 and SO₂ reductions were required beginning in 2010. States and the District of Columbia may implement CAIR by adopting EPA’s trading program or through adopting regulations that at a minimum achieve the level of reductions that would otherwise be achieved through implementation of EPA’s trading program. Pepco Energy Services Buzzard Point generating units and its landfill gas generating units produce fewer megawatts than CAIR’s applicability threshold and therefore are not subject to CAIR.

Each state covered by CAIR and the District of Columbia may determine independently which emission sources to control and which control measures to adopt. CAIR includes model rules for multi-state cap and trade programs for power plants that states may choose to adopt to meet the required emissions reductions. In the District of Columbia, the Pepco Energy Services’ Benning Road units are permitted to satisfy the CAIR requirements through the use of allocated allowances or allowances acquired in the open market, through the installation of pollution control devices or through fuel modifications. The Benning Road units use NOx annual, NOx ozone season and SO₂ allowances allocated or acquired, as necessary, in the open market to comply with CAIR.

In July 2011, EPA adopted new regulations to replace CAIR, which address transport of air pollution across state boundaries. The Cross-State Air Pollution Rule (CSAPR) imposes stricter limits on SO₂ and NOx (annual and ozone season) than CAIR; however, the District of Columbia was in the group of jurisdictions excluded from the SO₂, NOx, and seasonal NOx under CSAPR. As a result, CSAPR’s Cap and Trade program, which was originally planned to go into effect on January 1, 2012, is not applicable to Pepco Energy Services.

On December 30, 2011, the District of Columbia Circuit Court of Appeals ruled to stay the CSAPR, and ordered EPA to continue enforcing CAIR. Consequently, Pepco Energy Services must continue to meet its CAIR obligations until after the court resolves petitions for review of CSAPR.

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Federal Regional Haze Rule

The federal Regional Haze Rule was adopted by EPA to address a type of visibility impairment known as regional haze created by the emission of specified pollutants by certain types of large stationary sources. The regulation requires installation of best available retrofit technology (BART) to boilers that (i) emit 250 tons or more per year of a visibility-impairing air pollutant, (ii) were placed in service between 1962 and 1977, and (iii) may reasonably be anticipated to cause or contribute to visibility impairment in any federally protected park or wilderness area. Pepco Energy Services’ Benning Road generating units are subject to this regulation for particulate matter less than ten microns in diameter and for SO₂ and NOx to the extent not addressed by CAIR. Under Pepco Energy Services’ current operating permit issued by the DDOE, the Benning Road generating units will not be required to implement any remedial actions if the facilities are shut down on or before December 17, 2012, which is Pepco Energy Services’ current plan.

Pepco Energy Services’ other generating units, including those at Buzzard Point, are not subject to the Regional Haze Rule.

Hazardous Air Pollutant Emissions

In December 2011, EPA finalized a rule to reduce the emission of toxic air pollutants from generating facilities. The Mercury and Air Toxics Standards will reduce emissions of heavy metals, including mercury, arsenic, chromium and nickel, as well as emissions of acid gases, including hydrochloric and hydrofluoric acid. Because existing generating sources generally have up to four years from the Standards’ effective date to comply with the Mercury and Air Toxics Standards, this rule is not expected to impact the Benning Road or Buzzard Point generating facilities, which are expected to be retired by May 2012.

Greenhouse Gas Emissions Reporting

In October 2009, 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:

• Pepco Energy Services reports CO₂, methane and nitrous oxide for its Benning Road units. No changes or restrictions on operations will occur as a result of this rule.

• DPL currently reports 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 distributes to its customers. Beginning in September 2012, DPL will be required to report fugitive CO₂ and methane emissions for its gas distribution operations for the previous calendar year (hence, the 2012 report will contain data from calendar year 2011). DPL’s liquefied natural gas storage facility does not meet the reporting threshold (25,000 metric tons) for fugitive emissions.

• ACE, DPL and Pepco will be required to start reporting sulfur hexafluoride emissions from electrical equipment beginning in September 2012, for the previous calendar year.

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Water Quality Regulation

Clean Water Act

Provisions of the federal Water Pollution Control Act, also known as the Clean Water Act, establish the basic legal structure for regulating the discharge of pollutants from point sources 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 (generally a confined, discrete conveyance such as a pipe) obtain a National Pollutant Discharge Elimination System (NPDES) permit issued by EPA or by a state agency under a federally authorized state program. The Benning Road facility has a NPDES permit authorizing pollutant discharges, which is subject to periodic renewal.

Pepco and a subsidiary of Pepco Energy Services discharge water from the Benning Road electric generating plant and service center located in the District of Columbia under a NPDES permit issued by EPA in July 2009. The permit imposes compliance monitoring and storm water best management practices to satisfy the District of Columbia’s Total Maximum Daily Load standards for polychlorinated biphenyls (PCBs), oil and grease, metals and other substances. As required by the permit, Pepco has initiated studies to identify the source of the regulated substances to determine appropriate best management practices for minimizing the presence of the substances in storm water. The initial study reports are scheduled for completion in March 2012 and will be submitted to EPA as required. The capital expenditures, if any, that may be needed to implement best management practices to satisfy these new permit conditions will not be known until the results of the studies are reviewed by EPA.

New Jersey Flood Hazard Area Control Act

In November 2007, the New Jersey Department of Environmental Protection adopted amendments to the agency’s regulations under the Flood Hazard Area Control Act the (FHACA) to minimize damage to life and property from flooding caused by development in flood plains. The amended regulations impose a new regulatory program to mitigate flooding and related environmental impacts from a broad range of construction and development activities, including electric utility transmission and distribution construction, which were previously unregulated under the FHACA. These regulations impose restrictions on construction of new electric transmission and distribution facilities and increase the time and personnel resources required to obtain permits and conduct maintenance activities. While ACE continues to evaluate the financial impact related to compliance with the amended regulations, based on current information, PHI and ACE do not believe these regulations will have a material adverse effect on their respective financial conditions or results of operations.

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 Plans (SPCC) 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. ACE, DPL and Pepco are complying with the SPCC regulations by employing containment/diversionary structures and by means of inspection and monitoring measures, in each case where such measures have been determined to be appropriate. Total costs in 2011 to Pepco, DPL and ACE were approximately $5 million, $1 million and $2 million, respectively, as of December 31, 2011 and each utility expects to incur ongoing costs to comply with the SPCC regulations. In addition to the costs to comply with EPA’s oil pollution prevention regulations, PHI companies project expenditures of approximately $11 million over four years to replace certain oil-filled breakers with gas-filled breakers to eliminate the possibility of an oil release from such equipment. Compliance costs for Pepco Energy Services have not been material, and PHI does not expect that they will become material in the foreseeable future.

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Hazardous Substance Regulation

The Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) of 1980 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. Pepco, DPL and ACE each has been named by EPA or a state environmental agency as a potentially responsible party in pending proceedings involving certain contaminated sites. See (i) Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity – Capital Requirements – Environmental Remediation Obligations,” and (ii) Note (17), “Commitments and Contingencies – Environmental Matters,” to the consolidated financial statements of PHI.

Executive Officers of PHI

The names of the executive officers of PHI, their ages and the positions they held as of February 23, 2012, are set forth in the following table. The business experience of each executive officer during 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		55	Chairman of the Board 5/09 - Present, President 3/08 - Present, and Chief Executive Officer 3/09 - Present (1)
David M. Velazquez		52	Executive Vice President 3/09 - Present (2)
Kirk J. Emge		62	Senior Vice President and General Counsel 3/08 - Present (3)
Anthony J. Kamerick		64	Senior Vice President and Chief Financial Officer 6/09 - Present (4)
Beverly L. Perry		64	Senior Vice President 10/02 - Present
Ronald K. Clark		56	Vice President and Controller 8/05 - Present
Ernest L. Jenkins		57	Vice President 5/05 – Present
Laura L. Monica		55	Vice President 8/11 – Present (5)
Hallie M. Reese		48	Vice President, PHI Service Company 5/05 - Present
John U. Huffman		52	President 6/06 - Present, and Chief Executive Officer, Pepco Energy Services, Inc. 3/09 - Present (6)

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(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 ACE, DPL and Pepco from September 1, 2007 to February 28, 2009. Mr. Rigby has been Chairman of Pepco, DPL and ACE since March 1, 2009.

(2) Mr. Velazquez served as President of Conectiv Energy Holding Company, 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. He served as a Vice President of PHI from February 2005 to June 2006 and as Chief Risk Officer of PHI from August 2005 to June 2006.

(3) Mr. Emge was Vice President, Legal Services of PHI from August 2002 until March 2008. Mr. Emge has served as General Counsel of ACE, DPL and Pepco since August 2002 and as Senior Vice President of Pepco and DPL since March 1, 2009.

(4) Mr. Kamerick was Senior Vice President and Chief Regulatory Officer of PHI from March 2009 until June 2009. Mr. Kamerick was Vice President and Treasurer of PHI from August 2002 until February 28, 2009.

(5) From October 2006 to October 2010, Ms. Monica was Senior Vice President, Corporate Communications at American Water Works Company (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.

(6) 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.

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 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.

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PHI utility subsidiaries are subject to comprehensive regulation which may significantly affect 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 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 disallowances for failing to meet those objectives. The MPSC also stated that it would consider in Pepco’s pending Maryland retail base rate case the potential disallowance of costs which may be determined to have been imprudently incurred.

NERC’s eight regional oversight entities, including RFC, of which Pepco, DPL, ACE and Pepco Energy Services are members, and NPCC, of which Pepco Energy Services is a member, are charged with the day-to-day implementation and enforcement of NERC’s standards. RFC and NPCC perform compliance audits on entities registered with NERC based on reliability standards and criteria established by NERC. NERC, RFC 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 RFC resolving alleged violations and resulting in fines. There can be no assurance that additional settlements resolving issues related to RFC 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.

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 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 to obtain timely recognition of costs in its rates may have a negative effect on PHI’s results of operations and financial condition.

The public service commissions which regulate PHI’s utility subsidiaries establish utility rates and tariffs intended to provide the 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, ACE and DPL recover from their customers purchased power and natural gas

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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.

PHI’s utility subsidiaries are also exposed to “regulatory lag,” which refers to a shortfall in revenues 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 investment in the rate base and their operating expenses are outpacing revenue growth. PHI anticipates that this trend will continue for the foreseeable future. The failure to timely recognize costs in rates could have a material adverse effect on PHI’s and each utility subsidiary’s business, results of operations, cash flow and financial condition.

In their most recent rate cases, Pepco (in the District of Columbia and Maryland), DPL (in Maryland and Delaware) and ACE (in New Jersey) have proposed mechanisms that would track reliability and other expenses and permit each utility to make adjustments in its approved rates to account for prudent investments as made, thereby seeking to reduce the magnitude of regulatory lag. In New Jersey, the NJBPU has previously approved a similar mechanism, and ACE currently has an update and expansion of that previously approved mechanism pending before the NJPBU. There can be no assurance that these proposals or any attempts by Pepco, DPL and ACE to mitigate regulatory lag will be approved, or that even if approved, the rate recovery mechanisms will fully ameliorate the effects of regulatory lag. If necessary to address in whole or in part the problem of regulatory lag, each utility can file base rate cases annually (or even more frequently) to seek to align its revenue and related cash flow levels allowed by the applicable public service commissions with operation and maintenance spending and capital investments. The inability of PHI’s utility subsidiaries to obtain relief from the impact of regulatory lag through base rate cases or otherwise may have an adverse effect on the business, results of operations, cash flow and financial condition of PHI and each utility subsidiary.

The operating results of Power Delivery and the retail energy supply business of Pepco Energy Services 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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The retail energy supply business of Pepco Energy Services generally produces higher gross margins when temperatures are colder than normal in winter or warmer than normal in summer, and less gross margin when weather conditions are milder than normal. The energy services business of Pepco Energy Services, which includes providing energy savings performance contracting services principally to federal, state and local government customers, and designing, constructing and operating combined heat and power energy plants for customers, is not seasonal.

Facilities 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 involves many risks, including the breakdown or failure of equipment, accidents, labor disputes, theft of copper wire or pipe, scams, failure of software or hardware, and performance below expected levels. Older facilities 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, which seek to capitalize on the current high market price of copper, 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 can reduce revenues and result in the incurrence of additional expenses that may not be recoverable from customers or through insurance.

PHI’s Blueprint for the Future program includes the replacement of customers’ existing electric and gas meters with an AMI system. In addition to the replacement of existing meters, the AMI system involves the construction of a wireless network across the service territories of PHI’s utility subsidiaries and the implementation and integration of new and existing information technology systems to collect and manage data made available by the advanced meters. The implementation of the AMI system involves a combination of technologies provided by multiple vendors. If the AMI system results in lower than projected performance, PHI’s utility subsidiaries could experience higher than anticipated maintenance expenditures.

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, 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 or increased regulatory oversight. Unfavorable regulatory outcomes can include 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.

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Unfavorable regulatory developments and compliance with new or enhanced regulatory requirements will 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 December 2011, the MPSC approved proposed rules establishing reliability and customer service regulations, compliance with which is anticipated to be mandated as early as the second quarter of 2012. 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 thereafter and are intended to require Pepco to achieve a reliability level in the first quartile of all utilities in the nation by 2020. Pepco believes that the DCPSC’s standards are achievable in the short term, but continues to believe that the standards may not be realistically achievable at an acceptable cost over the longer term. 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 expect that it will have to incur significant operating and maintenance and capital expenses to comply with these requirements. Furthermore, each of Pepco and DPL would 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 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.

The transmission facilities of Power Delivery 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 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 and conservation measures may adversely affect Power Delivery.

Increased conservation and end-user generation made possible through advances in technology could reduce demand for the transmission and distribution facilities of Power Delivery and adversely affect PHI and one or more of its utility subsidiaries. Alternative technologies to produce electricity, the development of which has expanded due to climate change and other environmental concerns, could ultimately provide alternative sources of electricity. As these new technologies are developed and

become available, the quantity and pattern 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.

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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 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.

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.

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. 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, 2011, 55% of employees of PHI and its subsidiaries, collectively, were represented by various labor unions. PHI’s subsidiaries are parties to five collective bargaining agreements with four local unions that represent these employees. All five collective bargaining agreements will expire within the next four years, including one agreement that expires on June 1, 2012. 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. PHI’s last work stoppage, a two-week strike by DPL’s employees, occurred in 2010. During that strike, DPL used management and contractor employees to maintain essential operations. Though PHI believes that a protracted work stoppage is 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 PHI and the affected utility.

The energy services business of Pepco Energy Services is highly competitive. (PHI only)

Unlike PHI’s regulated business, Pepco Energy Services’ business is highly competitive and is not assured a rate of return on capital investments through a predetermined rate structure. This competition generally has the effect of limiting margins and requiring a continual focus on controlling costs. The energy services business is impacted by new entrants into the market, energy prices, and general economic conditions. These factors may negatively impact Pepco Energy Services’ ability to market its services to new customers, or renew existing contracts, as well as the prices Pepco Energy Services may charge.

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Among the factors on which the energy services business competes are the amount and duration of the guarantees provided in energy savings performance contracts. In connection with many of its energy efficiency installation projects, Pepco Energy Services guarantees a minimum level of annual energy cost savings over a period typically ranging up to 15 years. Currently, Pepco Energy Services does not insure against this risk, and accordingly could suffer financial losses if a project does not achieve the guaranteed level of performance.

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 adversely affect PHI’s results of operations, cash flow and financial condition.

The inability of Pepco Energy Services to perform its obligations in connection with its energy services construction projects may have a material adverse effect on PHI. (PHI only)

Projects undertaken by Pepco Energy Services include design, construction, startup and testing activities related to combined heat and power and other energy facilities, 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. Ultimately, however, Pepco Energy Services will bear responsibility in the event of unexcused failures by these subcontractors and vendors, as well as other third parties, to perform in accordance with the terms of these contracts or otherwise pursuant to the expectations of the parties. If such events occur, Pepco Energy Services could experience reputational harm and claims for money damages and other relief, which could, depending upon the cause and severity of the failure of performance, adversely affect PHI’s business, results of operations, cash flow and financial condition.

Pepco Energy Services relies on generation, transmission, storage and distribution assets that it does not own or control to deliver electricity and natural gas to its customers and to obtain the fuel required to operate its generating facilities. (PHI only)

Pepco Energy Services is dependent on electric generating and transmission facilities, natural gas pipelines and natural gas storage facilities owned and operated by others to fulfill the remaining contractual obligations of its retail energy supply business. A disruption in the operation of these facilities or the inefficient operation of these facilities would have an adverse effect on Pepco Energy Services.

The operation of Pepco Energy Services’ generating facilities depends on fuel supplied by others. If the fuel supply to these generating facilities was to be disrupted and storage or other sources of supply were not available, the ability of Pepco Energy Services to operate its plants would be adversely affected.

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:

• risks related to recovery of capital and operating costs;

• resource planning and other long-term planning risks, including resource acquisition risks;

• financial risks, including credit, interest rate and capital market risks; and

• macroeconomic risks, including risks related to economic conditions and changes in demand for electricity and natural gas in the service territories of PHI’s utility subsidiaries, as well as with respect to Pepco Energy Services’ 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 Audit Committee oversee the assessment, management and mitigation of risk. However, there can be no assurance these risk mitigation efforts will adequately address all such risks.

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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. For example, Pepco Energy Services has entered into commercial transactions for the purchase and sale of electricity and natural gas, as well as derivative and other transactions to manage the risk of commodity price fluctuations. Under these arrangements, Pepco Energy Services is exposed to the risk that the counterparty may fail to perform its obligation to make or take delivery under the contract, fail to make a required payment or fail to return collateral posted by Pepco Energy Services when the counterparty is required to do so. In addition, PHI’s PCI subsidiary has entered into several cross-border energy lease investments located outside the United States. Under these leases, PCI is exposed to the risk that the counterparty may fail to make lease payments on time or at all.

Many of these contracts provide for PHI or a subsidiary to receive collateral or other types of performance assurance from the counterparty, 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 can prevent the counterparty from meeting its collateral obligations or degrade the value of letters of credit and guarantees as a result of the lowered rating or insolvency of the issuer or guarantor. 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 held or payments received. In the case of PCI, the fact that the counterparties are located outside the United States could make it more difficult for PCI to seek redress or obtain a judgment or compensation against a foreign counterparty for any breach of the lease agreement by that counterparty.

The retail energy supply business of Pepco Energy Services can give rise to significant collateral requirements. (PHI only)

In conducting its retail energy supply business, Pepco Energy Services has entered into electricity or natural gas supply agreements and wholesale purchase contracts for electricity and natural gas that typically impose collateral requirements on each party. The collateral requirements are designed to protect the other party against the risk of nonperformance between the date the contract was entered into and the date of payment for the energy. When energy market prices decrease relative to the supplier contract prices, Pepco Energy Services’ collateral obligations increase. While Pepco Energy Services is no longer entering into new energy supply contracts, it has continuing supply obligations based on existing contracts and corresponding wholesale purchase contracts that extend through 2014. Particularly in periods of energy market price volatility, the collateral obligations associated with these wholesale purchase contracts can be substantial, although they can be expected to diminish as the retail energy supply business is wound down. These collateral demands could negatively affect PHI’s liquidity by requiring PHI to draw on its capacity under its primary credit facility or other financing sources.

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

The threat of, or actual acts of, terrorism 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 Pepco’s, DPL’s or ACE’s infrastructure facilities, including their transmission or distribution facilities, were to be a direct target, or an indirect casualty, of an act of terrorism, the operations of PHI, Pepco, DPL or ACE could be adversely affected. Furthermore, any threats or actions that negatively impact the physical security of PHI’s and its subsidiaries’ facilities, or the integrity or security of their computer networks and systems (and any programs or data stored thereon or therein), could adversely affect PHI’s and its subsidiaries’ ability 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. 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.

Mark-to-market accounting treatment for instruments Pepco Energy Services uses to hedge the cost of supply used to satisfy retail customer load obligations could cause earnings volatility. (PHI only)

Pepco Energy Services purchases energy commodity contracts in the form of electricity and natural gas futures, swaps, options and forward contracts to hedge commodity price risk in connection with the purchase of natural gas and electricity for delivery to customers. Certain commodity contracts that do not qualify as cash flow hedges of forecasted transactions or do not meet the requirements for normal purchase and normal sale accounting are marked to market through current earnings. Any change in the fair value of the transactions used to hedge price risk that receive mark-to-market accounting treatment will be reflected in PHI’s current earnings without any offsetting change in the fair value of its retail load obligations until the settlement date of these contracts in future periods. As a result, PHI’s earnings could be more volatile due to the mark-to-market accounting treatment associated with these commodity contracts. As of December 31, 2011, the commodity contracts that Pepco Energy Services currently accounts for on an accrual basis (because they are designated as normal purchases or normal sales) are, on a fair value basis, in a significant net loss position. If PHI could no longer sustain the normal purchase and normal sale designation for these contracts, it would be required to recognize these net losses in earnings, which could result in greater earnings volatility.

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 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.

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Each Reporting Company’s financial statements, including their reported earnings, could be significantly impacted by convergence of GAAP with International Financial Reporting Standards (IFRS).

The FASB is expected to make broad changes to GAAP as part of an overall initiative to converge GAAP with IFRS. These changes could have significant impacts on the financial statements of each Reporting Company. Also, the SEC is considering incorporating IFRS into the financial reporting system for U.S. public companies. A transition to IFRS could significantly impact each Reporting Company’s financial results, since these standards differ from GAAP in many ways. One of the major differences is the lack of special accounting treatment for regulated activities under IFRS, which could result in greater earnings volatility for each Reporting Company.

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, laws and regulations, taxation requirements and federal securities laws and regulations 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 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 or property losses that the companies might incur.

PHI and its subsidiaries, including Pepco, DPL and ACE, 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, such as weather related casualties, may not be insurable. In the case of loss or damage to property, plant or equipment, there is no assurance that the insurance proceeds received, if any, will be sufficient to cover the entire cost of replacement or repair.

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The Internal Revenue Service (IRS) challenge to cross-border energy sale and lease-back transactions entered into by a PHI subsidiary could result in loss of prior and future tax benefits. (PHI only)

PCI maintains a portfolio of seven cross-border energy lease investments, which as of December 31, 2011, had an equity value of approximately $1.3 billion and from which PHI currently derives approximately $51 million per year in tax benefits in the form of interest and depreciation deductions in excess of rental income. PHI’s cross-border energy lease investments, each of which is with a tax-indifferent party, have been under examination by the IRS as part of the normal PHI federal income tax audits. In the final IRS revenue agent’s report in connection with the audits of PHI’s federal income tax returns from 2001 to 2005, the IRS disallowed the depreciation and interest deductions in excess of rental income claimed by PHI with respect to its cross-border energy lease investments. In addition, the IRS has sought to recharacterize the leases as loan transactions as to which PHI would be subject to original issue discount income. PHI disagrees with the IRS’ proposed adjustments and filed tax protests.

Effective November 2010, PHI entered into a settlement agreement with the IRS for the 2001 and 2002 tax years 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. PHI’s claim for refund for the disallowed deductions was denied by the IRS and PHI has filed suit against the IRS in the U.S. Court of Federal Claims to recover payments made. The case with respect to the 2003 to 2005 returns is currently pending with the IRS Office of Appeals.

In the event that the IRS were to be successful in disallowing 100% of the tax benefits associated with these leases and recharacterizing these leases as loans, PHI estimates that, as of December 31, 2011, it would be obligated to pay approximately $643 million in additional federal and state taxes and $121 million of interest, of which $74 million has been satisfied by the payment made in January 2011. In addition, the IRS could require PHI to pay a penalty of up to 20% on the amount of additional taxes due. PHI anticipates that any additional taxes that it would be required to pay as a result of the disallowance of prior deductions or a re-characterization of the leases as loans would be recoverable in the form of lower taxes over the remaining terms of the affected leases. Moreover, the entire amount of any additional tax would not be due immediately. Rather, the federal and state taxes would be payable when the open audit years are closed and PHI amends subsequent tax returns not then under audit.

To the extent that PHI does not prevail in this matter and suffers a disallowance of the tax benefits and incurs imputed original issue discount income due to the recharacterization of the leases as loans, PHI would be required under Financial Accounting Standards Board guidance on leases (Accounting Standards Codification (ASC) 840) to recalculate the timing of the tax benefits generated by the cross-border energy lease investments and adjust the equity value of the investments, which would result in a non-cash charge to earnings that could be material.

For further discussion of this matter, see Note (17), “Commitments and Contingencies – PHI’s Cross-Border Energy Lease Investments,” to the consolidated financial statements of PHI.

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

PHI, Pepco, DPL and ACE each have significant capital requirements, including the funding of construction expenditures and the refinancing of maturing debt. These companies rely primarily on cash flow from operations and access to the capital markets to meet these financing needs. The operating activities of PHI and its subsidiaries also require access to short-term money markets and bank financing

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as sources of liquidity that are not met by cash flow 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 one or more financial markets. 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 terrorist 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 PHI, Pepco, DPL and ACE, and debt securities issued by Pepco, DPL and ACE. Ratings are not recommendations to buy or sell securities. PHI or its 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 PHI, Pepco, DPL or ACE under review for potential downgrade in certain circumstances or if any of them seek to take certain actions. 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 collateral requirements of Pepco Energy Services’ retail energy supply business also are determined in part by the unsecured debt rating of PHI. Negative ratings actions by one or more of the credit rating agencies resulting from a change in PHI’s or the utility’s operating results or prospects would increase funding costs. Any increases in collateral requirements could make such contractual obligations more expensive and make financing more difficult to obtain.

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 each 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 the affected 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, a further write-down of PHI’s 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 restrictions on its ability to operate its business in its sole discretion could harm 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.

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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 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 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 equity securities issued by PHI or to make any funds available for such payment. 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 48% 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.

Further delays in the current in-service date for the MAPP project or the suspension or cancellation of this project could hinder PHI’s future revenue growth. (PHI, Pepco and DPL)

In 2007, PJM directed PHI and its utility subsidiaries to construct MAPP to address future potential violations of national and regional standards for reliable operation of the region’s transmission system. On August 18, 2011, PJM notified PHI that it has delayed the scheduled in-service date for MAPP from June 1, 2015 to the 2019 to 2021 time period, after taking into account changes in the demand response, generation retirements and additions, and a revised load forecast for the PJM region that was lower than forecasted in prior PJM studies. A more recent load forecast continues to support this load forecast trend. PJM is currently evaluating the exact in-service date as part of its 2012 Regional Transmission Expansion Plan review process. In the interim, the delay of the in-service date will defer a substantial portion of the transmission revenue that PHI expects to earn from the MAPP project, which is anticipated to generate higher rates of return on equity than most of PHI’s other existing transmission assets. Depending on the conclusions reached in its 2012 evaluation, PJM may further delay the required in-service date for the MAPP project or suspend or cancel the project altogether. Although PHI intends to substitute alternative transmission projects for MAPP based on the delay in the MAPP in service date, PHI may not be able to achieve an equal or higher rate of return on these alternative projects as has been approved under the MAPP project.

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, 2011, of approximately $1.4 billion, primarily attributable to Pepco’s acquisition of 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 a decline in PHI’s stock price causing market capitalization to fall below book value, an adverse change in business conditions or an adverse regulatory action. 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 and results of operations, but would not have an impact on cash flow.

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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 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 postretirement 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 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 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 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 postretirement 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.

Section 203 could prohibit or delay mergers or other takeover attempts against PHI, and accordingly, may discourage or prevent attempts to acquire PHI through a tender offer, proxy contest or otherwise.

In addition, 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. 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

36

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. 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, PHI can exercise substantial control over their dividend policies and businesses and operations. (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. Among other decisions, each of Pepco’s, DPL’s and ACE’s board 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 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.

Item 1B. UNRESOLVED STAFF COMMENTS

Pepco Holdings

None.

Pepco

None.

DPL

None.

ACE

None.

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Item 2. PROPERTIES

Generating Facilities

The following table identifies the electric generating facilities owned by PHI’s subsidiaries at December 31, 2011.

Electric Generating Facilities	Location	Owner	Generating Capacity (kilowatts)
Oil Fired Units
Benning Road (a)	Washington, DC	Pepco Energy Services		550,000
Combustion Turbines/Combined Cycle Units
Buzzard Point (a)	Washington, DC	Pepco Energy Services		240,000
Landfill Gas-Fired Units
Fauquier Landfill Project	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
Total Electric Generating Capacity				802,000
(a)     PHI intends to deactivate these facilities by the end of May 2012.

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.

Transmission and Distribution Systems

On a combined basis, the electric transmission and distribution systems owned by Pepco, DPL and ACE at December 31, 2011, consisted of approximately 3,900 transmission circuit miles of overhead lines, 460 transmission circuit miles of underground cables, 18,400 distribution circuit miles of overhead lines, and 16,200 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 3 million gallons and an emergency sendout capability of 25,000 Mcf per day. DPL owns 10 natural gas city gate stations at various locations in New Castle County, Delaware. These stations have a total primary delivery point contractual entitlement of 204,075 Mcf per day. DPL also owns approximately 104 pipeline miles of natural gas transmission mains, 1,912 pipeline miles of natural gas distribution mains, and 1,309 natural gas pipeline miles of service lines. In addition, DPL has a 10% undivided interest in approximately 7 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.

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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 (11), “Debt” to the consolidated financial statements of PHI.

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 (17), “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 (13), “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 (15), “Commitments and Contingencies,” to the financial statements of DPL.

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 (14), “Commitments and Contingencies,” to the consolidated financial statements of ACE.

Item 4. MINE SAFETY DISCLOSURES

Not applicable

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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		Price Range
Period	Per Share		High		Low
2011:
First Quarter	$	.27	$	19.14	$	17.83
Second Quarter		.27		20.36		18.10
Third Quarter		.27		20.04		16.57
Fourth Quarter		.27		20.64		17.77
	$	1.08
2010:
First Quarter	$	.27	$	17.57	$	15.74
Second Quarter		.27		17.78		15.13
Third Quarter		.27		18.92		15.40
Fourth Quarter		.27		19.80		18.01
	$	1.08

At February 15, 2012, there were 52,667 registered holders of record of Pepco Holdings common stock.

Dividends

On January 26, 2012, the PHI Board of Directors declared a dividend on common stock of 27 cents per share payable March 30, 2012, to shareholders of record on March 12, 2012.

See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Resources and Liquidity — Capital Requirements — Dividends,” and Note (14), “Stock-Based Compensation, Dividend Restrictions, and Calculations of Earnings Per Share of Common Stock — Dividend Restrictions,” 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 48%-50% in each of its operating utilities. Each quarter, PHI may contribute equity into its utility subsidiaries or the utility subsidiaries may make a dividend payment to PHI in order to maintain an equity ratio of 48%-50% in each of the utility subsidiaries.

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Pepco

All of Pepco’s common stock is held by Pepco Holdings. The table below presents the aggregate amount of common stock dividends paid by Pepco to PHI during each quarter in the last two years. Dividends received by PHI in 2011 and 2010 were used to support the payment of its common stock dividend.

Period	Aggregate Dividends
2011:
First Quarter	$	—
Second Quarter		—
Third Quarter		—
Fourth Quarter		25,000,000
	$	25,000,000
2010:
First Quarter	$	25,000,000
Second Quarter		25,000,000
Third Quarter		45,000,000
Fourth Quarter		20,000,000
	$	115,000,000

DPL

All of DPL’s common stock is held by Conectiv, LLC (Conectiv). The table below presents the aggregate amount of common stock dividends paid by DPL to Conectiv during each quarter in the last two years. Dividends received by Conectiv in 2011 and 2010 were passed through to PHI to support the payment of its common stock dividend.

Period	Aggregate Dividends
2011:
First Quarter	$	—
Second Quarter		—
Third Quarter		50,000,000
Fourth Quarter		10,000,000
	$	60,000,000
2010:
First Quarter	$	—
Second Quarter		23,000,000
Third Quarter		—
Fourth Quarter		—
	$	23,000,000

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ACE

All of ACE’s common stock is held by Conectiv. The table below presents the aggregate amount of common stock dividends paid by ACE to Conectiv during each quarter in the last two years. Dividends received by Conectiv in 2010 were used to pay down short-term debt owed to PHI.

Period	Aggregate Dividends
2011:
First Quarter	$	—
Second Quarter		—
Third Quarter		—
Fourth Quarter		—
	$	—
2010:
First Quarter	$	—
Second Quarter		—
Third Quarter		—
Fourth Quarter		35,000,000
	$	35,000,000

Recent Sales of Unregistered Equity Securities

Pepco Holdings

None.

Pepco

None.

DPL

None.

ACE

None.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

Pepco Holdings

None.

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 the years ended December 31, 2011, 2010, 2009, 2008, and 2007, derived from PHI’s audited financial statements.

PEPCO HOLDINGS CONSOLIDATED FINANCIAL HIGHLIGHTS

	2011				2010					2009				2008				2007
		(in millions, except per share data)
Consolidated Operating Results
Total Operating Revenue	$	5,920			$	7,039				$	7,402			$	8,059	(h	)	$	7,613
Total Operating Expenses		5,283		(a)		6,415		(c	)		6,754	(f	)		7,510				6,953	(j	)
Operating Income		637				624					648				549				660
Other Expenses		228				474		(d	)		321				276				255
Preferred Stock Dividend Requirements of Subsidiaries		—				—					—				—				—
Income from Continuing Operations Before Income Tax Expense		409				150					327				273				405
Income Tax Expense Related to Continuing Operations		149		(b)		11		(e	)		104	(g	)		90	(h	)(i)		141	(k	)
Net Income from Continuing Operations		260				139					223				183				264
(Loss) Income from Discontinued Operations, net of Income Taxes		(3	)			(107	)				12				117				70
Net Income		257				32					235				300				334
Earnings Available for Common Stock		257				32					235				300				334
Common Stock Information
Basic Earnings Per Share of Common Stock from Continuing Operations	$	1.15			$	0.62				$	1.01			$	0.90			$	1.36
Basic (Loss) Earnings Per Share of Common Stock from Discontinued Operations		(0.01	)			(0.48	)				0.05				0.57				0.36
Basic Earnings Per Share of Common Stock		1.14				0.14					1.06				1.47				1.72
Diluted Earnings Per Share of Common Stock from Continuing Operations		1.15				0.62					1.01				0.90				1.36
Diluted (Loss) Earnings Per Share of Common Stock from Discontinued Operations		(0.01	)			(0.48	)				0.05				0.57				0.36
Diluted Earnings Per Share of Common Stock		1.14				0.14					1.06				1.47				1.72
Cash Dividends Per Share of Common Stock		1.08				1.08					1.08				1.08				1.04
Year-End Stock Price		20.30				18.25					16.85				17.76				29.33
Net Book Value Per Common Share		19.05				18.79					19.15				19.14				20.04
Weighted Average Shares Outstanding		226				224					221				204				194
Other Information
Investment in Property, Plant and Equipment	$	12,855			$	12,120				$	11,431			$	10,860			$	10,392
Net Investment in Property, Plant and Equipment		8,220				7,673					7,241				6,874				6,552
Total Assets		14,910				14,480					15,779				16,133				15,111
Capitalization
Short-term Debt	$	732			$	534				$	530			$	465			$	289
Long-term Debt		3,794				3,629					4,470				4,859				4,175
Current Portion of Long-Term Debt and Project Funding		112				75					536				85				332
Transition Bonds issued by ACE Funding		295				332					368				401				434
Capital Lease Obligations due within one year		8				8					7				6				6
Capital Lease Obligations		78				86					92				99				105
Long-Term Project Funding		13				15					17				19				21
Non-controlling Interest		—				6					6				6				6
Common Shareholders’ Equity		4,336				4,230					4,256				4,190				4,018
Total Capitalization	$	9,368			$	8,915				$	10,282			$	10,130			$	9,386

(a) Includes $39 million pre-tax ($3 million after-tax) gain from the early termination of certain cross-border energy leases held in trust.

(b) Includes tax benefits of $14 million primarily associated with an interest benefit related to federal tax liabilities and a $22 million reversal of previously recognized tax benefits associated with the early termination of cross-border energy leases held in trust.

(c) Includes $30 million ($18 million after-tax) related to a restructuring charge and an $11 million ($6 million after-tax) charge related to the effects of Pepco divestiture-related claims.

(d) Includes a loss on extinguishment of debt of $189 million ($113 million after-tax).

(e) Includes $12 million of net Federal and state income tax benefits primarily related to adjustments of accrued interest on uncertain and effectively settled tax positions, $14 million of state tax benefits resulting from the restructuring of certain PHI subsidiaries and $17 million of state income tax benefits associated with the loss on extinguishment of debt.

(f) Includes $40 million ($24 million after-tax) gain related to the effects of Pepco divestiture-related claims.

(g) Includes a $13 million state income tax benefit (after Federal tax) related to a change in the state income tax reporting for the disposition of certain assets in prior years and a benefit of $6 million related to additional analysis of current and deferred tax balances completed in 2009.

(h) Includes a pre-tax charge of $124 million ($86 million after-tax) related to the adjustment to the equity value of cross-border energy lease investments, and included in Income Taxes is a $7 million after-tax charge for the additional interest accrued on the related tax obligation.

(i) Includes $18 million of after-tax net interest income on uncertain and effectively settled tax positions (primarily associated with the reversal of previously accrued interest payable resulting from the tentative settlement with the IRS on the mixed service cost issue and a claim made with the IRS related to the tax reporting for fuel over- and under-recoveries) and a benefit of $8 million (including a $3 million correction of prior period errors) related to additional analysis of deferred tax balances completed in 2008.

(j) Includes $33 million ($20 million after-tax) from settlement of Mirant bankruptcy claims.

(k) Includes $20 million ($18 million net of fees) benefit related to Maryland income tax settlement.

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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 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	45
Pepco	95
DPL	105
ACE	116

44

PEPCO HOLDINGS

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 the distribution and supply of natural gas (Power Delivery). Through Pepco Energy Services, PHI provides energy efficiency services primarily to government and institutional customers and is in the process of winding down its competitive electricity and natural gas retail supply business. Each of Power Delivery and Pepco Energy Services constitutes a separate segment for financial reporting purposes. A third segment, Other Non-Regulated, owns a portfolio of seven cross-border energy lease investments.

The following table sets forth the percentage contributions to consolidated operating revenue and operating income from continuing operations attributable to the Power Delivery, Pepco Energy Services and Other Non-Regulated segments:

	December 31,
	2011			2010			2009
Percentage of Consolidated Operating Revenue
Power Delivery		79	%		73	%		67	%
Pepco Energy Services		21	%		27	%		32	%
Other Non-Regulated		—	%		—	%		1	%
Percentage of Consolidated Operating Income
Power Delivery		78	%		81	%		78	%
Pepco Energy Services		5	%		11	%		14	%
Other Non-Regulated		17	%		8	%		8	%
Percentage of Power Delivery Operating Revenue
Power Delivery Electric		95	%		95	%		95	%
Power Delivery Gas		5	%		5	%		5	%

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. Power Delivery represents a single operating segment for financial reporting purposes.

Each utility comprising Power Delivery is a regulated public utility in the jurisdictions that encompass its service territory. Each company is responsible for the distribution of electricity and, in the case of DPL, 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 company 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 SOS in Delaware, the District of Columbia and Maryland, and BGS in New Jersey. In this report, these supply service obligations are referred to generally as Default Electricity Supply.

Pepco, DPL and ACE are also responsible for the transmission of wholesale electricity into and across their service territories. The rates each company 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.

45

PEPCO HOLDINGS

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, energy prices and the impact of energy efficiency measures on customer usage of electricity.

In ACE and DPL’s Delaware service territories, 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 for customers of Pepco in the District of Columbia, revenue is not affected by season changes because a BSA was implemented for retail customers that provides for a fixed distribution charge per customer rather than a charge based upon 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 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. With respect to customers subject to a BSA, changes in usage (such as due to weather conditions, energy prices, energy efficiency programs or other reasons) from period to period have no impact on reported distribution revenue.

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 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.

The following are developments in some of the key initiatives of Power Delivery in 2011:

Reliability Enhancement and Emergency Restoration Improvement Plans

In 2010, PHI announced that Pepco had adopted and begun to implement comprehensive reliability enhancement plans in Maryland and the District of Columbia. These reliability enhancement plans include various initiatives to improve electrical system reliability, such as:

• enhanced vegetation management;

• the identification and upgrading of under-performing feeder lines;

• the addition of new facilities to support load;

• the installation of distribution automation systems on both the overhead and underground network system;

• the rejuvenation and replacement of underground residential cables;

• improvements to substation supply lines; and

• selective undergrounding of portions of existing above ground primary feeder lines, where appropriate to improve reliability.

During 2011, Pepco invested $120 million in capital expenditures on these reliability enhancement activities.

In 2011, prior to the start of the summer storm season, PHI initiated a program to improve Pepco’s emergency restoration efforts that included, among other initiatives, an expansion and enhancement of customer service capabilities.

PHI has extended its reliability enhancement efforts to DPL and ACE. PHI’s capital expenditures for continuing reliability enhancement efforts are included in the table of projected capital expenditures in the section titled “Capital Resources and Liquidity — Capital Expenditures.”

46

PEPCO HOLDINGS

Blueprint for the Future

Each of PHI’s three utilities is participating in a PHI initiative referred to as “Blueprint for the Future.” The installation of smart meters (also known as AMI), a key initiative of Blueprint for the Future, is almost complete for DPL electric customers in Delaware, with meter activation expected to be completed in the first quarter of 2012. Meter installation is still underway for Pepco customers in both the District of Columbia and Maryland, with installation of residential meters expected to be complete in the first and fourth quarters of 2012, respectively. The respective public service commissions have approved the creation of regulatory assets to defer AMI costs between rate cases, as well as the accrual of a return on the deferred costs. Thus, these costs will be recovered through base rates in the future. In addition to the replacement of existing meters, the AMI system involves the construction of a wireless network across the service territories of PHI’s utility subsidiaries and the implementation and integration of new and existing information technology systems to collect and manage data made available by the advanced meters. The implementation of the AMI system involves a combination of technologies provided by multiple vendors.

Approval of AMI is still pending for electric customers in DPL’s Maryland jurisdiction, and has been deferred in New Jersey.

In 2011, the DPSC approved DPL’s request to implement dynamic pricing for its Delaware customers. Implementation for customers will be phased in between 2012 and 2014. Dynamic pricing has been approved in concept, with phase-in for residential customers beginning in 2012 for Pepco customers in Maryland. Customers in Pepco’s District of Columbia jurisdiction have proposals pending with proposed phase-in for residential customers anticipated to begin in 2012. Dynamic pricing has been approved in concept pending AMI deployment authorization for DPL’s Maryland customers and has been deferred for ACE’s customers in New Jersey.

Regulatory Lag

An important factor in the ability of each of Pepco, DPL and ACE to earn its authorized rate of return is the willingness of applicable public service commissions to adequately recognize forward-looking costs in the utility’s rate structure in order to address the shortfall in revenues 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.” Each of Pepco, DPL and ACE is currently experiencing significant regulatory lag because their investment in the rate base and their operating expenses are outpacing revenue growth. PHI is continuing to seek cost recovery and tracking mechanisms from applicable public service commissions to reduce the effects of regulatory lag.

Pepco Energy Services

Pepco Energy Services is engaged in the following businesses:

• providing energy efficiency services principally to federal, state and local government customers, and designing, constructing and operating combined heat and power and central energy plants.

• providing high voltage electric construction and maintenance services to customers throughout the United States and low voltage electric construction and maintenance services and streetlight construction and asset management services to utilities, municipalities and other customers in the Washington, D.C. area.

47

PEPCO HOLDINGS

Pepco Energy Services also has been engaged in the business of providing retail energy supply services, consisting of the sale of electricity, including electricity from renewable resources, primarily to commercial, industrial and government customers located primarily in the mid-Atlantic and northeastern regions of the U.S., as well as Texas and Illinois, and the sale of natural gas to customers located primarily in the mid-Atlantic region. In December 2009, PHI announced that it will wind-down the retail energy supply component of the Pepco Energy Services business. The decision was made after considering, among other factors, the return PHI earns by investing capital in the retail energy supply business as compared to alternative investments.

To effectuate the wind-down, Pepco Energy Services will continue to fulfill all of its commercial and regulatory obligations and perform its customer service functions to ensure that it meets the needs of its existing customers, but will not be entering into any new retail energy supply contracts. Operating revenues related to the retail energy supply business for the years ended December 31, 2011, 2010 and 2009 were $0.9 billion, $1.6 billion and $2.3 billion, respectively, and operating income for the same periods was $11 million, $59 million and $88 million, respectively.

PHI expects the operating results of the retail energy supply business, excluding the effects of unrealized mark-to-market gains or losses on derivatives contracts, to be profitable in 2012, based on its existing retail contracts and its corresponding portfolio of wholesale hedges, with immaterial losses beyond that date. Substantially all of Pepco Energy Services’ retail customer obligations will be fully performed by June 1, 2014.

In connection with the operation of the retail energy supply business, as of December 31, 2011 and 2010, Pepco Energy Services had collateral pledged to counterparties primarily for the instruments it uses to hedge commodity price risk of approximately $113 million and $230 million, respectively. The collateral pledged as of December 31, 2011, included $1 million in the form of letters of credit and $112 million posted in cash. Pepco Energy Services estimates that at current market prices, with the wind-down of the retail energy supply business, an aggregate of 80% of the collateral will no longer need to be pledged by December 31, 2012, and substantially all collateral will no longer need to be pledged by June 1, 2014.

As a result of the decision to wind-down the retail energy supply business, Pepco Energy Services in the fourth quarter of 2009 recorded (i) a $4 million pre-tax impairment charge reflecting the write off of all goodwill allocated to the business and (ii) a pre-tax charge of less than $1 million related to employee severance.

Pepco Energy Services’ remaining businesses will not be affected by the wind-down of the retail energy supply business.

Other Non-Regulated

Through its subsidiary PCI, PHI maintains a portfolio of cross-border energy lease investments with a book value at December 31, 2011 of approximately $1.3 billion. This activity constitutes a third operating segment, which is designated as “Other Non-Regulated,” for financial reporting purposes. For a discussion of PHI’s cross-border energy lease investments, see Note (8), “Leasing Activities – Investment in Finance Leases Held in Trust,” and Note (17), “Commitments and Contingencies—PHI’s Cross-Border Energy Lease Investments,” to the consolidated financial statements of PHI.

Discontinued Operations

On April 20, 2010, the Board of Directors of PHI approved a plan for the disposition of Conectiv Energy. On July 1, 2010, PHI completed the sale of Conectiv Energy’s wholesale power generation business to Calpine for $1.64 billion. The disposition of all of Conectiv Energy’s remaining assets and businesses not

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included in the Calpine sale, including its load service supply contracts, energy hedging portfolio and certain tolling agreements, has been substantially completed. The operations of Conectiv Energy, which previously comprised a separate segment for financial reporting purposes, have been classified as a discontinued operation in PHI’s consolidated financial statements for each of the years ended December 31, 2011, 2010 and 2009, and the business is no longer being treated as a separate segment for financial reporting purposes. Accordingly, in this Management’s Discussion and Analysis of Financial Condition and Results of Operations, all references to continuing operations exclude the operations of the former Conectiv Energy segment.

Earnings Overview

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

PHI’s net income from continuing operations for the year ended December 31, 2011 was $260 million, or $1.15 per share, compared to $139 million, or $0.62 per share, for the year ended December 31, 2010.

Net income from continuing operations for the year ended December 31, 2010, included the charges set forth below in the business segments noted which are presented net of federal and state income taxes (assuming a composite tax rate of approximately 40%) and are in millions of dollars:

Debt extinguishment costs including treasury lock hedge (Corporate and Other)	$	113
Restructuring charge (All segments)	$	18
Effects of Pepco divestiture-related claims (Power Delivery)	$	6

Excluding these items, net income from continuing operations would have been $276 million, or $1.24 per share, for the year ended December 31, 2010. PHI discloses net income from continuing operations and related per share data excluding these 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.

PHI’s net loss from discontinued operations for the year ended December 31, 2011 was $3 million, or $0.01 per share, compared to a net loss of $107 million, or $0.48 per share, for the year ended December 31, 2010.

PHI’s net income (loss) for the years ended December 31, 2011 and 2010, by operating segment, is set forth in the table below (in millions of dollars):

	2011			2010			Change
Power Delivery	$	210		$	206		$	4
Pepco Energy Services		24			36			(12	)
Other Non-Regulated		35			25			10
Corporate and Other		(9	)		(128	)		119
Net Income from Continuing Operations		260			139			121
Discontinued Operations		(3	)		(107	)		104
Total PHI Net Income	$	257		$	32		$	225

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Discussion of Operating Segment Net Income Variances:

Power Delivery’s $4 million increase in earnings was primarily due to the following:

• $23 million increase from higher distribution revenue primarily due to Regulated T&D Electric and Regulated Gas distribution rate increases.

• $18 million increase associated with higher Default Electricity Supply margins, primarily resulting from an approval by the DCPSC of an increase in Pepco’s cost recovery rate for providing SOS in the District of Columbia, and adjustments to Pepco and DPL operating and maintenance expenses for providing SOS.

• $17 million increase from higher transmission revenue primarily attributable to higher rates effective June 1, 2010 and June 1, 2011, related to increases in transmission plant investment.

• $17 million increase due to a restructuring charge related to severance, pension and health and welfare benefits for employee terminations, associated with the reorganization of PHI in 2010.

• $6 million increase due to an order by the DCPSC in 2010 associated with the effects of Pepco divestiture-related claims.

• $56 million decrease due to higher operating and maintenance expenses primarily from increased system preventative maintenance and reliability activities.

• $10 million decrease in distribution revenues due to lower usage, including the effect of milder weather.

• $8 million decrease due to higher depreciation expense.

Pepco Energy Services’ $12 million decrease in earnings was primarily due to mark-to-market losses of $18 million in 2011 on derivative contracts, lower earnings as a result of the ongoing wind-down of the retail energy supply business and lower capacity revenues from the generating facilities, partially offset by higher operating income from the energy services business.

Other Non-Regulated’s $10 million increase in earnings was primarily due to favorable income tax adjustments and the gain on the early termination of certain cross-border energy leases, partially offset by lower financial investment portfolio activity (as further discussed in Note (8), “Leasing Activities – Investment in Finance Leases Held in Trust,” and Note (12), “Income Taxes,” to the consolidated financial statements of PHI.

Corporate and Other’s $119 million decrease in loss was primarily due to the unfavorable impact of debt extinguishment costs in 2010 and lower interest expense in 2011 as a result of the reduction in outstanding debt due to the retirement of debt with the Conectiv Energy sale proceeds, partially offset by favorable income tax adjustments in 2010 from the release of certain deferred tax valuation allowances related to state net operating losses.

The $104 million decrease in the net loss from discontinued operations was primarily due to the 2010 write-down associated with the sale of the wholesale power generation business to Calpine and unrealized losses on derivative instruments no longer qualifying for cash flow hedge accounting, partially offset by gains in the 2010 period from sales of load service supply contracts.

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Consolidated Results of Operations

The following results of operations discussion compares the year ended December 31, 2011, to the year ended December 31, 2010. 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:

	2011			2010			Change
Power Delivery	$	4,650		$	5,114		$	(464	)
Pepco Energy Services		1,238			1,883			(645	)
Other Non-Regulated		48			54			(6	)
Corporate and Other		(16	)		(12	)		(4	)
Total Operating Revenue	$	5,920		$	7,039		$	(1,119	)

Power Delivery Business

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

	2011		2010		Change
Regulated T&D Electric Revenue	$	1,891	$	1,858	$	33
Default Electricity Supply Revenue		2,462		2,951		(489	)
Other Electric Revenue		67		68		(1	)
Total Electric Operating Revenue		4,420		4,877		(457	)
Regulated Gas Revenue		183		191		(8	)
Other Gas Revenue		47		46		1
Total Gas Operating Revenue		230		237		(7	)
Total Power Delivery Operating Revenue	$	4,650	$	5,114	$	(464	)

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.

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. Depending on the jurisdiction, Default Electricity Supply is also known as SOS or BGS. The costs related to Default Electricity Supply are included in Fuel and 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 issued by ACE Funding, and revenue in the form of transmission enhancement credits that PHI utility subsidiaries receive as transmission owners from PJM for approved regional transmission expansion plan costs.

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 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

	2011		2010		Change
Regulated T&D Electric Revenue
Residential	$	683	$	683	$	—
Commercial and industrial		884		883		1
Transmission and other		324		292		32
Total Regulated T&D Electric Revenue	$	1,891	$	1,858	$	33

	2011		2010		Change
Regulated T&D Electric Sales (Gigawatt hours(GWh))
Residential		17,728		18,398		(670	)
Commercial and industrial		31,282		32,045		(763	)
Transmission and other		256		260		(4	)
Total Regulated T&D Electric Sales		49,266		50,703		(1,437	)

	2011		2010		Change
Regulated T&D Electric Customers (in thousands)
Residential		1,636		1,635		1
Commercial and industrial		198		198		—
Transmission and other		2		2		—
Total Regulated T&D Electric Customers		1,836		1,835		1

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 activity in the region includes banking and other professional services, government, insurance, real estate, shopping malls, casinos, stand alone construction and tourism.

• Industrial activity in the region includes chemical, glass, pharmaceutical, steel manufacturing, food processing and oil refining.

Regulated T&D Electric Revenue increased by $33 million primarily due to:

• An increase of $32 million due to distribution rate increases (Pepco in the District of Columbia effective March 2010 and July 2010, and in Maryland effective July 2010; DPL in Maryland effective July 2011, and in Delaware effective February 2011; and ACE in New Jersey effective June 2010).

• An increase of $32 million in transmission revenue primarily attributable to higher rates effective June 1, 2010 and June 1, 2011 related to increases in transmission plant investment.

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• An increase of $11 million due to higher pass-through revenue (which is substantially offset by a corresponding increase in Other Taxes) primarily the result of rate increases in Montgomery County, Maryland utility taxes that are collected by Pepco on behalf of the county.

• An increase of $7 million primarily due to Pepco customer growth in 2011, primarily in the residential class.

• An increase of $2 million due to the implementation of the EmPower Maryland (a demand side management program) surcharge in March 2010 (which is substantially offset by a corresponding increase in Depreciation and Amortization).

The aggregate amount of these increases was partially offset by:

• A decrease of $30 million due to an ACE New Jersey Societal Benefit Charge rate decrease that became effective in January 2011 (which is offset in Deferred Electric Service Costs).

• A decrease of $11 million due to lower sales as a result of cooler weather during the spring and summer months of 2011, and warmer weather during the fall months of 2011, as compared to the corresponding periods in 2010.

• A decrease of $10 million due to lower non-weather related average customer usage.

Default Electricity Supply

	2011		2010		Change
Default Electricity Supply Revenue
Residential	$	1,668	$	2,022	$	(354	)
Commercial and industrial		642		733		(91	)
Other		152		196		(44	)
Total Default Electricity Supply Revenue	$	2,462	$	2,951	$	(489	)

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.

	2011		2010		Change
Default Electricity Supply Sales (GWh)
Residential		15,545		17,385		(1,840	)
Commercial and industrial		6,168		7,034		(866	)
Other		73		93		(20	)
Total Default Electricity Supply Sales		21,786		24,512		(2,726	)

	2011		2010		Change
Default Electricity Supply Customers (in thousands)
Residential		1,432		1,525		(93	)
Commercial and industrial		137		148		(11	)
Other		—		1		(1	)
Total Default Electricity Supply Customers		1,569		1,674		(105	)

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Default Electricity Supply Revenue decreased by $489 million primarily due to:

• A decrease of $200 million due to lower sales, primarily as a result of customer migration to competitive suppliers.

• A net decrease of $153 million as a result of lower Pepco and DPL Default Electricity Supply rates, partially offset by higher ACE rates.

• A decrease of $94 million due to lower sales as a result of cooler weather during the spring and summer months of 2011, and warmer weather during the fall months of 2011, as compared to the corresponding periods in 2010.

• A decrease of $40 million in wholesale energy and capacity resale revenues primarily due to the sale of lower volumes of electricity and capacity purchased from NUGs.

• A decrease of $3 million due to a decrease in revenue from Transmission Enhancement Credits.

The aggregate amount of these decreases was partially offset by:

• An increase of $3 million resulting from an approval by the DCPSC of an increase in Pepco’s cost recovery rate for providing Default Electricity Supply in the District of Columbia to provide for recovery of higher cash working capital costs incurred in prior periods. The higher cash working capital costs were incurred when the billing cycle for providers of Default Electricity Supply was shortened from a monthly to a weekly period, effective in June 2009.

Total Default Electricity Supply Revenue for the 2011 period includes a decrease of $8 million in unbilled revenue attributable to ACE’s BGS ($5 million decrease in net income), primarily due to lower customer usage and lower Default Electricity Supply rates during the unbilled revenue period at the end of 2011 as compared to the corresponding period in 2010. Under the BGS terms approved by the NJBPU, ACE’s BGS unbilled revenue is not included in the deferral calculation until it is billed to customers, and therefore has an impact on the results of operations in the period during which it is accrued.

Regulated Gas

	2011		2010		Change
Regulated Gas Revenue
Residential	$	113	$	118	$	(5	)
Commercial and industrial		61		65		(4	)
Transportation and other		9		8		1
Total Regulated Gas Revenue	$	183	$	191	$	(8	)

	2011		2010		Change
Regulated Gas Sales (billion cubic feet)
Residential		7		8		(1	)
Commercial and industrial		5		5		—
Transportation and other		7		6		1
Total Regulated Gas Sales		19		19		—

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	2011		2010		Change
Regulated Gas Customers (in thousands)
Residential		115		114		1
Commercial and industrial		9		9		—
Transportation and other		—		—		—
Total Regulated Gas Customers		124		123		1

DPL’s natural gas service territory is located in New Castle County, Delaware. Several key industries contribute to the economic base as well as to growth.

• Commercial activity in the region includes banking and other professional services, government, insurance, real estate, shopping malls, stand alone construction and tourism.

• Industrial activity in the region includes chemical and pharmaceutical.

Regulated Gas Revenue decreased by $8 million primarily due to:

• A decrease of $17 million due to lower non-weather related average customer usage.

The decrease was partially offset by:

• An increase of $6 million due to higher sales primarily as a result of colder weather during the winter of 2011 as compared to the winter of 2010.

• An increase of $2 million due to a distribution rate increase effective February 2011.

• An increase of $2 million due to customer growth in 2011.

Pepco Energy Services

Pepco Energy Services’ operating revenue decreased $645 million primarily due to:

• A decrease of $672 million due to lower retail supply sales volume primarily attributable to the ongoing wind-down of the retail energy supply business.

• A decrease of $33 million due to lower generation and capacity revenues at the generating facilities.

The aggregate amount of these decreases was partially offset by:

• An increase of $61 million due to increased energy services activities.

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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:

	2011			2010			Change
Power Delivery	$	2,490		$	3,086		$	(596	)
Pepco Energy Services		1,106			1,691			(585	)
Corporate and Other		(2	)		(6	)		4
Total	$	3,594		$	4,771		$	(1,177	)

Power Delivery Business

Power Delivery’s Fuel and Purchased Energy 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 decreased by $596 million primarily due to:

• A decrease of $300 million due to lower average electricity costs under Default Electricity Supply contracts.

• A decrease of $221 million primarily due to customer migration to competitive suppliers.

• A decrease of $83 million due to lower electricity sales primarily as a result of cooler weather during the spring and summer months of 2011, and warmer weather during the fall months of 2011, as compared to the corresponding periods in 2010.

• A decrease of $16 million in the cost of gas purchases for on-system sales as a result of lower average gas prices, lower volumes purchased and lower withdrawals from storage.

• A decrease of $11 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 decreases was partially offset by:

• An increase of $18 million in deferred electricity expense primarily due to lower Default Electricity Supply rates, which resulted in a higher rate of recovery of Default Electricity Supply costs.

• An increase of $18 million in deferred natural gas expense as a result of a higher rate of recovery of natural gas supply costs.

Pepco Energy Services

Pepco Energy Services’ Fuel and Purchased Energy and Other Services Cost of Sales decreased $585 million primarily due to:

• A decrease of $621 million due to lower volumes of electricity and gas purchased to serve decreased retail supply sales volume as a result of the ongoing wind-down of the retail energy supply business.

• A decrease of $10 million due to lower fuel usage associated with the generating facilities.

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The aggregate amount of these decreases was partially offset by:

• An increase of $46 million due to increased energy services activities.

Other Operation and Maintenance

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

	2011			2010			Change
Power Delivery	$	884		$	809		$	75
Pepco Energy Services		81			95			(14	)
Other Non-Regulated		6			4			2
Corporate and Other		(57	)		(24	)		(33	)
Total	$	914		$	884		$	30

Other Operation and Maintenance expense for Power Delivery increased by $75 million primarily due to:

• An increase of $38 million associated with higher tree trimming and preventative maintenance costs.

• An increase of $13 million primarily due to higher 2011 DCPSC rate case costs and reliability audit expenses and due to 2010 Pepco adjustments for the deferral of (i) February 2010 severe winter storm costs of $5 million and (ii) distribution rate case costs of $4 million that previously were charged to other operation and maintenance expense. The adjustments were recorded in accordance with a MPSC rate order issued in August 2010 and a DCPSC rate order issued in February 2010, allowing for the recovery of the costs.

• An increase of $9 million in employee-related costs, primarily benefit expenses.

• An increase of $8 million primarily due to Pepco’s emergency restoration improvement project and reliability improvement costs.

• An increase of $8 million in customer support service and system support costs.

• An increase of $6 million in communication costs.

• An increase of $5 million in corporate cost allocations, primarily due to higher contractor and outside legal counsel fees.

• An increase of $5 million related to New Jersey Societal Benefit Program costs that are deferred and recoverable.

• An increase of $4 million in emergency restoration costs. The increase is primarily related to significant incremental costs incurred for repair work following Hurricane Irene in August 2011. Costs incurred for repair work were $28 million, of which $22 million was deferred as regulatory assets to reflect the probable recovery of these storm costs in certain jurisdictions, and the remaining $6 million was charged to other operation and maintenance expense. Approximately $4 million of these total incremental storm costs have been estimated for the cost of restoration services provided by outside contractors. Since the invoices for such services had not been received at December 31, 2011, actual invoices may vary from these estimates. PHI’s utility subsidiaries currently plan to seek recovery of the incremental Hurricane Irene costs in each of their various jurisdictions in pending or planned distribution rate case filings.

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• An increase of $3 million in costs related to customer requested and mutual assistance work (primarily offset in other Electric T&D Revenue).

The aggregate amount of these increases was partially offset by:

• A decrease of $17 million resulting from adjustments recorded by PHI in 2011 associated with the accounting for DPL and Pepco Default Electricity Supply. These adjustments were primarily due to the under-recognition of allowed returns on working capital, uncollectible accounts, late fees and administrative costs.

• A decrease of $15 million in environmental remediation costs.

Restructuring Charge

As a result of PHI’s organizational review in the second quarter of 2010, PHI’s operating expenses include a pre-tax restructuring charge of $30 million for the year ended December 31, 2010, related to severance and health and welfare benefits to be provided to terminated employees.

Depreciation and Amortization

Depreciation and Amortization expense increased by $33 million to $426 million in 2011 from $393 million in 2010 primarily due to:

• An increase of $16 million in amortization of stranded costs as the result of higher revenue due to rate increases effective October 2010 for the ACE Transition Bond Charge and Market Transition Charge Tax (partially offset in Default Electricity Supply Revenue).

• An increase of $14 million due to utility plant additions.

• An increase of $4 million in amortization of regulatory assets primarily associated with the EmPower Maryland surcharge that became effective in March 2010 (which is substantially offset by a corresponding increase in Regulated T&D Electric Revenue).

• An increase of $1 million in amortization of software upgrades to Pepco’s Energy Management System.

The aggregate amount of these increases was partially offset by:

• A decrease of $3 million primarily due to the higher 2010 recognition of asset retirement obligations associated with Pepco Energy Services generating facilities scheduled for deactivation in May 2012.

Other Taxes

Other Taxes increased by $17 million to $451 million in 2011 from $434 million in 2010. The increase was primarily due to:

• An increase of $16 million primarily due to rate increases in the Montgomery County, Maryland utility taxes that are collected and passed through by Pepco (substantially offset by a corresponding increase in Regulated T&D Electric Revenue).

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• An increase of $5 million due to an adjustment in the third quarter of 2010 to correct certain errors related to other taxes.

The aggregate amount of these increases was partially offset by:

• A decrease of $5 million in the Energy Assistance Trust Fund surcharge primarily due to rate decreases effective October 2010 (substantially offset by a corresponding decrease in Regulated T&D Electric Revenue).

Gain on Early Termination of Finance Leases Held in Trust

PHI’s operating expenses include a $39 million pre-tax gain for the year ended December 31, 2011 associated with the early termination of several lease investments included in its cross-border energy lease portfolio. For a further discussion of this transaction, see Note (8), “Leasing Activities,” to the consolidated financial statements of PHI.

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

Deferred Electric Service Costs increased by $45 million, to an expense reduction of $63 million in 2011 as compared to an expense reduction of $108 million in 2010, primarily due to higher Default Electricity Supply Revenue rates and lower electricity supply costs.

Effects of Pepco Divestiture-Related Claims

The DCPSC on May 18, 2010 issued an order addressing all of the outstanding issues relating to Pepco’s obligation to share with its District of Columbia customers the net proceeds realized by Pepco from the sale of its generation-related assets in 2000. This order disallowed certain items that Pepco had included in the costs it deducted in calculating the net proceeds of the sale. The disallowance of these costs, together with interest, increased the aggregate amount Pepco is required to distribute to customers by approximately $11 million. PHI recognized a pre-tax expense of $11 million for the year ended December 31, 2010.

Other Income (Expenses)

Other Expenses (which are net of Other Income) decreased by $246 million primarily due to the loss on extinguishment of debt that was recorded in 2010 and lower interest expense in 2011 resulting from the reduction in outstanding long term debt in 2010 with the proceeds from the Conectiv Energy sale.

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Loss on Extinguishment of Debt

In 2010, PHI purchased or redeemed senior notes in the aggregate principal amount of $1,194 million. In connection with these transactions, PHI recorded a pre-tax loss on extinguishment of debt of $189 million in 2010, $174 million of which was attributable to the retirement of the debt and $15 million of which related to the acceleration of losses on treasury rate lock transactions associated with the retired debt. For a further discussion of these transactions, see Note (11), “Debt,” to the consolidated financial statements of PHI.

Income Tax Expense

PHI’s consolidated effective tax rates from continuing operations for the years ended December 31, 2011 and 2010 were 36.4% and 7.3%, respectively. The increase in the effective tax rate was primarily due to the recognition of certain tax benefits in 2010 that did not recur in 2011 and PHI’s early termination of its interest in certain cross-border energy leases in 2011.

In 2010, certain PHI subsidiaries were restructured which subjected PHI to state income taxes in new jurisdictions and resulted in current state tax benefits that were recorded in 2010 and did not recur in 2011. Specifically, on April 1, 2010, as part of an ongoing effort to simplify PHI’s organizational structure, certain of PHI’s subsidiaries were converted from corporations to single member limited liability companies. In addition to increased organizational flexibility and reduced administrative costs, converting these entities to limited liability companies allows PHI to include income or losses in the former corporations in a single state income tax return, thus increasing the utilization of state income tax attributes. As a result of inclusions of income or losses in a single state return as discussed above, PHI recorded an $8 million benefit by reversing a valuation allowance on certain state net operating losses and an additional benefit of $6 million resulting from changes to certain state deferred tax benefits.

In addition, in November 2010, PHI reached final settlement with the IRS with respect to its federal tax returns for the years 1996 to 2002 for all issues except its cross-border energy lease investments. In connection with the settlement, PHI reallocated certain amounts on deposit with the IRS since 2006 among liabilities in the settlement years and subsequent years. In light of the settlement and reallocations, PHI has recalculated the estimated interest due for the tax years 1996 to 2002. The revised estimate resulted in the reversal of $15 million (after-tax) of estimated interest due to the IRS which was recorded as an income tax benefit in the fourth quarter of 2010.

In 2011, a $17 million (after-tax) income tax benefit was recorded in the first quarter when PHI reached a settlement with the IRS related to the calculation of interest due as a result of the November 2010 audit settlement. This benefit was more than offset during the second quarter of 2011, when PHI terminated early its interest in certain cross-border energy leases prior to the end of their stated term. As a result of the early terminations, PHI reversed $22 million of previously recognized federal tax benefits associated with those leases that will not be realized.

Discontinued Operations

For the year ended December 31, 2011, the $3 million loss from discontinued operations, net of income taxes, consists of an after-tax loss from operations of $1 million and after-tax net loss of $2 million from dispositions of assets and businesses.

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The following results of operations discussion is for the year ended December 31, 2010, compared to the year ended December 31, 2009. 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:

	2010			2009			Change
Power Delivery	$	5,114		$	4,980		$	134
Pepco Energy Services		1,883			2,383			(500	)
Other Non-Regulated		54			51			3
Corporate and Other		(12	)		(12	)		—
Total Operating Revenue	$	7,039		$	7,402		$	(363	)

Power Delivery Business

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

	2010		2009		Change
Regulated T&D Electric Revenue	$	1,858	$	1,653	$	205
Default Electricity Supply Revenue		2,951		2,990		(39	)
Other Electric Revenue		68		69		(1	)
Total Electric Operating Revenue		4,877		4,712		165
Regulated Gas Revenue		191		228		(37	)
Other Gas Revenue		46		40		6
Total Gas Operating Revenue		237		268		(31	)
Total Power Delivery Operating Revenue	$	5,114	$	4,980	$	134

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.

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. Depending on the jurisdiction, Default Electricity Supply is also known as SOS or BGS. The costs related to Default Electricity Supply are included in Fuel and 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 issued by ACE Funding, and revenue in the form of transmission enhancement credits that PHI utility subsidiaries receive as transmission owners from PJM for approved regional transmission expansion plan costs.

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 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.

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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

	2010		2009		Change
Regulated T&D Electric Revenue
Residential	$	683	$	596	$	87
Commercial and industrial		883		804		79
Transmission and other		292		253		39
Total Regulated T&D Electric Revenue	$	1,858	$	1,653	$	205

	2010		2009		Change
Regulated T&D Electric Sales (GWh)
Residential		18,398		16,871		1,527
Commercial and industrial		32,045		31,570		475
Transmission and other		260		261		(1	)
Total Regulated T&D Electric Sales		50,703		48,702		2,001

	2010		2009		Change
Regulated T&D Electric Customers (in thousands)
Residential		1,635		1,623		12
Commercial and industrial		198		198		—
Transmission and other		2		2		—
Total Regulated T&D Electric Customers		1,835		1,823		12

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 activity in the region includes banking and other professional services, government, insurance, real estate, shopping malls, casinos, stand alone construction and tourism.

• Industrial activity in the region includes chemical, glass, pharmaceutical, steel manufacturing, food processing and oil refining.

Regulated T&D Electric Revenue increased by $205 million primarily due to:

• An increase of $61 million due to higher pass-through revenue (which is substantially offset by a corresponding increase in Other Taxes) primarily the result of rate increases in Montgomery County, Maryland utility taxes that are collected by Pepco on behalf of the county.

• An increase of $46 million due to distribution rate increases (Pepco in the District of Columbia effective November 2009 and March 2010; DPL in Maryland effective December 2009; DPL in Delaware effective April 2010; and ACE in New Jersey effective June 2010).

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• An increase of $37 million in transmission revenue primarily attributable to higher rates effective June 1, 2010 related to an increase in transmission plant investment.

• An increase of $26 million due to higher revenue in the District of Columbia, Delaware and New Jersey service territories, primarily as a result of warmer weather during the spring and summer months of 2010 as compared to 2009. Distribution revenue in Maryland was decoupled from consumption in 2010 and 2009, and therefore, the weather in this jurisdiction does not affect the period-to-period comparison. The BSA was not implemented in the District of Columbia until November 2009, and therefore, the period-to-period comparison is affected by weather.

• An increase of $15 million due to the implementation of the EmPower Maryland surcharge in March 2010 (which is substantially offset by a corresponding increase in Depreciation and Amortization).

• An increase of $9 million due to higher non-weather related average customer usage.

• An increase of $8 million due to Pepco customer growth of 1% in 2010, primarily in the residential class.

Default Electricity Supply

	2010		2009		Change
Default Electricity Supply Revenue
Residential	$	2,022	$	1,915	$	107
Commercial and industrial		733		915		(182	)
Other		196		160		36
Total Default Electricity Supply Revenue	$	2,951	$	2,990	$	(39	)

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.

	2010		2009		Change
Default Electricity Supply Sales (GWh)
Residential		17,385		16,274		1,111
Commercial and industrial		7,034		8,470		(1,436	)
Other		93		101		(8	)
Total Default Electricity Supply Sales		24,512		24,845		(333	)

	2010		2009		Change
Default Electricity Supply Customers (in thousands)
Residential		1,525		1,572		(47	)
Commercial and industrial		148		159		(11	)
Other		1		2		(1	)
Total Default Electricity Supply Customers		1,674		1,733		(59	)

Default Electricity Supply Revenue decreased by $39 million primarily due to:

• A decrease of $200 million due to lower sales, primarily as a result of commercial customer migration to competitive suppliers.

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• A decrease of $59 million as a result of lower Default Electricity Supply rates.

The aggregate amount of these decreases was partially offset by:

• An increase of $144 million due to higher sales primarily as a result of warmer weather during the spring and summer months of 2010 as compared to 2009.

• An increase of $40 million due to higher non-weather related average customer usage.

• An increase of $29 million in wholesale energy and capacity revenues primarily due to higher market prices for the sale of electricity and capacity purchased from NUGs.

• An increase of $8 million due to an increase in revenue from transmission enhancement credits.

Total Default Electricity Supply Revenue for the 2010 period includes an increase of $8 million in unbilled revenue attributable to ACE’s BGS ($5 million increase in net income), primarily due to lower customer usage and lower Default Electricity Supply rates during the unbilled revenue period at the end of 2010 as compared to the corresponding period in 2009. Under the BGS terms approved by the NJBPU, ACE’s BGS unbilled revenue is not included in the deferral calculation until it is billed to customers, and therefore has an impact on the results of operations in the period during which it is accrued.

Regulated Gas

	2010		2009		Change
Regulated Gas Revenue
Residential	$	118	$	139	$	(21	)
Commercial and industrial		65		81		(16	)
Transportation and other		8		8		—
Total Regulated Gas Revenue	$	191	$	228	$	(37	)
	2010		2009		Change
Regulated Gas Sales (billion cubic feet)
Residential		8		8		—
Commercial and industrial		5		5		—
Transportation and other		6		6		—
Total Regulated Gas Sales		19		19		—
	2010		2009		Change
Regulated Gas Customers (in thousands)
Residential		114		113		1
Commercial and industrial		9		10		(1	)
Transportation and other		—		—		—
Total Regulated Gas Customers		123		123		—

DPL’s natural gas service territory is located in New Castle County, Delaware. Several key industries contribute to the economic base as well as to growth.

• Commercial activity in the region includes banking and other professional services, government, insurance, real estate, shopping malls, stand alone construction and tourism.

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• Industrial activity in the region includes chemical and pharmaceutical.

Regulated Gas Revenue decreased by $37 million primarily due to:

• A decrease of $22 million due to Gas Cost Rate (GCR) decreases effective March 2009 and November 2009.

• A decrease of $14 million due to lower sales as a result of milder weather during the winter months of 2010 as compared to 2009.

Other Gas Revenue

Other Gas Revenue increased by $6 million primarily due to higher revenue from off-system sales resulting from:

• An increase of $4 million due to higher demand from electric generators and natural gas marketers.

• An increase of $2 million due to higher market prices.

Pepco Energy Services

Pepco Energy Services’ operating revenue decreased $500 million primarily due to:

• A decrease of $651 million due to lower retail electricity sales volume due to the ongoing wind-down of the retail energy supply business.

The decrease is partially offset by:

• An increase of $100 million due to higher electricity generation output as the result of completed transmission construction projects and warmer than normal weather, and lower RPM charges associated with the generating facilities.

• An increase of $38 million due to increased energy services activities.

• An increase of $13 million due to a higher retail natural gas supply load as the result of 2009 customer acquisitions, partially offset by lower retail natural gas prices.

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:

	2010			2009			Change
Power Delivery	$	3,086		$	3,243		$	(157	)
Pepco Energy Services		1,691			2,179			(488	)
Corporate and Other		(6	)		(7	)		1
Total	$	4,771		$	5,415		$	(644	)

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Power Delivery Business

Power Delivery’s Fuel and Purchased Energy 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 decreased by $157 million primarily due to:

• A decrease of $197 million primarily due to commercial customer migration to competitive suppliers.

• A decrease of $59 million in deferred electricity expense primarily due to lower Default Electricity Supply Revenue rates, which resulted in a lower rate of recovery of Default Electricity Supply costs.

• A decrease of $17 million in deferred natural gas expense as a result of a lower rate of recovery of natural gas supply costs.

• A decrease of $14 million due to lower average electricity costs under Default Electricity Supply contracts.

• A decrease of $12 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 decreases was partially offset by:

• An increase of $143 million due to higher electricity sales primarily as a result of warmer weather during the spring and summer months of 2010 as compared to 2009.

Pepco Energy Services

Pepco Energy Services’ Fuel and Purchased Energy and Other Services Cost of Sales decreased $488 million primarily due to:

• A decrease of $571 million due to lower volumes of electricity purchased to serve decreased retail customer load as a result of the ongoing wind-down of the retail energy supply business.

The decrease is partially offset by:

• An increase of $42 million due to increased energy services activities.

• An increase of $27 million due to higher fuel usage associated with the generating facilities.

• An increase of $15 million due to a higher retail natural gas supply load as the result of 2009 customer acquisitions, partially offset by lower wholesale natural gas prices.

Other Operation and Maintenance

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

	2010			2009			Change
Power Delivery	$	809		$	752		$	57
Pepco Energy Services		95			90			5
Other Non-Regulated		4			2			2
Corporate and Other		(24	)		(25	)		1
Total	$	884		$	819		$	65

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Other Operation and Maintenance expense for Power Delivery increased by $57 million; however, excluding an increase of $11 million primarily related to bad debt and administrative expenses that are deferred and recoverable in Default Electricity Supply Revenue, Other Operation and Maintenance expense increased by $46 million. The $46 million increase was primarily due to:

• An increase of $33 million in emergency restoration costs primarily due to severe storms in February, July and August 2010.

• An increase of $17 million in estimated environmental remediation costs.

• An increase of $14 million primarily due to higher tree trimming and preventative maintenance costs.

• An increase of $5 million primarily due to system support and customer support service costs.

The aggregate amount of these increases was partially offset by:

• A decrease of $17 million in employee-related costs, primarily due to lower pension and other postretirement benefit (OPEB) expenses.

• A decrease of $9 million primarily due to Pepco deferral of (i) February 2010 severe winter storm costs, and (ii) distribution rate case costs, which in each case originally had been charged to Other Operation and Maintenance expense. These deferrals were recorded in accordance with a MPSC rate order issued in August 2010 and a DCPSC rate order issued in February 2010, respectively, authorizing the establishment of regulatory assets for the recovery of these costs.

Other Operation and Maintenance expense for Pepco Energy Services increased $5 million, primarily due to increases of $8 million in power plant operating costs and $3 million due to the repair cost of a distribution system pipe leak; partially offset by a decrease of $5 million in bad debt expense.

Restructuring Charge

As a result of PHI’s organizational review in the second quarter of 2010, PHI’s operating expenses include a pre-tax restructuring charge of $30 million for the year ended December 31, 2010, related to severance and health and welfare benefits to be provided to terminated employees.

Depreciation and Amortization

Depreciation and Amortization expense increased by $44 million to $393 million in 2010 from $349 million in 2009 primarily due to:

• An increase of $12 million in amortization of regulatory assets primarily due to the EmPower Maryland surcharge that became effective in March 2010 (which is substantially offset by a corresponding increase in Regulated T&D Electric Revenue).

• An increase of $10 million due to utility plant additions.

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• An increase of $8 million due to higher amortization by ACE of stranded costs, primarily the result of higher revenue due to increases in sales (partially offset in Default Electricity Supply Revenue).

• An increase of $4 million primarily due to the recognition of asset retirement obligations associated with Pepco Energy Services generating facilities scheduled for deactivation in May 2012.

• An increase of $2 million in the amortization of demand-side management program deferred expenses.

Other Taxes

Other Taxes increased by $66 million to $434 million in 2010 from $368 million in 2009. The increase was primarily due to increased pass-throughs experienced by Power Delivery (which are substantially offset by a corresponding increase in Regulated T&D Electric Revenue) primarily resulting from utility tax rate increases imposed by Montgomery County, 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 purchased is reported under Fuel and Purchased Energy and the corresponding revenue is reported under Default Electricity Supply Revenue. The cost of New Jersey Societal Benefit Programs is reported under Other Operation and Maintenance and the corresponding revenue is reported under Regulated T&D Electric Revenue.

Deferred Electric Service Costs increased by $53 million, to an expense reduction of $108 million in 2010 as compared to an expense reduction of $161 million in 2009, primarily due to an increase in deferred electricity expense as a result of lower electricity supply costs and higher Default Electricity Supply Revenue rates.

Effects of Pepco Divestiture-Related Claims

District of Columbia Divestiture Case

The DCPSC on May 18, 2010 issued an order addressing all of the outstanding issues relating to Pepco’s obligation to share with its District of Columbia customers the net proceeds realized by Pepco from the sale of its generation-related assets in 2000. This order disallowed certain items that Pepco had included in the costs it deducted in calculating the net proceeds of the sale. The disallowance of these costs, together with interest, increased the aggregate amount Pepco was required to distribute to customers by approximately $11 million. PHI recognized a pre-tax expense of $11 million for the year ended December 31, 2010.

Settlement of Mirant Bankruptcy Claims

In March 2009, the DCPSC approved an allocation between Pepco and its District of Columbia customers of the District of Columbia portion of the Mirant bankruptcy settlement proceeds remaining after the transfer of the power purchase agreement between Pepco and Panda-Brandywine, L.P. As a result, Pepco recorded a pre-tax gain of $14 million in the first quarter of 2009 reflecting the District of Columbia proceeds retained by Pepco. In July 2009, the MPSC approved an allocation between Pepco and its Maryland customers of the Maryland portion of the Mirant bankruptcy settlement proceeds. As a result, Pepco recorded a pre-tax gain of $26 million in the third quarter of 2009 reflecting the Maryland proceeds retained by Pepco.

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Other Income (Expenses)

Other Expenses (which are net of Other Income) increased by $153 million primarily due to a $189 million loss on extinguishment of debt that was recorded in 2010 as further discussed below, partially offset by lower interest expense of $34 million.

Loss on Extinguishment of Debt

In 2010, PHI purchased or redeemed senior notes in the aggregate principal amount of $1,194 million. In connection with these transactions, PHI recorded a pre-tax loss on extinguishment of debt of $189 million in 2010, $174 million of which was attributable to the retirement of the debt and $15 million of which related to the acceleration of losses on treasury rate lock transactions associated with debt that was retired. For a further discussion of these transactions, see Note (11), “Debt,” to the consolidated financial statements of PHI.

Income Tax Expense

PHI’s consolidated effective tax rates from continuing operations for the years ended December 31, 2010 and 2009 were 7.3% and 31.8%, respectively. The reduction in the effective tax rate is primarily due to two factors. The first is the recording of current state tax benefits resulting from the restructuring of certain PHI subsidiaries which subjected PHI to state income taxes in new jurisdictions. On April 1, 2010, as part of an ongoing effort to simplify PHI’s organizational structure, certain of PHI’s subsidiaries were converted from corporations to single member limited liability companies. In addition to increased organizational flexibility and reduced administrative costs, converting these entities to limited liability companies allows PHI to include income or losses in the former corporations in a single state income tax return, thus increasing the utilization of state income tax attributes. As a result of inclusions of income or losses in a single state return as discussed above, PHI recorded an $8 million benefit by reversing a valuation allowance on certain state net operating losses and an additional benefit of $6 million resulting from changes to certain state deferred tax benefits.

The second factor is the reversal of accrued interest on uncertain and effectively settled tax positions resulting from final settlement with the IRS of certain open tax years. In November 2010, PHI reached final settlement with the IRS with respect to its federal tax returns for the years 1996 to 2002 for all issues except its cross-border energy lease investments. In connection with the settlement, PHI reallocated certain amounts on deposit with the IRS since 2006 among liabilities in the settlement years and subsequent years. In light of the settlement and reallocations, PHI has recalculated the estimated interest due for the tax years 1996 to 2002. The revised estimate has resulted in the reversal of $15 million of previously accrued estimated interest due to the IRS. This reversal has been recorded as an income tax benefit in 2010, and PHI recorded an additional tax benefit of $17 million (after-tax) in the second quarter of 2011 when the IRS finalized its calculation of the amount of interest due.

Discontinued Operations

For the year ended December 31, 2010, the $107 million loss from discontinued operations, net of income taxes, consists of after-tax income from operations of $6 million and after-tax net losses of $113 million from dispositions of assets and businesses.

Capital Resources and Liquidity

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

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Working Capital

At December 31, 2011, PHI’s current assets on a consolidated basis totaled $1.4 billion and its current liabilities totaled $1.9 billion, resulting in a working capital deficit of $422 million. PHI expects the working capital deficit at December 31, 2011 to be funded during 2012 in part through cash flow from operations. Additional working capital will be provided by anticipated reductions in collateral requirements due to the ongoing wind-down of the Pepco Energy Services retail energy supply business. At December 31, 2010, PHI’s current assets on a consolidated basis totaled $1.8 billion and its current liabilities totaled $1.8 billion. The decrease in working capital from December 31, 2010 to December 31, 2011 was primarily due to a decrease in prepayments of income taxes and an increase in short-term debt. Prepayments of income taxes have decreased in 2011 because certain net operating losses that were classified as current assets in 2010 were reclassified as long-term assets in 2011. Short-term debt increased to temporarily support higher spending by the utilities on infrastructure investments and reliability initiatives until permanent financing is obtained.

At December 31, 2011, PHI’s cash and current cash equivalents totaled $109 million, of which $87 million was invested in money market funds, and the balance was held as cash and uncollected funds. Current restricted cash equivalents (cash that is available to be used only for designated purposes) totaled $11 million. At December 31, 2010, PHI’s cash and current cash equivalents totaled $21 million, of which $1 million was reflected on the balance sheet in Conectiv Energy assets held for sale, and its current restricted cash equivalents totaled $11 million.

A detail of PHI’s short-term debt balance and its current maturities of long-term debt and project funding balance follows:

	As of December 31, 2011 (millions of dollars)
Type	PHI Parent		Pepco		DPL		ACE		ACE Funding		Pepco Energy Services		PHI Consolidated
Variable Rate Demand Bonds	$	—	$	—	$	105	$	23	$	—	$	18	$	146
Commercial Paper		465		74		47		—		—		—		586
Total Short-Term Debt	$	465	$	74	$	152	$	23	$	—	$	18	$	732
Current Maturities of Long-Term Debt and Project Funding	$	—	$	—	$	66	$	—	$	37	$	9	$	112

	As of December 31, 2010 (millions of dollars)
Type	PHI Parent		Pepco		DPL		ACE		ACE Funding		Pepco Energy Services		PHI Consolidated
Variable Rate Demand Bonds	$	—	$	—	$	105	$	23	$	—	$	18	$	146
Commercial Paper		230		—		—		158		—		—		388
Total Short-Term Debt	$	230	$	—	$	105	$	181	$	—	$	18	$	534
Current Maturities of Long-Term Debt and Project Funding	$	—	$	—	$	35	$	—	$	35	$	5	$	75

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, 2011, PHI, Pepco, DPL and ACE entered into an amended and restated credit agreement with respect to the facility, which among other changes, extended the expiration date of the facility to August 1, 2016.

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The aggregate borrowing limit under the 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 initial credit sublimit for PHI is $750 million 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 one month 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 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 financial covenants under this facility as of December 31, 2011.

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.

PHI, Pepco, DPL and ACE maintain commercial paper programs to address short-term liquidity needs. As of December 31, 2011, the maximum capacity available under these programs was $875 million, $500 million, $500 million and $250 million, respectively. In January 2012, the Board of Directors approved an increase in PHI’s maximum to $1.25 billion.

PHI, Pepco and DPL had $465 million, $74 million and $47 million, respectively, of commercial paper outstanding at December 31, 2011. ACE had no commercial paper outstanding at December 31, 2011. The weighted average interest rate for commercial paper issued by PHI, Pepco, DPL and ACE during 2011 was 0.64%, 0.35%, 0.34% and 0.33%, respectively. The weighted average maturity of all commercial paper issued by PHI, Pepco, DPL and ACE in 2011 was eleven, two, two and six days, respectively.

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Cash and Credit Facility Available as of December 31, 2011

	Consolidated PHI		PHI Parent		Utility Subsidiaries
	(millions of dollars)
Credit Facility (Total Capacity)	$	1,500	$	750	$	750
Less: Letters of Credit issued		7		2		5
Commercial Paper outstanding		586		465		121
Remaining Credit Facility Available		907		283		624
Cash Invested in Money Market Funds (a)		87		—		87
Total Cash and Credit Facility Available	$	994	$	283	$	711

(a) Cash and cash equivalents reported on the balance sheet of $109 million includes $22 million of cash and uncollected funds.

Collateral Requirements of Pepco Energy Services

In conducting its retail energy supply business, Pepco Energy Services, during periods of declining energy prices, has been exposed to the asymmetrical risk of having to post collateral under its wholesale purchase contracts without receiving a corresponding amount of collateral from its retail customers. To partially address these asymmetrical collateral obligations, Pepco Energy Services, in the first quarter of 2009, entered into a credit intermediation arrangement with Morgan Stanley Capital Group, Inc. (MSCG). Under this arrangement, MSCG, in consideration for the payment to MSCG of certain fees, (i) assumed by novation, the electricity purchase obligations of Pepco Energy Services in years 2009 through 2011 under several wholesale purchase contracts, and (ii) supplied electricity to Pepco Energy Services on the same terms as the novated transactions, but without imposing on Pepco Energy Services any obligation to post collateral based on changes in electricity prices. The upfront fees incurred by Pepco Energy Services in 2009 in the amount of $25 million was amortized into expense in declining amounts over the life of the arrangement based on the fair value of the underlying contracts at the time of the novation. For the years ended December 31, 2011, 2010 and 2009, approximately $1 million $8 million and $16 million, respectively, of the fees have been amortized and reflected in interest expense.

In relation to the wind-down of its retail energy supply business, Pepco Energy Services in the ordinary course of business has entered into various contracts to buy and sell electricity, fuels and related products, including derivative instruments, designed to reduce its financial exposure to changes in the value of its assets and obligations due to energy price fluctuations. These contracts also typically have collateral requirements.

Depending on the contract terms, the collateral required to be posted by Pepco Energy Services can be of varying forms, including cash and letters of credit. As of December 31, 2011, Pepco Energy Services posted net cash collateral of $112 million and letters of credit of $1 million. At December 31, 2010, Pepco Energy Services posted net cash collateral of $117 million and letters of credit of $113 million.

At December 31, 2011 and 2010, the amount of cash, plus borrowing capacity under the primary credit facility available to meet the future liquidity needs of Pepco Energy Services totaled $283 million and $728 million, respectively.

Pension and Other Postretirement Benefit Plans

Based on the results of the 2011 actuarial valuation, PHI’s net periodic pension and OPEB costs were approximately $94 million in 2011 versus $116 million in 2010. The current estimate of benefit cost for 2012 is $103 million. The utility subsidiaries are responsible for substantially all of the total PHI net periodic pension and OPEB costs. Approximately 30% of net periodic pension and OPEB costs are capitalized. PHI estimates that its net periodic pension and OPEB expense will be approximately $72 million in 2012, as compared to $66 million in 2011 and $81 million in 2010.

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Pension benefits are provided under the PHI Retirement Plan, a non-contributory, defined benefit pension plan that covers substantially all employees of Pepco, DPL and ACE and certain employees of other PHI subsidiaries. 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.

During 2011, Pepco, DPL and ACE made discretionary tax-deductible contributions totaling $110 million to the PHI Retirement Plan, in the amounts of $40 million, $40 million and $30 million, respectively. In 2010, PHI Service Company made discretionary tax-deductible contributions totaling $100 million to the PHI Retirement Plan.

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. PHI satisfied the minimum required contribution rules under the Pension Protection Act in 2011, 2010 and 2009. On January 31, 2012, Pepco, DPL and ACE made discretionary tax-deductible contributions to the PHI Retirement Plan in the amounts of $85 million, $85 million and $30 million, respectively, which is expected to bring the PHI Retirement Plan assets to at least the funding target level for 2012 under the Pension Protection Act. For additional discussion of PHI’s Pension and Other Postretirement Benefits, see Note (10), “Pension and Other Postretirement Benefits,” to the consolidated financial statements of PHI.

Effective July 1, 2011, PHI approved revisions to certain of PHI’s existing benefit programs, including the PHI Retirement Plan. The changes to the PHI Retirement Plan were effected in order to establish a more unified approach to PHI’s retirement programs and to further align the benefits offered under PHI’s retirement programs. The changes to the PHI Retirement Plan were effective on or after July 1, 2011 and affect the retirement benefits payable to approximately 750 of PHI’s employees. All full-time employees of PHI and certain subsidiaries are eligible to participate in the PHI Retirement Plan. Retirement benefits for all other employees remain unchanged.

In the third quarter of 2011, PHI also approved a new, non-qualified Supplemental Executive Retirement Plan (SERP) which replaced PHI’s two pre-existing supplemental retirement plans, effective August 1, 2011. As of the effective date of the new SERP, the Conectiv SERP and the PHI Combined SERP were closed to new participants. The establishment of the new SERP is consistent with PHI’s efforts to align retirement benefits for PHI and its subsidiaries with current market practices and to provide similarly situated participants with retirement benefits that are the same or similar in value as compared to the benefits provided under the prior SERPs.

In the fourth quarter of 2011, PHI approved an increase in the medical benefit limits for certain employees in its postretirement health care benefit plan to align the limits with those provided to other employees. The amendment affects approximately 1,400 employees, of which 400 are retirees and 1,000 are active union employees. The effective date of the plan modification was January 1, 2012.

The additional liabilities and expenses for the benefit plan modifications described above did not have a material impact on PHI’s overall consolidated financial condition, results of operations, or cash flows.

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Cash Flow Activity

PHI’s cash flows during 2011, 2010 and 2009 are summarized below:

	Cash Source (Use)
	2011			2010			2009
	(millions of dollars)
Operating Activities	$	686		$	813		$	606
Investing Activities		(747	)		718			(860	)
Financing Activities		149			(1,556	)		(84	)
Net increase (decrease) in cash and cash equivalents	$	88		$	(25	)	$	(338	)

Operating Activities

Cash flows from operating activities during 2011, 2010 and 2009 are summarized below:

	Cash Source (Use)
	2011			2010			2009
	(millions of dollars)
Net Income from continuing operations	$	260		$	139		$	223
Non-cash adjustments to net income		351			352			262
Pension contributions		(110	)		(100	)		(300	)
Changes in cash collateral related to derivative activities		9			13			24
Changes in other assets and liabilities		134			161			294
Changes in Conectiv Energy net assets held for sale		42			248			103
Net cash from operating activities	$	686		$	813		$	606

Net cash from operating activities was $127 million lower for the year ended December 31, 2011, compared to the same period in 2010. The decrease was due primarily to a $206 million reduction in Conectiv Energy net assets held for sale as well as $10 million increase in pension contributions compared to 2010. A significant portion of the decline in Conectiv Energy assets held for sale was associated with the transfer of derivative instruments to a third party as further described in Note (20), “Discontinued Operations,” to the consolidated financial statements of PHI. Partially offsetting this decrease in operating cash flows was a $121 million increase in cash flows from continuing operations.

Net cash from operating activities was $207 million higher for the year ended December 31, 2010, compared to the same period in 2009. Portions of the increase are attributable to a 2010 decrease in pension plan contributions of $200 million compared to 2009 and a decrease in regulatory liabilities during 2010 that was the result of a lower rate of recovery by ACE of costs associated with energy and capacity purchased under the NUG contracts. Changes in cash from Conectiv Energy assets held for sale reflect a net decrease in Conectiv Energy assets and liabilities included in discontinued operations, including a decrease in collateral requirements as a result of the liquidation of derivative instruments.

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Investing Activities

Cash flows used by investing activities during 2011, 2010 and 2009 are summarized below:

	Cash (Use) Source
	2011			2010			2009
	(millions of dollars)
Investment in property, plant and equipment	$	(941	)	$	(802	)	$	(664	)
DOE capital reimbursement awards received		52			13			—
Proceeds from early termination of finance leases held in trust		161			—			—
Proceeds from sale of Conectiv Energy wholesale power generation business		—			1,640			—
Proceeds from sale of assets		—			3			4
Changes in restricted cash equivalents		(10	)		(2	)		—
Net other investing activities		(9	)		4			—
Investment in property, plant and equipment associated with Conectiv Energy assets held for sale		—			(138	)		(200	)
Net cash (used by) from investing activities	$	(747	)	$	718		$	(860	)

Net cash from investing activities decreased $1,465 million for the year ended December 31, 2011 compared to the same period in 2010. The decrease was due primarily to the $1,640 million in proceeds from the sale of the Conectiv Energy wholesale power generation business and $139 million increase in capital expenditures, partially offset by the $161 million of proceeds from the early termination of certain cross-border energy lease investments in 2011.

Net cash from investing activities increased $1,578 million for the year ended December 31, 2010 compared to the same period in 2009. The increase was due primarily to the $1,640 million proceeds from the sale of the Conectiv Energy wholesale power generation business offset by a $138 million increase in capital expenditures primarily attributable to capital costs associated with transmission plant investment and PHI’s Blueprint for the Future initiatives.

Financing Activities

Cash flows from financing activities during 2011, 2010 and 2009 are summarized below.

	Cash (Use) Source
	2011			2010			2009
	(millions of dollars)
Dividends paid on common stock	$	(244	)	$	(241	)	$	(238	)
Common stock issued for the Dividend Reinvestment Plan and employee-related compensation		47			47			49
Redemption of preferred stock of subsidiaries		(6	)		—			—
Issuances of long-term debt		235			383			110
Reacquisitions of long-term debt		(70	)		(1,726	)		(83	)
Issuances of short-term debt, net		198			4			65
Cost of issuances		(10	)		(7	)		(4	)
Net other financing activities		(1	)		(6	)		10
Net financing activities associated with Conectiv Energy assets held for sale		—			(10	)		7
Net cash from (used by) financing activities	$	149		$	(1,556	)	$	(84	)

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Net cash related to financing activities increased $1,705 million for the year ended December 31, 2011 compared to the same period in 2010 primarily due to a $1,656 million decrease in reacquisitions of long-term debt in 2011 as a result of debt extinguishments in 2010.

Net cash related to financing activities decreased $1,472 million for the year ended December 31, 2010 compared to the same period in 2009 primarily due to the retirement of $1,643 million of long-term debt using the proceeds from the sale of the Conectiv Energy wholesale power generation business.

Common Stock Dividends

Common stock dividend payments were $244 million in 2011, $241 million in 2010, and $238 million in 2009. The increase in common stock dividends paid in 2011 and 2010 was the result of additional shares outstanding, primarily shares issued under the Shareholder Dividend Reinvestment Plan (DRP).

Changes in Outstanding Common Stock

Under the DRP, PHI issued 1.6 million shares of common stock in 2011, 1.8 million shares of common stock in 2010, and 2.2 million shares of common stock in 2009.

Changes in Outstanding Long-Term Debt

Cash flows from the issuance and reacquisition of long-term debt in 2011, 2010 and 2009 are summarized in the charts below:

	2011		2010		2009
Issuances	(millions of dollars)
PHI
2.70% senior notes due 2015	$	—	$	250	$	—
		—		250		—
Pepco
6.20% tax-exempt bonds due 2022 (a)		—		—		110
		—		—		110
DPL
0.75% tax-exempt bonds due 2026 (b)		35		—		—
5.40% tax-exempt bonds due 2031 (c)		—		78		—
1.80% tax-exempt bonds due 2025 (d)		—		15		—
2.30% tax-exempt bonds due 2028 (d)		—		16		—
		35		109		—
ACE
4.35% First mortgage bonds due 2021		200		—		—
4.875% tax-exempt bonds due 2029 (e)		—		23		—
		200		23		—
Pepco Energy Services		—		1		—
	$	235	$	383	$	110

(a) Consists of Pollution Control Revenue Refunding Bonds (Pepco 2022 Bonds) issued by the Maryland Economic Development Corporation for the benefit of Pepco that were purchased by Pepco in 2008. In connection with their resale by Pepco, the interest rate on the Pepco 2022 Bonds was changed from an auction rate to a fixed rate. The Pepco 2022 Bonds are secured by an outstanding series of senior notes issued by Pepco, and the senior notes are in turn secured by a series of collateral first mortgage bonds (Collateral First Mortgage Bonds) issued by Pepco. Both the senior notes and the Collateral First Mortgage Bonds have maturity dates, optional and mandatory redemption provisions, interest rates and interest payment dates that are identical to the terms of the Pepco 2022 Bonds. The payment by Pepco of its obligations with respect to the Pepco 2022 Bonds satisfies the corresponding payment obligations on the senior notes and Collateral First Mortgage Bonds. See Note (11), “Debt,” to the consolidated financial statements of PHI.

(b) Consists of Pollution Control Refunding Revenue Bonds issued by the Delaware Economic Development Authority (DEDA) for the benefit of DPL that were purchased by DPL in May 2011. See footnote (b) to the Reacquisitions table below. These bonds were resold to the public in June 2011.

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(c) Consists of Gas Facilities Refunding Revenue Bonds issued by DEDA for the benefit of DPL.

(d) Consists of Pollution Control Refunding Revenue Bonds issued by DEDA for the benefit of DPL that were purchased by DPL in July 2010. See footnote (c) to the Reaquisitions table below. The bonds were resold to the public in December 2010. While DPL held the bonds, they remained outstanding as a contractual matter, but were considered extinguished for accounting purposes. In connection with the resale of the bonds, the interest rate on the bonds was changed (i) from 5.50% to a fixed rate of 1.80% with respect to the tax-exempt bonds due 2025 and (ii) from 5.65% to a fixed rate of 2.30% with respect to the tax-exempt bonds due 2028. The bonds are subject to mandatory purchase by DPL on June 1, 2012.

(e) Consists of Pollution Control Revenue Refunding Bonds (ACE Bonds) issued by The Pollution Control Financing Authority of Salem County for the benefit of ACE that were purchased by ACE in 2008. In connection with the resale by ACE, the interest rate on the ACE Bonds was changed from an auction rate to a fixed rate. The ACE Bonds are secured by an outstanding series of senior notes issued by ACE, and the senior notes are in turn secured by a series of Collateral First Mortgage Bonds issued by ACE. Both the senior notes and the Collateral First Mortgage Bonds have maturity dates, optional and mandatory redemption provisions, interest rates and interest payment dates that are identical to the terms of the ACE Bonds. The payment by ACE of its obligations with respect to the ACE Bonds satisfies the corresponding payment obligations on the senior notes and Collateral First Mortgage Bonds. See Note (11), “Debt,” to the consolidated financial statements of PHI.

		2011		2010		2009
Reacquisitions		(millions of dollars)
PHI
	4.00% notes due 2010	$	—	$	200	$	—
	Floating rate notes due 2010		—		250		—
	6.45% senior notes due 2012		—		750		—
	5.90% senior notes due 2016		—		10		—
	6.125% senior notes due 2017		—		169		—
	6.00% senior notes due 2019		—		200		—
	7.45% senior notes due 2032		—		65		—
			—		1,644		—
Pepco
	5.75% tax-exempt bonds due 2010 (a)		—		16		—
	6.25% medium-term notes due 2009		—		—		50
			—		16		50
DPL
	4.90% tax-exempt bonds due 2026 (b)		35		—		—
	5.5% tax-exempt bonds due 2025 (c)		—		15		—
	5.65% tax-exempt bonds due 2028 (c)		—		16		—
			35		31		—
ACE
	7.25% medium-term notes due 2010		—		1		—
	Securitization bonds due 2009-2011		35		34		32
			35		35		32
Pepco Energy Services			—		—		1
		$	70	$	1,726	$	83

(a) Consists of Pollution Control Revenue Refunding Bonds (Pepco 2010 Bonds) issued by Prince George’s County for the benefit of Pepco. The Pepco 2010 Bonds were secured by an outstanding series of Collateral First Mortgage Bonds issued by Pepco. The Collateral First Mortgage Bonds had maturity dates, optional and mandatory redemption provisions, interest rates and interest payment dates that were identical to the terms of the Pepco 2010 Bonds. Accordingly, the redemption of the Pepco 2010 Bonds at maturity automatically effected the redemption of the Collateral First Mortgage Bonds.

(b) Repurchased by DPL in May 2011 pursuant to a mandatory purchase provision in the indenture for the bonds. The bonds were resold by DPL in June 2011. See footnote (b) to the Issuances table above.

(c) Repurchased by DPL in July 2010 pursuant to a mandatory repurchase provision in the indenture for the bonds that was triggered by the expiration of the original interest period for the bonds. The bonds were resold by DPL in December 2010. See footnote (d) to the Issuances table above.

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Purchase and Resale of Tax-Exempt Auction Rate Bonds

On June 1, 2011, DPL resold $35 million of Pollution Control Refunding Revenue Bonds (Delmarva Power & Light Company Project) Series 2001C due 2026 (the Series 2001C Bonds). The Series 2001C Bonds were issued for the benefit of DPL in 2001 and were repurchased by DPL on May 2, 2011, pursuant to a mandatory repurchase provision in the indenture for the Series 2001C Bonds triggered by the expiration of the original interest rate period specified by the Series 2001C Bonds. See footnote (b) to the Reacquisitions table above.

In connection with the issuance of the Series 2001C Bonds, DPL entered into a continuing disclosure agreement under which it is obligated to furnish certain information to the bondholders. At the time of the resale, the continuing disclosure agreement was amended and restated to designate the Municipal Securities Rulemaking Board as the sole repository for these continuing disclosure documents. The amendment and restatement of the continuing disclosure agreement did not change the operating or financial data that are required to be provided by DPL under such agreement.

On April 5, 2011, ACE issued $200 million of 4.35% first mortgage bonds due April 1, 2021. The net proceeds were used to repay short-term debt and for general corporate purposes.

In 2010, DEDA issued $78 million of 5.40% Gas Facilities Refunding Revenue Bonds due 2031 for the benefit of DPL. The proceeds were used by DPL to redeem $78 million in principal amount of Exempt Facilities Refunding Revenue Bonds issued by DEDA purchased in 2008. See footnote (c) to the Issuances table above. In March 2010, $23 million in aggregate principal amount of Pollution Control Revenue Refunding Bonds were resold by ACE to the public. See footnote (e) to the Issuances table above.

In 2009, Pepco resold Pollution Control Revenue Refunding Bonds issued by the Maryland Economic Development Corporation in the aggregate principal amount of $110 million. See footnote (a) to the Issuances table above. In 2009, ACE redeemed $32 million in Pollution Control Revenue Refunding Bonds.

Changes in Short-Term Debt

As of December 31, 2011, PHI had a total of $586 million of commercial paper outstanding as compared to $388 million and $384 million of commercial paper outstanding at December 31, 2010 and 2009, respectively.

In 2008 and 2009, the following insured Variable Rate Demand Bonds (VRDBs) issued by The Pollution Control Financing Authority of Salem County for the benefit of ACE were tendered to The Bank of New York Mellon, bond trustee, by the holders and purchased by The Bank of New York Mellon pursuant to standby bond purchase agreements for the respective series:

• $18.2 million of Pollution Control Revenue Refunding Bonds 1997 Series A due 2014 (ACE 1997A Bonds), and

• $4.4 million of Pollution Control Revenue Refunding Bonds 1997 Series B due 2017 (ACE 1997B Bonds).

In June 2009, the ACE VRDBs were resold to the public. In connection with this remarketing, the financial guaranty insurance policies issued as credit support for the ACE VRDBs were cancelled and replaced with letters of credit. In June 2010, the letters of credit expired and were replaced with new irrevocable direct pay letters of credit. The new letter of credit supporting the ACE 1997A Bonds expires in April 2014 and the new letter of credit for the ACE 1997B Bonds expires in June 2013. The expiration, cancellation, or termination of a letter of credit prior to the maturity of the related VRDBs will require ACE to repurchase the corresponding series of ACE VRDBs.

For a further description of the VRDBs issued by or for the benefit of PHI’s utility subsidiaries, see Note (11), “Debt,” to the consolidated financial statements of PHI.

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Capital Requirements

Capital Expenditures

Pepco Holdings’ capital expenditures for the year ended December 31, 2011 totaled $941 million, up $139 million versus $802 million in 2010. Capital expenditures in 2011 were $521 million for Pepco, $229 million for DPL, $138 million for ACE, $14 million for Pepco Energy Services and $39 million for Corporate and Other. The Power Delivery expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission. 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 2012 through 2016. Pepco Holdings expects to fund these expenditures through internally generated cash and external financing.

	For the Year
	2012			2013			2014		2015		2016		Total
	(millions of dollars)
Power Delivery
Distribution	$	601		$	679		$	729	$	689	$	711	$	3,409
Distribution – Blueprint for the Future		120			3			—		9		92		224
Transmission		305			260			278		255		258		1,356
Transmission – MAPP		5			2			2		6		190		205
Gas Delivery		22			23			23		25		27		120
Other		140			80			50		39		49		358
Sub-Total		1,193			1,047			1,082		1,023		1,327		5,672
DOE Capital Reimbursement Awards (a)		(50	)		(3	)		—		—		—		(53	)
Total for Power Delivery		1,143			1,044			1,082		1,023		1,327		5,619
Pepco Energy Services		14			7			7		7		7		42
Corporate and Other		3			3			3		3		3		15
Total PHI	$	1,160		$	1,054		$	1,092	$	1,033	$	1,337	$	5,676

(a) Reflects remaining anticipated reimbursements pursuant to awards from the U.S. Department of Energy (DOE) under the American Recovery and Reinvestment Act of 2009.

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Transmission and Distribution

The projected capital expenditures listed in the table for distribution (other than Blueprint for the Future), transmission (other than the MAPP project) 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—Reliability Enhancement and Emergency Restoration Improvement Plans.”

Infrastructure Investment Plan

In 2009, the NJBPU approved ACE’s proposed Infrastructure Investment Plan and the revenue requirement associated with recovering the cost of the related projects, subject to a prudency review in the next rate case. The approved projects were designed to enhance reliability of ACE’s distribution system and support economic activity and job growth in New Jersey in the near term. ACE was granted cost recovery through an Infrastructure Investment Surcharge, which became effective on June 1, 2009. This approved plan was completed in 2011 and has added incremental capital spending of approximately $28 million since 2009. In 2011, ACE proposed a new Infrastructure Investment Plan that if approved by the NJBPU, would be expected to add an additional $63 million of capital spending for 2012, which is included in Distribution in the table above.

Blueprint for the Future

Each of PHI’s utility subsidiaries have undertaken programs to install smart meters, further automate their electric distribution systems and enhance their communications infrastructure, which is referred to as the Blueprint for the Future. For a discussion of the Blueprint for the Future initiative, see “General Overview—Blueprint for the Future.” The projected capital expenditures over the next five years are shown as Distribution—Blueprint for the Future in the table above.

MAPP Project

PJM has approved the construction of a new 152-mile, interstate transmission line as part of PJM’s regional transmission expansion plan. In August 2011, PJM notified PHI that the scheduled in-service date for MAPP has been delayed from June 1, 2015 to the 2019 to 2021 time period. The projected capital expenditures over the next five years are shown as Transmission—MAPP in the table above.

MAPP/DOE Loan Program

To assist in the funding of the MAPP project, PHI has applied for a $684 million loan guarantee from the DOE for a substantial portion of the MAPP project, primarily the Calvert Cliffs to Indian River segment. The application has been made under a federal loan guarantee program for projects that employ innovative energy efficiency, renewable energy and advanced transmission and distribution technologies. If granted, PHI believes the guarantee could allow PHI to acquire financing at a

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lower cost than it would otherwise be able to obtain in the capital markets. Whether PHI’s application will be granted and, if so, the amount of debt guaranteed is subject to the discretion of the DOE and the negotiation of terms that will satisfy the conditions of the guarantee program. On February 28, 2011, the DOE issued a Notice of Intent to prepare an Environmental Impact Statement to assist the DOE in assessing the environmental impact of constructing the portion of the MAPP project to be supported by the loan guarantee. Since February 2011, the DOE has conducted field inspections of the entire route and has held public meetings to obtain input from the communities along the route.

The DOE’s review of the loan guarantee program has delayed the DOE’s review of PHI’s loan guarantee application. There is not an approval deadline under the loan guarantee program, but this program could change or be terminated in the future. PHI continues to coordinate environmental activities with the DOE.

DOE Capital Reimbursement Awards

In 2009, the 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 advanced metering infrastructure system, direct load control, distribution automation, and communications infrastructure.

• $19 million to ACE for the implementation of direct load control, distribution automation, and communications infrastructure in its New Jersey service territory.

In April 2010, PHI and the DOE signed agreements formalizing the $168 million in awards. Of the $168 million, $130 million is expected to offset incurred and projected Blueprint for the Future and other capital expenditures of Pepco and ACE. The remaining $38 million will be used to offset incremental expenses associated with direct load control and other Pepco and ACE programs. In 2011, Pepco received award payments of $53 million and ACE received award payments of $6 million. In 2010, Pepco received award payments of $15 million and ACE received award payments of $2 million.

The IRS has announced that, to the extent these grants are expended on capital items, they will 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 2011, PHI’s Board of Directors declared quarterly dividends of 27 cents per share of common stock payable on March 31, 2011, June 30, 2011, September 30, 2011 and December 31, 2011.

On January 26, 2012, the Board of Directors declared a dividend on common stock of 27 cents per share payable March 30, 2012, to shareholders of record on March 12, 2012.

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. 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 $1,072 million and $1,059 million of retained earnings free of restrictions at December 31, 2011 and 2010, 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, 2011, is as follows:

	Contractual Maturity
Obligation	Total		Less than 1 Year		1-3 Years		3-5 Years		After 5 Years
	(millions of dollars)
Variable Rate Demand Bonds	$	146	$	146	$	—	$	—	$	—
Commercial paper		586		586		—		—		—
Long-term debt (a)		4,211		111		892		747		2,461
Long-term project funding		15		2		4		3		6
Interest payments on debt		3,162		244		441		365		2,112
Capital leases		121		15		30		30		46
Operating leases		530		39		71		61		359
Estimated pension and OPEB plan contributions		235		235		—		—		—
Non-derivative fuel and purchase power contracts (b)		4,102		553		716		708		2,125
Total (c)	$	13,108	$	1,931	$	2,154	$	1,914	$	7,109

(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 $180 million of net non-current liabilities related to uncertain tax positions due to uncertainty in the timing of the associated cash payments.

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 of December 31, 2011, PHI and its subsidiaries were parties to a variety of agreements pursuant to which they were guarantors for standby letters of credit, energy procurement obligations, and other commitments and obligations. Such agreements include performance and payment guarantees of PHI aggregating $175 million related to Pepco Energy Services. For additional discussion of PHI’s third party guarantees, indemnifications, obligations and off-balance sheet arrangements, see Note (17), “Commitments and Contingencies,” to the consolidated financial statements of PHI.

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Energy Contract Activity

The following table provides detail on changes in the net asset or liability positions of the Pepco Energy Services segment with respect to energy commodity contracts for the year ended December 31, 2011. The balances in the table are pre-tax and the derivative assets and liabilities reflect netting by counterparty before the impact of collateral.

	Energy Commodity Activities (a)
	(millions of dollars)
Total Fair Value of Energy Contract Net Liabilities at December 31, 2010	$	(135	)
Current period unrealized losses		(30	)
Effective portion of changes in fair value—recorded in Accumulated Other Comprehensive Loss		—
Cash flow hedge ineffectiveness—recorded in income		(1	)
Reclassification to realized on settlement of contracts		83
Total Fair Value of Energy Contract Net Liabilities at December 31, 2011	$	(83	)
Detail of Fair Value of Energy Contract Net Liabilities at December 31, 2011 (see above)
Derivative liabilities (current liabilities)	$	(81	)
Derivative liabilities (non-current liabilities)		(2	)
Total Fair Value of Energy Contract Liabilities		(83	)
Total Fair Value of Energy Contract Net Liabilities	$	(83	)
(a)     Includes all effective hedging activities from continuing operations recorded at fair value through Accumulated Other Comprehensive Loss (AOCL) or trading activities from continuing operations recorded at fair value in the consolidated statements of income.

The $83 million net liability on energy contracts at December 31, 2011 was primarily attributable to losses on power swaps and natural gas futures held by Pepco Energy Services. Pepco Energy Services’ net liability decreased to $83 million at December 31, 2011 from $135 million at December 31, 2010 primarily due to settlements of the derivatives. PHI expects that future revenues from existing customer sales obligations that are accounted for on an accrual basis will largely offset expected realized net losses on Pepco Energy Services’ energy contracts.

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PHI uses its best estimates to determine the fair value of the commodity derivative contracts that are entered into by Pepco Energy Services. The fair values in each category presented below reflect forward prices and volatility factors as of December 31, 2011, and the fair values are subject to change as a result of changes in these prices and factors. As of December 31, 2011, all of these contracts were held by Pepco Energy Services.

	Fair Value of Contracts at December 31, 2011 Maturities
Source of Fair Value	2012			2013			2014			2015 and Beyond		Total Fair Value
	(millions of dollars)
Energy Commodity Activities, net (a)
Actively Quoted (i.e., exchange-traded) prices	$	(37	)	$	(9	)	$	(2	)	$	—	$	(48	)
Prices provided by other external sources (b)		(26	)		(7	)		—			—		(33	)
Modeled (c)		(2	)		—			—			—		(2	)
Total	$	(65	)	$	(16	)	$	(2	)	$	—	$	(83	)

(a) Includes all effective hedging activities recorded at fair value through AOCL, and hedge ineffectiveness and trading activities on the statements of income, as required.

(b) Prices provided by other external sources reflect information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms that are readily observable in the market.

(c) Modeled values include significant inputs, usually representing more than 10% of the valuation, not readily observable in the market. The modeled valuation above represents the fair valuation of certain long-dated power transactions based on limited observable broker prices extrapolated for periods beyond two years into the future.

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, 2011, a downgrade in the unsecured debt credit ratings of PHI or each of its rated subsidiaries to below “investment grade” would increase the collateral obligation of PHI and its subsidiaries by up to $233 million, none of which is related to the discontinued operations of Conectiv Energy, and $124 million of which is the net settlement amount attributable to derivatives, normal purchase and normal sale contracts, collateral, and other contracts under master netting agreements as described in Note (15), “Derivative Instruments and Hedging Activities,” to the consolidated financial statements of PHI. The remaining $109 million of the collateral obligation that would be incurred in the event PHI were downgraded to below “investment grade” is attributable primarily to energy services contracts and accounts payable to independent system operators and distribution companies on full requirements contracts entered into by Pepco Energy Services. 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 competitive energy and 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. As of December 31, 2011, Pepco Energy Services provided net cash collateral in the amount of $112 million in connection with these activities.

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Environmental Remediation Obligations

PHI’s accrued liabilities for environmental remediation obligations as of December 31, 2011 totaled $30 million, of which approximately $6 million is expected to be incurred in 2012, 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 (17), “Commitments and Contingencies,” to the consolidated financial statements of PHI. For information regarding projected expenditures for environmental control facilities, see “Business—Environmental Matters.” The most significant environmental remediation obligations as of December 31, 2011, are for the following items:

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

• 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.

• 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

Pepco Holdings’ 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, 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. See “Risk Factors,” for additional discussion of important factors that may impact these sources of capital.

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 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.

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As of December 31, 2011, Pepco Holdings, Pepco, DPL and ACE each maintains an ongoing commercial paper program pursuant to which each entity has the ability to issue up to $875 million, $500 million, $500 million and $250 million, respectively, of commercial paper. In January 2012, the PHI Board of Directors approved an increase in the maximum amount of commercial paper that PHI is authorized to issue under its commercial paper program to $1.25 billion. The commercial paper can be issued with maturities of up to 270 days.

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 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.

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 a 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. Borrowings from the money pool are unsecured. 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.

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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 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 (New Jersey, Maryland, Delaware and the District of Columbia); a surcharge to pay the Transitional Bond Charge (New Jersey); and surcharges to reimburse the utility for certain environmental costs (Delaware and Maryland).

Each utility subsidiary regularly reviews its distribution rates in each jurisdiction of its service territory, and from time to time 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. In the third quarter of 2011, Pepco filed an electric distribution base rate increase application in the District of Columbia and ACE filed an electric distribution base rate increase application in New Jersey. In the fourth quarter of 2011, DPL filed an electric distribution base rate increase application in Delaware and Maryland. Also in the fourth quarter of 2011, Pepco filed an electric distribution base rate increase application in Maryland. DPL currently expects to file a natural gas distribution base rate increase application in early 2013.

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 company. 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.

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If revenues do not keep pace with increases in costs, this situation will result in a lag between when the costs are incurred and when the utility can begin to recover those costs through its rates.

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 date as of which the rate as determined in the proceeding was implemented:

Rate Base (In millions)	Authorized Return on Equity	Rate Effective Date
Pepco:
District of Columbia (electricity)	9.625%	March 2010
Maryland (electricity)	9.83%	August 2010
DPL:
Delaware (electricity)	10.00%	April 2010
Maryland (electricity)	Not specified(a)	July 2011
Delaware (natural gas)	10.00%	February 2011
ACE:
New Jersey (electricity)	10.30%	June 2010
(a)     Cost of equity at 10% for purposes of calculating allowance for funds used during construction and regulatory asset carrying costs.

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 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. In connection with the MAPP project, FERC has authorized for each of Pepco and DPL a 150 basis point adder to its return on equity, resulting in a FERC-approved rate of return on the MAPP project of 12.8%, along with full recovery of construction work in progress and prudently incurred abandoned plant costs. Additional return on equity adders are in effect for each of Pepco, DPL and ACE relating to specific transmission upgrades and improvements, as well as in consideration for each utility’s continued membership in PJM. As members of PJM, the transmission rates of Pepco, DPL and ACE are set out in PJM’s Open Access Transmission Tariff.

For a discussion of pending state public utility commission and FERC rate proceedings, see Note (7), “Regulatory Matters,” to the consolidated financial statements of PHI.

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Legal Proceedings and Regulatory Matters

For a discussion of legal proceedings, see Note (17), “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 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 operations 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). Management has identified Power Delivery as a single reporting unit because its components have similar economic characteristics, similar products and services and operate in a similar regulatory environment.

PHI tests its goodwill impairment at least annually as of November 1 and on an interim basis if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Factors that may result in an interim impairment test include, but are not limited to: a change in identified reporting units; an adverse change in business conditions; a protracted decline in stock price causing market capitalization to fall below book value; an adverse regulatory action; or impairment of long-lived assets in the reporting unit.

The first step of the goodwill impairment test compares the fair value of the reporting unit with its carrying amount, including goodwill. Management uses its best judgment to make reasonable projections of future cash flows for Power Delivery when estimating the reporting unit’s fair value. In addition, PHI selects a discount rate for the associated risk with those estimated cash flows. 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, 2011 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 uses two valuation techniques: an income approach and a market approach. The income approach estimates fair value based on a discounted cash flow analysis using estimated future cash flows 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 market-based information for the cost of equity and cost of debt that is appropriate for Power Delivery 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 management believes is consistent with EBITDA multiples for comparable utilities. PHI has consistently used this valuation framework to estimate the fair value of Power Delivery.

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The estimation of fair value is dependent on a number of factors that are sourced from the Power Delivery reporting unit’s business forecast, 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 and methodologies used in the models were consistent with historical experience. A hypothetical 10 percent decrease in fair value of the Power Delivery reporting unit at November 1, 2011 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 cost of capital, and other factors.

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 management makes assumptions and judgments, and the impact of a change in 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 management 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 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. In order to estimate an asset’s future cash flows, PHI considers historical cash flows. PHI uses its best estimates in making these evaluations and considers various factors, including forward price curves for energy, fuel costs, legislative initiatives, and operating costs. If necessary, the process of determining fair value is performed consistently with the process described in assessing the fair value of goodwill discussed above.

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Accounting for Derivatives

PHI believes that the estimates involved in accounting for its derivative instruments represent “Critical Accounting Estimates” because management exercises judgment in the following areas, any of which could have a material impact on its financial statements: (i) the application of the definition of a derivative to contracts to identify derivatives, (ii) the election of the normal purchases and normal sales exception from derivative accounting, (iii) the application of cash flow hedge accounting, and (iv) the estimation of fair value used in the measurement of derivatives and hedged items, which are highly susceptible to changes in value over time due to market trends or, in certain circumstances, significant uncertainties in modeling techniques used to measure fair value that could result in actual results being materially different from PHI’s estimates. See Note (2), “Significant Accounting Policies—Accounting for Derivatives,” and Note (15), “Derivative Instruments and Hedging Activities,” to the consolidated financial statements of PHI.

PHI and its subsidiaries use derivative instruments primarily to manage risk associated with commodity prices. The definition of a derivative in the FASB guidance results in management having to exercise judgment, such as whether there is a notional amount or net settlement provision in contracts. Management assesses a number of factors before determining whether it can designate derivatives for the normal purchase or normal sale exception from derivative accounting, including whether it is probable that the contracts will physically settle with delivery of the underlying commodity. The application of cash flow hedge accounting often requires judgment in the prospective and retrospective assessment and measurement of hedge effectiveness as well as whether it is probable that the forecasted transaction will occur. The fair value of derivatives is determined using quoted exchange prices where available. For instruments that are not traded on an exchange, external broker quotes are used to determine fair value. For some custom and complex instruments, internal models use market information when external broker quotes are not available. For certain long-dated instruments, broker or exchange data is extrapolated for future periods where information is limited. Models are also used to estimate volumes for certain transactions. The same valuation methods are used for risk management purposes to determine the value of non-derivative, commodity exposure.

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 plans and would have an impact on the projected benefit obligations, which affect the reported amount of annual net periodic pension and OPEB cost on the 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 and participant compensation have a significant impact on employee benefit costs.

The discount rate for determining the pension benefit obligation was 5.00% and 5.65% as of December 31, 2011 and 2010, respectively. The discount rate for determining the postretirement benefit obligation was 4.90% and 5.60% as of December 31, 2011 and 2010, 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 plan assets was 7.75% and 8.00% as of December 31, 2011 and 2010, respectively. 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 the related asset class. The plan assets consist of equity, fixed income, real estate and private equity investments. The plan assets are expected to yield a return on assets of 7.75% as of December 31, 2011 when viewed over a long-term horizon.

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The following table reflects the effect on the projected benefit obligation for the pension plan and the accumulated benefit obligation for the OPEB plan, as well as the net periodic cost for both plans, 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 2011 Net Periodic Cost
Pension Plan
Discount rate		(0.25	)%	$	61		$	5
Expected return		(0.25	)%		—	(a)		5
Postretirement Benefit Plan
Discount rate		(0.25	)%	$	20		$	1
Expected return		(0.25	)%		—	(a)		1
Health care cost trend rate		1.00	%		32			2
(a)     A change in the expected return assumption has no impact on the Projected Benefit Obligation.

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

For additional discussion, see Note (10), “Pension and Other Postretirement Benefits,” to the consolidated financial statements of PHI.

Accounting for Regulated Activities

FASB guidance on the accounting for regulated activities, 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 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 activities represent “Critical Accounting Estimates” because (i) management 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 management 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.

Management’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, management 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. Management 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.

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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 management is required to make assumptions and judgments about input 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 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 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 requires it to estimate future effective tax rates and future taxable income on its federal and state tax returns; (vi) it asserts that foreign earnings will continue to be indefinitely reinvested abroad; (vii) it must consider the effect of newly enacted tax law on its estimated effective tax rate and in measuring deferred tax balances; and (viii) 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” standard (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” standard quarterly.

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PHI also evaluates quarterly the probability of realizing deferred tax assets by reviewing a forecast of future taxable income and 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 by PHI and its subsidiaries or that one or more of the companies will be required to adopt on or before a specified date in the future, 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 Montgomery County and Prince George’s 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 energy supplier. Default Electricity Supply is known as SOS in both the District of Columbia and Maryland. Pepco’s service territory covers approximately 640 square miles and has a population of approximately 2.2 million. As of December 31, 2011, approximately 57% of delivered electricity sales were to Maryland customers and approximately 43% were to the District of Columbia customers.

For retail customers of Pepco in Maryland and in the District of Columbia, earnings are not affected by the warmest and coldest periods of the year because a BSA for retail customers was implemented that recognizes distribution revenue based on an approved distribution charge per customer. Consequently, distribution revenue recognized is decoupled in a reporting period from the amount of power delivered during the period and the only factors that will cause distribution revenue recognized 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 (such as 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 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 PHI and Pepco and certain activities of Pepco are subject to FERC’s regulatory oversight under PUHCA 2005.

Reliability Enhancement and Emergency Restoration Improvement Plans

In 2010, Pepco announced that it had adopted and begun to implement comprehensive reliability enhancement plans in Maryland and the District of Columbia. These reliability enhancement plans include various initiatives to improve electrical system reliability, such as:

• enhanced vegetation management;

• the identification and upgrading of under-performing feeder lines;

• the addition of new facilities to support load;

• the installation of distribution automation systems on both the overhead and underground network system;

• the rejuvenation and replacement of underground residential cables;

• improvements to substation supply lines; and

• selective undergrounding of portions of existing above ground primary feeder lines, where appropriate to improve reliability.

During 2011, Pepco invested $120 million in capital expenditures on these reliability enhancement activities.

In 2011, prior to the start of the summer storm season, Pepco initiated a program to improve its emergency restoration efforts that included, among other initiatives, an expansion and enhancement of customer service capabilities.

Blueprint for the Future

Pepco is participating in a PHI initiative referred to as “Blueprint for the Future,” which is designed to meet the challenges of rising energy costs, concerns about the environment, improved reliability and government energy reduction goals. For a discussion of the Blueprint for the Future initiative, see PHI’s “Management’s Discussion and Analysis of Financial Condition and Results of Operations – General Overview—Blueprint for the Future.”

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MAPP Project

PJM has approved PHI’s proposal to construct a new 152-mile, interstate transmission line as part of PJM’s regional transmission expansion plan. In August 2011, PJM notified PHI that the scheduled in-service date for MAPP has been delayed from June 1, 2015 to the 2019 to 2021 time period.

Regulatory Lag

An important factor in Pepco’s ability to earn its authorized rate of return is the willingness of applicable public service commissions to adequately recognize forward-looking costs in Pepco’s rate structure in order to minimize the shortfall in revenues 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 its investment in the rate base and its operating expenses are outpacing revenue growth. In its most recent rate cases, Pepco (in the District of Columbia and Maryland) has proposed mechanisms that would track reliability and other expenses and permit Pepco between rate cases to make adjustments in its rates for prudent investments as made, thereby seeking to reduce the magnitude of regulatory lag. There can be no assurance that these proposals or any other attempts by Pepco to mitigate regulatory lag will be approved, or that even if approved, the rate recovery mechanisms or any base rate cases will fully ameliorate the effects of regulatory lag. Until such time as these proposed mechanisms are approved, if necessary to address the problem of regulatory lag, Pepco plans to file rate cases at least annually in an effort to align more closely its revenue and related cash flow levels with other operation and maintenance spending and capital investments. In future rate cases, Pepco would also continue to seek cost recovery and tracking mechanisms from applicable regulatory commissions to reduce the effects of regulatory lag.

Results of Operations

The following results of operations discussion compares the year ended December 31, 2011 to the year ended December 31, 2010. All amounts in the tables (except sales and customers) are in millions of dollars.

Operating Revenue

	2011		2010		Change
Regulated T&D Electric Revenue	$	1,111	$	1,068	$	43
Default Electricity Supply Revenue		933		1,185		(252	)
Other Electric Revenue		34		35		(1	)
Total Operating Revenue	$	2,078	$	2,288	$	(210	)

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 territory 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.

Default Electricity Supply Revenue is the revenue received from the supply of electricity by Pepco at regulated rates to retail customers who do not elect to purchase electricity from a competitive energy supplier, and which is also known as SOS. 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 for approved regional transmission expansion plan costs.

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

	2011		2010		Change
Regulated T&D Electric Revenue
Residential	$	328	$	314	$	14
Commercial and industrial		647		631		16
Transmission and other		136		123		13
Total Regulated T&D Electric Revenue	$	1,111	$	1,068	$	43
	2011		2010		Change
Regulated T&D Electric Sales (GWh)
Residential		8,052		8,350		(298	)
Commercial and industrial		18,683		19,155		(472	)
Transmission and other		160		160		—
Total Regulated T&D Electric Sales		26,895		27,665		(770	)
	2011		2010		Change
Regulated T&D Electric Customers (in thousands)
Residential		714		713		1
Commercial and industrial		74		74		—
Transmission and other		—		—		—
Total Regulated T&D Electric Customers		788		787		1

Regulated T&D Electric Revenue increased by $43 million primarily due to:

• An increase of $13 million in transmission revenue primarily attributable to higher rates effective June 1, 2010 and June 1, 2011 related to increases in transmission plant investment.

• An increase of $12 million due to distribution rate increases in the District of Columbia effective March 2010 and July 2010; and in Maryland effective July 2010.

• An increase of $11 million due to higher pass-through revenue (which is substantially offset by a corresponding increase in Other Taxes) primarily the result of rate increases in Montgomery County, Maryland utility taxes that are collected by Pepco on behalf of the county.

• An increase of $6 million due to customer growth in 2011, primarily in the residential class.

• An increase of $2 million due to the implementation of the EmPower Maryland surcharge in March 2010 (which is substantially offset by a corresponding increase in Depreciation and Amortization).

Default Electricity Supply

	2011		2010		Change
Default Electricity Supply Revenue
Residential	$	668	$	865	$	(197	)
Commercial and industrial		257		309		(52	)
Other		8		11		(3	)
Total Default Electricity Supply Revenue	$	933	$	1,185	$	(252	)
	2011		2010		Change
Default Electricity Supply Sales (GWh)
Residential		6,770		7,576		(806	)
Commercial and industrial		2,854		3,113		(259	)
Other		8		10		(2	)
Total Default Electricity Supply Sales		9,632		10,699		(1,067	)

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	2011		2010		Change
Default Electricity Supply Customers (in thousands)
Residential		598		644		(46	)
Commercial and industrial		45		47		(2	)
Other Commercial and industrial		—		—		—
Total Default Electricity Supply Customers		643		691		(48	)

Default Electricity Supply Revenue decreased by $252 million primarily due to:

• A decrease of $135 million as a result of lower Default Electricity Supply rates.

• A decrease of $74 million due to lower sales, primarily as a result of residential and commercial customer migration to competitive suppliers.

• A decrease of $48 million due to lower sales as a result of cooler weather during the spring and summer months of 2011, and warmer weather during the fall months of 2011, as compared to the corresponding periods in 2010.

The aggregate amount of these decreases was partially offset by:

• An increase of $5 million due to higher non-weather related average customer usage.

• An increase of $3 million resulting from an approval by the DCPSC of an increase in Pepco’s cost recovery rate for providing Default Electricity Supply in the District of Columbia to provide for recovery of higher cash working capital costs incurred in prior periods. The higher cash working capital costs were incurred when the billing cycle for providers of Default Electricity Supply was shortened from a monthly to a weekly period, effective in June 2009.

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.

	2011			2010
Sales to District of Columbia customers		27	%		29	%
Sales to Maryland customers		43	%		46	%

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 $259 million to $893 million in 2011 from $1,152 million in 2010 primarily due to:

• A decrease of $162 million due to lower average electricity costs under Default Electricity Supply contracts.

• A decrease of $62 million primarily due to customer migration to competitive suppliers.

• A decrease of $45 million due to lower electricity sales primarily as a result of cooler weather during the spring and summer months of 2011, and warmer weather during the fall months of 2011, as compared to the corresponding periods in 2010.

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The aggregate amount of these decreases was partially offset by:

• An increase of $11 million in deferred electricity expense primarily due to lower Default Electricity Supply rates, which resulted in a higher rate of recovery of Default Electricity Supply costs.

Other Operation and Maintenance

Other Operation and Maintenance increased by $66 million to $420 million in 2011 from $354 million in 2010 primarily due to:

• An increase of $28 million associated with higher tree trimming and preventative maintenance costs.

• An increase of $13 million due to higher 2011 DCPSC rate case costs and reliability audit expenses and due to 2010 adjustments for the deferral of (i) February 2010 severe winter storm costs of $5 million and (ii) distribution rate case costs of $4 million that previously were charged to other operation and maintenance expense. The adjustments were recorded in accordance with a MPSC rate order issued in August 2010 and a DCPSC rate order issued in February 2010, allowing for the recovery of the costs.

• An increase of $8 million in customer support service and system support costs.

• An increase of $7 million primarily due to emergency restoration improvement project and reliability improvement costs.

• An increase of $5 million in communication costs.

• An increase of $4 million in employee-related costs, primarily benefit expenses.

• An increase of $3 million in outside legal counsel fees.

• An increase of $3 million in emergency restoration costs. The increase is primarily related to significant incremental costs incurred for repair work following Hurricane Irene in August 2011. Costs incurred for repair work were $12 million, of which $10 million was deferred as a regulatory asset to reflect the probable recovery of these storm costs in certain jurisdictions, and the remaining $2 million was charged to other operation and maintenance expense. Pepco currently plans to seek recovery of the incremental Hurricane Irene costs in each of its jurisdictions in pending or planned distribution rate case filings.

The aggregate amount of these increases was partially offset by:

• A decrease of $11 million in environmental remediation costs.

Restructuring Charge

As a result of PHI’s organizational review in the second quarter of 2010, Pepco’s operating expenses include a pre-tax restructuring charge of $15 million for the year ended December 31, 2010, related to severance and health and welfare benefits to be provided to terminated employees.

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Depreciation and Amortization

Depreciation and Amortization expense increased by $9 million to $171 million in 2011 from $162 million in 2010 primarily due to:

• An increase of $5 million due to utility plant additions.

• An increase of $3 million in amortization of regulatory assets primarily associated with the EmPower Maryland surcharge that became effective in March 2010 (which is substantially offset by a corresponding increase in Regulated T&D Electric Revenue).

• An increase of $1 million in the amortization of software upgrades to Pepco’s Energy Management System.

Other Taxes

Other Taxes increased by $18 million to $382 million in 2011 from $364 million in 2010. The increase was primarily due to:

• An increase of $16 million primarily due to rate increases in the Montgomery County, Maryland utility taxes that are collected and passed through by Pepco (substantially offset by a corresponding increase in Regulated T&D Electric Revenue).

• An increase of $5 million due to an adjustment in the third quarter of 2010 to correct certain errors related to other taxes.

The aggregate amount of these increases was partially offset by:

• A decrease of $5 million in the Energy Assistance Trust Fund surcharge primarily due to rate decreases effective October 2010 (substantially offset by a corresponding decrease in Regulated T&D Electric Revenue).

Effects of Divestiture-Related Claims

The DCPSC on May 18, 2010 issued an order addressing all of the outstanding issues relating to Pepco’s obligation to share with its District of Columbia customers the net proceeds realized by Pepco from the sale of its generation-related assets in 2000. This order disallowed certain items that Pepco had included in the costs it deducted in calculating the net proceeds of the sale. The disallowance of these costs, together with interest, increased the aggregate amount Pepco is required to distribute to customers by approximately $11 million. Pepco recognized a pre-tax expense of $11 million for the year ended December 31, 2010.

Other Income (Expenses)

Other Expenses (which are net of Other Income) decreased by $8 million to a net expense of $77 million in 2011 from a net expense of $85 million in 2010. The decrease was primarily due to:

• An increase of $8 million in income related to AFUDC that is applied to capital projects.

• An increase of $3 million in other income due to net proceeds from a company owned life insurance policy.

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The aggregate amount of these increases was partially offset by:

• A decrease of $3 million in other income due to gains on the sale of four parcels of land in 2010.

Income Tax Expense

Pepco’s effective tax rates for the years ended December 31, 2011 and 2010 were 26.7% and 25.5%, respectively. The increase in the effective tax rate primarily resulted from changes in estimates and interest related to uncertain and effectively settled tax positions offset by an increase in certain asset removal costs.

Income Tax Adjustments

During 2011, Pepco recorded an adjustment to correct certain income tax errors related to prior periods associated with the interest on uncertain tax positions. The adjustment resulted in an increase in income tax expense of $1 million for the year ended December 31, 2011.

In 2010, Pepco recorded certain adjustments to correct errors in income tax expense which resulted in an increase to income tax expense of $4 million for the year ended December 31, 2010.

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. See “Risk Factors,” for additional discussion of important factors that may have an effect on Pepco’s sources of capital.

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. 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 issued tax-exempt bonds through a municipality or public agency, the proceeds of which are loaned to Pepco by the municipality or agency.

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Information concerning the principal amount and terms of Pepco’s outstanding debt securities, as of December 31, 2011, is set forth in Note (10), “Debt,” to the financial statements of Pepco.

Bank Financing

As further discussed in Note (10), “Debt,” to the financial statements of Pepco, Pepco is a borrower under a $1.5 billion credit facility, along with PHI, DPL and ACE, which expires in 2016. 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 of up to $500 million under which it can issue commercial paper with maturities of up to 270 days. The commercial paper is backed by Pepco’s borrowing capacity under the $1.5 billion credit facility.

Pepco had $74 million of commercial paper outstanding at December 31, 2011 and zero outstanding at December 31, 2010. The weighted average interest rate for commercial paper issued during 2011 was 0.35%, and the weighted average maturity was two days. Pepco did not issue commercial paper during 2010.

Money Pool

Pepco participates in the money pool operated by PHI under authorization received from FERC. The money pool is a 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. Borrowings from the money pool are unsecured. 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 PHI may obtain 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, 2011 and 2010, 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.

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Capital Expenditures

Pepco’s capital expenditures for the year ended December 31, 2011 totaled $521 million. These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission. 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.

The following table shows Pepco’s projected capital expenditures for the five-year period 2012 through 2016. Pepco expects to fund these expenditures through internally generated cash, external financing and capital contributions from PHI.

	For the Year
	2012			2013			2014		2015		2016		Total
	(millions of dollars)
Pepco
Distribution	$	321		$	367		$	439	$	398	$	406	$	1,931
Distribution – Blueprint for the Future		76			1			—		—		—		77
Transmission		104			93			68		58		71		394
Transmission – MAPP		1			1			1		3		132		138
Other		56			30			17		13		18		134
Sub-Total		558			492			525		472		627		2,674
DOE Capital Reimbursement Awards (a)		(46	)		(2	)		—		—		—		(48	)
Total Pepco	$	512		$	490		$	525	$	472	$	627	$	2,626

(a) Reflects anticipated reimbursements pursuant to awards from the DOE under the American Recovery and Reinvestment Act of 2009.

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Transmission and Distribution

The projected capital expenditures listed in the table above for distribution (other than Blueprint for the Future) and transmission (other than the MAPP project) are primarily for facility replacements and upgrades to accommodate customer growth and service reliability, including capital expenditures for continuing reliability enhancement efforts.

Blueprint for the Future

Pepco has undertaken programs to install smart meters, further automate its electric distribution systems and enhance its communications infrastructure, which it refers to as the Blueprint for the Future. For a discussion of the Blueprint for the Future initiative, see PHI’s “Management’s Discussion and Analysis of Financial Condition and Results of Operations – General Overview—Blueprint for the Future.” The projected capital expenditures over the next five years are shown as Distribution—Blueprint for the Future in the table above.

MAPP Project

PJM has approved PHI’s proposal to construct a new 152-mile, interstate transmission line as part of PJM’s regional transmission expansion plan. In August 2011, PJM notified PHI that the scheduled in-service date for MAPP has been delayed from June 1, 2015 to the 2019 to 2021 time period. The projected capital expenditures over the next five years for MAPP are shown as Transmission—MAPP in the table above.

MAPP/DOE Loan Program

To assist in the funding of the MAPP project, PHI has applied for a $684 million loan guarantee from the DOE for a substantial portion of the MAPP project, primarily the Calvert Cliffs to Indian River segment. The application has been made under a federal loan guarantee program for projects that employ innovative energy efficiency, renewable energy and advanced transmission and distribution technologies. If granted, PHI believes the guarantee could allow PHI to acquire financing at a lower cost than it would otherwise be able to obtain in the capital markets. Whether PHI’s application will be granted and, if so, the amount of debt guaranteed is subject to the discretion of the DOE and the negotiation of terms that will satisfy the conditions of the guarantee program. On February 28, 2011, the DOE issued a Notice of Intent to prepare an Environmental Impact Statement to assist the DOE in assessing the environmental impact of constructing the portion of the MAPP project to be supported by the loan guarantee. Since February 2011, the DOE has conducted field inspections of the entire route and has held public meetings to obtain input from the communities along the route.

The DOE’s review of the loan guarantee program has delayed the DOE’s review of PHI’s loan guarantee application. There is not an approval deadline under the loan guarantee program, but this program could change or be terminated in the future. PHI continues to coordinate environmental activities with the DOE.

DOE Capital Reimbursement Awards

In 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.

In April 2010, PHI and the DOE signed agreements formalizing Pepco’s $149 million share of the $168 million award. Of the $149 million, $118 million is expected to offset incurred and projected Blueprint for the Future and other capital expenditures of Pepco. The remaining $31 million will be used to offset incremental expenses associated with direct load control and other programs. In 2011, Pepco received award payments of $53 million. In 2010, Pepco received award payments of $15 million.

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

Pension and Other Postretirement Benefit Plans

Pepco participates in pension and OPEB plans sponsored by PHI for its employees. Pepco contributed $40 million and zero to the PHI Retirement Plan during 2011 and 2010, respectively.

On January 31, 2012, Pepco made an $85 million discretionary tax-deductible contribution to the PHI Retirement Plan.

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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 Delaware and portions of Maryland. DPL 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 energy supplier. Default Electricity Supply is known as SOS in both Delaware and Maryland. DPL’s electricity distribution service territory covers approximately 5,000 square miles and has a population of approximately 1.4 million. As of December 31, 2011, approximately 66% of delivered electricity sales were to Delaware customers and approximately 34% 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 that purchase natural gas from other suppliers. DPL’s natural gas distribution service territory covers approximately 275 square miles and has a population of approximately 500,000.

In DPL’s Delaware service territory, 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, earnings are not affected by the warmest and coldest periods of the year because a BSA for retail customers was implemented that recognizes distribution revenue based on an approved distribution charge per customer. Consequently, distribution revenue recognized is decoupled in a reporting period from the amount of power delivered during the period and the only factors that will cause distribution revenue recognized 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 comparable revenue decoupling mechanism for DPL electricity and natural gas customers in Delaware is under consideration by the DPSC. Changes in customer usage (such as 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 PHI is a public utility holding company subject to PUHCA 2005, the relationship between PHI and DPL and certain activities of DPL are subject to FERC’s regulatory oversight under PUHCA 2005.

Blueprint for the Future

DPL is participating in a PHI initiative referred to as “Blueprint for the Future,” which is designed to meet the challenges of rising energy costs, concerns about the environment, improved reliability and government energy reduction goals. For a discussion of the Blueprint for the Future initiative, see PHI’s “Management’s Discussion and Analysis of Financial Condition and Results of Operations – General Overview—Blueprint for the Future.”

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MAPP Project

PJM has approved PHI’s proposal to construct a new 152-mile, interstate transmission line as part of PJM’s regional transmission expansion plan. In August 2011, PJM notified PHI that the scheduled in-service date for MAPP has been delayed from June 1, 2015 to the 2019 to 2021 time period. The projected capital expenditures over the next five years for MAPP are shown as Transmission—MAPP in the table above.

Regulatory Lag

An important factor in the ability of DPL to earn its authorized rate of return is the willingness of applicable public service commissions to adequately recognize forward-looking costs in DPL’s rate structure in order to minimize the shortfall in revenues 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 its investment in the rate base and its operating expenses are outpacing revenue growth. In its most recent rate cases, DPL (in Delaware and Maryland) has proposed mechanisms that would track reliability and other expenses and permit DPL between rate cases to make adjustments in its rates for prudent investments as made, thereby seeking to reduce the magnitude of regulatory lag. There can be no assurance that these proposals or any other attempts by DPL to mitigate regulatory lag will be approved, or that even if approved, the rate recovery mechanisms or any base rate cases will fully ameliorate the effects of regulatory lag. Until such time as these proposed mechanisms are approved, if necessary to address the problem of regulatory lag, DPL plans to file rate cases at least annually in an effort to align more closely its revenue and related cash flow levels with other operation and maintenance spending and capital investments. In future rate cases, DPL would also continue to seek cost recovery and tracking mechanisms from applicable regulatory commissions to reduce the effects of regulatory lag.

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Results of Operations

The following results of operations discussion compares the year ended December 31, 2011 to the year ended December 31, 2010. All amounts in the tables (except sales and customers) are in millions of dollars.

Electric Operating Revenue

	2011		2010		Change
Regulated T&D Electric Revenue	$	394	$	375	$	19
Default Electricity Supply Revenue		664		768		(104	)
Other Electric Revenue		16		20		(4	)
Total Electric Operating Revenue	$	1,074	$	1,163	$	(89	)

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 territory 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.

Default Electricity Supply Revenue is the revenue received from the supply of electricity by DPL at regulated rates to retail customers who do not elect to purchase electricity from a competitive energy supplier, and which is also known as SOS. 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 for approved regional transmission expansion plan costs.

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

	2011		2010		Change
Regulated T&D Electric Revenue
Residential	$	188	$	184	$	4
Commercial and industrial		113		110		3
Transmission and other		93		81		12
Total Regulated T&D Electric Revenue	$	394	$	375	$	19
	2011		2010		Change
Regulated T&D Electric Sales (GWh)
Residential		5,197		5,357		(160	)
Commercial and industrial		7,442		7,445		(3	)
Transmission and other		49		51		(2	)
Total Regulated T&D Electric Sales		12,688		12,853		(165	)

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	2011		2010		Change
Regulated T&D Electric Customers (in thousands)
Residential		441		440		1
Commercial and industrial		59		59		—
Transmission and other		1		1		—
Total Regulated T&D Electric Customers		501		500		1

Regulated T&D Electric Revenue increased by $19 million primarily due to:

• An increase of $12 million in transmission revenue primarily attributable to higher rates effective June 1, 2010 and June 1, 2011 related to increases in transmission plant investment.

• An increase of $11 million due to distribution rate increases in Maryland effective July 2011, and in Delaware effective February 2011.

The aggregate amount of these increases was partially offset by:

• A decrease of $4 million due to lower sales as a result of cooler weather during the 2011 spring and summer months, and warmer weather during the 2011 fall months as compared to 2010.

Default Electricity Supply

	2011		2010		Change
Default Electricity Supply Revenue
Residential	$	505	$	577	$	(72	)
Commercial and industrial		148		181		(33	)
Other		11		10		1
Total Default Electricity Supply Revenue	$	664	$	768	$	(104	)
	2011		2010		Change
Default Electricity Supply Sales (GWh)
Residential		4,856		5,199		(343	)
Commercial and industrial		1,845		1,954		(109	)
Other		29		37		(8	)
Total Default Electricity Supply Sales		6,730		7,190		(460	)
	2011		2010		Change
Default Electricity Supply Customers (in thousands)
Residential		415		423		(8	)
Commercial and industrial		42		45		(3	)
Other		—		1		(1	)
Total Default Electricity Supply Customers		457		469		(12	)

Default Supply Revenue decreased by $104 million primarily due to:

• A decrease of $58 million as a result of lower Default Electricity Supply rates.

• A decrease of $28 million due to lower sales, primarily as a result of customer migration to competitive suppliers.

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• A decrease of $25 million due to lower sales as a result of cooler weather during the spring and summer months of 2011, and warmer weather during the fall months of 2011, as compared to the corresponding periods in 2010.

The aggregate amount of these decreases was partially offset by:

• An increase of $7 million due to higher non-weather related average customer usage.

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:

	2011			2010
Sales to Delaware customers		51	%		53	%
Sales to Maryland customers		58	%		63	%

Natural Gas Operating Revenue

	2011		2010		Change
Regulated Gas Revenue	$	183	$	191	$	(8	)
Other Gas Revenue		47		46		1
Total Natural Gas Operating Revenue	$	230	$	237	$	(7	)

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 includes 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

	2011		2010		Change
Regulated Gas Revenue
Residential	$	113	$	118	$	(5	)
Commercial and industrial		61		65		(4	)
Transportation and other		9		8		1
Total Regulated Gas Revenue	$	183	$	191	$	(8	)
	2011		2010		Change
Regulated Gas Sales (billion cubic feet)
Residential		7		8		(1	)
Commercial and industrial		5		5		—
Transportation and other		7		6		1
Total Regulated Gas Sales		19		19		—

	2011		2010		Change
Regulated Gas Customers (in thousands)
Residential		115		114		1
Commercial and industrial		9		9		—
Transportation and other		—		—		—
Total Regulated Gas Customers		124		123		1

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Regulated Gas Revenue decreased by $8 million primarily due to:

• A decrease of $17 million due to lower non-weather related average customer usage.

The decrease was partially offset by:

• An increase of $6 million due to higher sales primarily as a result of colder weather during the winter months of 2011 as compared to 2010.

• An increase of $2 million due to a distribution rate increase effective February 2011.

• An increase of $2 million due to customer growth in 2011.

Operating Expenses

Purchased Energy

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 decreased by $105 million to $635 million in 2011, from $740 million in 2010 primarily due to:

• A decrease of $68 million due to lower average electricity costs under Default Electricity Supply contracts.

• A decrease of $22 million due to lower electricity sales primarily as a result of cooler weather during the spring and summer months of 2011, and warmer weather during the fall months of 2011, as compared to the corresponding periods in 2010.

• A decrease of $21 million primarily due to customer migration to competitive suppliers.

The aggregate amount of these decreases was partially offset by:

• An increase of $8 million in deferred electricity expense primarily due to lower Default Electricity Supply rates, which resulted in a higher rate of recovery of Default Electricity Supply costs.

Gas Purchased

Gas Purchased 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 decreased by $9 million to $155 million in 2011 from $164 million in 2010 primarily due to:

• A decrease of $16 million in the cost of gas purchases for on-system sales as a result of lower average gas prices, lower volumes purchased and lower withdraws from storage.

• A decrease of $11 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 decreases was partially offset by:

• An increase of $18 million in deferred gas expense as a result of a higher rate of recovery of natural gas supply costs.

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Other Operation and Maintenance

Other Operation and Maintenance decreased by $16 million to $239 million in 2011 from $255 million in 2010 primarily due to:

• A decrease of $16 million resulting from adjustments recorded by DPL in 2011 associated with the accounting for DPL Default Electricity Supply. These adjustments were primarily due to the under-recognition of allowed returns on working capital, uncollectible, late fees and administrative costs.

• A decrease of $4 million in environmental remediation costs.

• A decrease of $2 million due to an adjustment of self-insurance reserves for general and auto liability claims recorded in 2011.

• A decrease of $2 million due to an adjustment for February 2010 severe winter storm costs that previously were charged to other operation and maintenance expense. The adjustment was recorded in accordance with a MPSC rate order issued in July 2011, allowing for the recovery of the costs.

The aggregate amount of these decreases was partially offset by:

• An increase of $5 million in emergency restoration costs. The increase is primarily related to significant incremental costs incurred for repair work following Hurricane Irene in August 2011. Costs incurred for repair work were $8 million, of which $5 million was deferred as a regulatory asset to reflect the probable recovery of these storm costs in certain jurisdictions, and the remaining $3 million was charged to other operation and maintenance expense. DPL currently plans to seek recovery of the incremental Hurricane Irene costs in each of its jurisdictions in planned distribution rate case filings.

• An increase of $5 million associated with higher preventative maintenance and tree trimming costs.

Restructuring Charge

As a result of PHI’s organizational review in the second quarter of 2010, DPLs operating expenses include a pre-tax restructuring charge of $8 million for the year ended December 31, 2010, related to severance and health and welfare benefits to be provided to terminated employees.

Depreciation and Amortization

Depreciation and Amortization expense increased by $6 million to $89 million in 2011 from $83 million in 2010 primarily due to:

• An increase of $4 million due to utility plant additions.

• An increase of $1 million in amortization of regulatory assets primarily associated with the EmPower Maryland surcharge that became effective in March 2010 (which is substantially offset by a corresponding increase in Regulated T&D Electric Revenue).

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Income Tax Expense

DPL’s effective tax rates for the years ended December 31, 2011 and 2010 were 37.2% and 40.8%, respectively. The decrease in the effective rate is primarily related to PHI’s 2011 settlement with the IRS regarding interest due on its federal tax liabilities related to the November 2010 audit settlement for the tax years 1996 to 2002. In connection with this agreement, PHI reallocated certain amounts that have been on deposit with the IRS since 2006 among liabilities in the settlement years and subsequent years. Primarily related to the settlement and reallocations, DPL recorded an additional $4 million (after-tax) interest benefit. This is partially offset by adjustments recorded in the third quarter of 2011 related to DPL’s settlement with the state taxing authorities resulting in $1 million (after-tax) of additional tax expense and the recalculation of interest on its uncertain tax positions for open tax years based on different assumptions related to the application of its deposit made with the IRS in 2006. This resulted in an additional tax expense of $1 million (after-tax).

In addition, the effective tax rate increased in 2010 as a result of the November 2010 settlement PHI reached with the IRS with respect to its Federal tax returns for the years 1996 to 2002. In connection with the settlement, PHI reallocated certain amounts on deposit with the IRS since 2006 among liabilities in the settlement years and subsequent years. In light of the settlement and reallocations, DPL recalculated the estimated interest due for the tax years 1996 to 2002. The revised estimate resulted in an additional $3 million (after-tax) of estimated interest due to the IRS. This expense was partially offset by the reversal of $2 million of previously recorded tax liabilities.

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, 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. See “Risk Factors,” for additional discussion of important factors that may have an effect on DPL’s sources of capital.

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. 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 VRDBs. To fund the construction of pollution control facilities, DPL also has from time to time issued tax-exempt bonds, including tax-exempt VRDBs, through a public agency, the proceeds of which are loaned to DPL by the agency.

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Information concerning the principal amount and terms of DPL’s outstanding First Mortgage Bonds, senior notes, medium-term notes and VRDBs, and tax-exempt bonds issued for the benefit of DPL, as of December 31, 2011, is set forth in Note (11), “Debt,” to the financial statements of DPL.

Bank Financing

As further discussed in Note (11), “Debt,” to the financial statements of DPL, DPL is a borrower under a $1.5 billion credit facility, along with PHI, Pepco and ACE, which expires in 2016. 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 of up to $500 million under which it can issue commercial paper with maturities of up to 270 days. The commercial paper is backed by DPL’s borrowing capacity under the $1.5 billion credit facility.

DPL had $47 million of commercial paper outstanding at December 31, 2011 and zero outstanding at December 31, 2010. The weighted average interest rates for commercial paper issued during 2011 and 2010 were 0.34%. The weighted average maturity of all commercial paper issued by DPL during 2011 and 2010 was two days.

Money Pool

DPL participates in the money pool operated by PHI under authorization received from FERC. The money pool is a 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. Borrowings from the money pool are unsecured. 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 PHI may obtain 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, 2011, totaled $229 million. These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission. 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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The following table shows DPL’s projected capital expenditures for the five-year period 2012 through 2016. DPL expects to fund these expenditures through internally generated cash, external financing and capital contributions from PHI.

	For the Year
	2012		2013		2014		2015		2016		Total
	(millions of dollars)
DPL
Distribution	$	136	$	153	$	144	$	144	$	161	$	738
Distribution – Blueprint for the Future		44		2		—		—		—		46
Transmission		148		93		128		120		116		605
Transmission – MAPP		4		1		1		3		58		67
Gas Delivery		22		23		23		25		27		120
Other		52		29		20		14		17		132
Total DPL	$	406	$	301	$	316	$	306	$	379	$	1,708

Transmission and Distribution

The projected capital expenditures listed in the table above for distribution (other than Blueprint for the Future), transmission (other than the MAPP project) and gas delivery are primarily for facility replacements and upgrades to accommodate customer growth and service reliability, including capital expenditures for reliability enhancement efforts.

Blueprint for the Future

DPL has undertaken programs to install smart meters, further automate its electric distribution systems and enhance its communications infrastructure, which it refers to as the Blueprint for the Future. For a discussion of the Blueprint for the Future initiative, see PHI’s “Management’s Discussion and Analysis of Financial Condition and Results of Operations – General Overview—Blueprint for the Future.” The projected capital expenditures over the next five years are shown as Distribution – Blueprint for the Future in the table above.

MAPP Project

PHI has under development the construction of a new 152-mile, interstate transmission line as part of PJM’s regional transmission expansion plan. The projected capital expenditures over the next five years for MAPP are shown as Transmission – MAPP in the table above.

MAPP/DOE Loan Program

To assist in the funding of the MAPP project, PHI has applied for a $684 million loan guarantee from the DOE for a substantial portion of the MAPP project, primarily the Calvert Cliffs to Indian River segment. The application has been made under a federal loan guarantee program for projects that employ innovative energy efficiency, renewable energy and advanced transmission and distribution technologies. If granted, PHI believes the guarantee could allow PHI to acquire financing at a lower cost than it would otherwise be able to obtain in the capital markets. Whether PHI’s application will be granted and, if so, the amount of debt guaranteed is subject to the discretion of the DOE and the negotiation of terms that will satisfy the conditions of the guarantee program. On February 28, 2011,

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the DOE issued a Notice of Intent to prepare an Environmental Impact Statement to assist the DOE in assessing the environmental impact of constructing the portion of the MAPP project to be supported by the loan guarantee. Since February 2011, the DOE has conducted field inspections of the entire route and has held public meetings to obtain input from the communities along the route.

The DOE’s review of the loan guarantee program has delayed the DOE’s review of PHI’s loan guarantee application. There is not an approval deadline under the loan guarantee program, but this program could change or be terminated in the future. PHI continues to coordinate environmental activities with the DOE.

Pension and Other Postretirement Benefit Plans

DPL participates in pension and OPEB plans sponsored by PHI for its employees. DPL contributed $40 million and zero to the PHI Retirement Plan during 2011 and 2010, respectively.

On January 31, 2012, DPL made an $85 million discretionary tax-deductible contribution to the PHI Retirement Plan.

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ACE

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 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 BGS in New Jersey. ACE’s service territory covers approximately 2,700 square miles and has a population of approximately 1.1 million.

ACE is a wholly owned subsidiary of Conectiv, which is wholly owned by PHI. Because PHI is a public utility holding company subject to PUHCA 2005, the relationship between PHI and ACE and certain activities of ACE are subject to FERC’s regulatory oversight under PUHCA 2005.

Blueprint for the Future

ACE is participating in a PHI initiative referred to as “Blueprint for the Future,” which is designed to meet the challenges of rising energy costs, concerns about the environment, improved reliability and government energy reduction goals. For a discussion of the Blueprint for the Future initiative, see PHI’s “Management’s Discussion and Analysis of Financial Condition and Results of Operations – General Overview—Blueprint for the Future.”

Regulatory Lag

An important factor in ACE’s ability to earn its authorized rate of return is the willingness of the NJBPU to adequately recognize forward-looking costs in ACE’s rate structure in order to minimize the shortfall in revenues 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 its investment in the rate base and its operating expenses are outpacing revenue growth. The NJBPU has approved certain rate recovery mechanisms in connection with ACE’s Infrastructure Investment Program (IIP), which ACE has proposed to extend and expand. There can be no assurance that this proposal or any other attempts by ACE to mitigate regulatory lag will be approved, or that even if approved, the rate recovery mechanisms or any base rate cases will fully ameliorate the effects of regulatory lag. Until such time as this proposed mechanism is approved, if necessary to address the problem of regulatory lag, ACE plans to file rate cases at least annually in an effort to align more closely its revenue and related cash flow levels with other operation and maintenance spending and capital investments. In future rate cases, ACE would also continue to seek cost recovery and tracking mechanisms from applicable regulatory commissions to reduce the effects of regulatory lag.

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Results of Operations

The following results of operations discussion compares the year ended December 31, 2011 to the year ended December 31, 2010. All amounts in the tables (except sales and customers) are in millions of dollars.

Operating Revenue

	2011		2010		Change
Regulated T&D Electric Revenue	$	386	$	415	$	(29	)
Default Electricity Supply Revenue		865		998		(133	)
Other Electric Revenue		17		17		—
Total Operating Revenue	$	1,268	$	1,430	$	(162	)

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.

Default Electricity Supply Revenue is the revenue received from the supply of electricity by ACE at regulated rates to retail customers who do not elect to purchase electricity from a competitive supplier, also known as BGS. 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 issued by ACE Funding, 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.

Regulated T&D Electric

	2011		2010		Change
Regulated T&D Electric Revenue
Residential	$	167	$	185	$	(18	)
Commercial and industrial		124		142		(18	)
Transmission and other		95		88		7
Total Regulated T&D Electric Revenue	$	386	$	415	$	(29	)

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ACE

	2011		2010		Change
Regulated T&D Electric Sales (GWh)
Residential		4,479		4,691		(212	)
Commercial and industrial		5,157		5,445		(288	)
Transmission and other		47		49		(2	)
Total Regulated T&D Electric Sales		9,683		10,185		(502	)
	2011		2010		Change
Regulated T&D Electric Customers (in thousands)
Residential		481		482		(1	)
Commercial and industrial		65		65		—
Transmission and other		1		1		—
Total Regulated T&D Electric Customers		547		548		(1	)

Regulated T&D Electric Revenue decreased by $29 million primarily due to:

• A decrease of $30 million due to a New Jersey Societal Benefit Charge rate decrease that became effective in January 2011 (which is offset in Deferred Electric Service Costs).

• A decrease of $8 million due to lower non-weather related average customer usage.

• A decrease of $7 million due to lower sales as a result of cooler weather during the spring and summer months of 2011, and warmer weather during the fall months of 2011, as compared to the corresponding periods in 2010.

The aggregate amount of these decreases was partially offset by:

• An increase of $9 million due to a distribution rate increase that became effective in June 2010.

• An increase of $7 million in transmission revenue primarily attributable to higher rates effective June 1, 2010 and June 1, 2011 related to increases in transmission plant investment.

Default Electricity Supply

	2011		2010		Change
Default Electricity Supply Revenue
Residential	$	495	$	580	$	(85	)
Commercial and industrial		237		243		(6	)
Other		133		175		(42	)
Total Default Electricity Supply Revenue	$	865	$	998	$	(133	)

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.

	2011		2010		Change
Default Electricity Supply Sales (GWh)
Residential		3,919		4,610		(691	)
Commercial and industrial		1,469		1,967		(498	)
Other		36		46		(10	)
Total Default Electricity Supply Sales		5,424		6,623		(1,199	)

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ACE

	2011		2010		Change
Default Electricity Supply Customers (in thousands)
Residential		419		458		(39	)
Commercial and industrial		50		56		(6	)
Other		—		—		—
Total Default Electricity Supply Customers		469		514		(45	)

Default Electricity Supply Revenue decreased by $133 million primarily due to:

• A decrease of $98 million due to lower sales, primarily as a result of residential and commercial customer migration to competitive suppliers.

• A decrease of $40 million in wholesale energy and capacity resale revenues primarily due to the sale of lower volumes of electricity and capacity purchased from NUGs.

• A decrease of $21 million due to lower sales as a result of cooler weather during the spring and summer months of 2011, and warmer weather during the fall months of 2011, as compared to the corresponding periods in 2010.

• A decrease of $11 million due to lower non-weather related average customer usage.

• A decrease of $3 million due to a decrease in revenue from transmission enhancement credits.

The aggregate amount of these decreases was partially offset by:

• An increase of $39 million as a result of higher Default Electricity Supply rates, primarily due to a Non-utility Generation Charge rate increase that became effective in January 2011.

Total Default Electricity Supply Revenue for the 2011 period includes a decrease of $8 million in unbilled revenue attributable to ACE’s BGS ($5 million decrease in net income), primarily due to lower customer usage and lower Default Electricity Supply rates during the unbilled revenue period at the end of 2011 as compared to the corresponding period in 2010. Under the BGS terms approved by the NJBPU, ACE’s BGS unbilled revenue is not included in the deferral calculation until it is billed to customers, and therefore has an impact on the results of operations in the period during which it is accrued.

For the years ended December 31, 2011 and 2010, the percentages of ACE’s total distribution sales that are derived from customers receiving Default Electricity Supply are 56% and 65%, 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 decreased by $223 million to $807 million in 2011 from $1,030 million in 2010 primarily due to:

• A decrease of $138 million primarily due to customer migration to competitive suppliers.

• A decrease of $69 million due to lower average electricity costs under Default Electricity Supply contracts.

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ACE

• A decrease of $16 million due to lower electricity sales primarily as a result of cooler weather during the spring and summer months of 2011, and warmer weather during the fall months of 2011, as compared to 2010.

Other Operation and Maintenance

Other Operation and Maintenance increased by $22 million to $226 million in 2011 from $204 million in 2010 primarily due to:

• An increase of $5 million associated with higher tree trimming and preventative maintenance costs.

• An increase of $5 million related to New Jersey Societal Benefit Program costs that are deferred and recoverable.

• An increase of $4 million in employee-related costs, primarily benefit expenses.

• An increase of $3 million in corporate cost allocations.

• An increase of $2 million in costs related to customer requested and mutual assistance work (primarily offset in other T&D Electric Revenues).

• An increase of $2 million in emergency restoration and reliability improvement, communication and customer support service costs.

The aggregate amount of these increases was partially offset by:

• A decrease of $4 million in emergency restoration costs due to higher storm activity in 2010, primarily the severe winter storms of February 2010. In 2011, ACE incurred significant incremental restoration costs for repair work following Hurricane Irene in August 2011 of $7 million, but such costs were deferred as a regulatory asset to reflect the probable recovery of these storm costs. Approximately $3 million of these total incremental storm costs have been estimated for the cost of restoration services provided by outside contractors. Since the invoices for such services had not been received at December 31, 2011, actual invoices may vary from these estimates. ACE currently plans to seek recovery of the incremental Hurricane Irene costs as discussed in Note (7), “Regulatory Matters — Regulatory Proceedings — Rate Proceedings.”

Restructuring Charge

As a result of PHI’s organizational review in the second quarter of 2010, ACEs operating expenses include a pre-tax restructuring charge of $6 million for the year ended December 31, 2010, related to severance and health and welfare benefits to be provided to terminated employees.

Depreciation and Amortization

Depreciation and Amortization expense increased by $22 million to $134 million in 2011 from $112 million in 2010 primarily due to:

• An increase of $16 million in amortization of stranded costs as the result of higher revenue due to rate increases effective October 2010 for the ACE Transition Bond Charge and Market Transition Charge Tax (partially offset in Default Electricity Supply Revenue).

• An increase of $6 million due to utility plant additions.

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ACE

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

Deferred Electric Service Costs increased by $45 million, to an expense reduction of $63 million in 2011 as compared to an expense reduction of $108 million in 2010, primarily due to higher Default Electricity Supply Revenue rates and lower electricity supply costs.

Income Tax Expense

ACE’s consolidated effective tax rates for the years ended December 31, 2011 and 2010 were 45.8% and 44.8%, respectively. The increase in the rate is primarily the result of the recalculation of interest on uncertain and effectively settled tax positions. During 2011, PHI reached a settlement with the IRS with respect to interest due on its federal tax liabilities related to the November 2010 audit settlement for years 1996 through 2002. In connection with this agreement, PHI reallocated certain amounts that have been on deposit with the IRS since 2006 among liabilities in the settlement years and subsequent years. Primarily related to the settlement and reallocations, ACE has recorded an additional $1 million (after-tax) of interest due to the IRS. This additional interest expense was recorded in the second quarter of 2011. This is further impacted by the adjustment recorded in the third quarter of 2011 related to the recalculation of interest on its uncertain tax positions for open tax years using different assumptions related to the application of its deposit made with the IRS in 2006. This resulted in an additional tax expense of $3 million (after-tax).

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 short-term funding needs, including commercial paper, 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. See “Risk Factors,” for additional discussion of important factors that may have an effect on ACE’s sources of capital.

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. 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 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 issued tax-exempt bonds, including tax-exempt VRDBs, through a municipality, the proceeds of which are loaned to ACE by the municipality.

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ACE

Information concerning the principal amount and terms of ACE’s outstanding First Mortgage Bonds, senior notes and VRDBs, and tax-exempt bonds issued for the benefit of ACE, as of December 31, 2011, is set forth in Note (10), “Debt,” to the consolidated financial statements of ACE.

Bank Financing

As further discussed in Note (10), “Debt,” to the consolidated financial statements of ACE, ACE is a borrower under a $1.5 billion credit facility, along with PHI, Pepco and DPL, which expires in 2016. 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 $250 million.

Commercial Paper Program

ACE maintains an ongoing commercial paper program of up to $250 million under which it can issue commercial paper with maturities of up to 270 days. The commercial paper is backed by ACE’s borrowing capacity under the $1.5 billion credit facility.

ACE had no commercial paper outstanding at December 31, 2011 and $158 million of commercial paper outstanding at December 31, 2010. The weighted average interest rates for commercial paper issued during 2011 and 2010 were 0.33% and 0.36%, respectively. The weighted average maturity of all commercial paper issued by ACE during 2011 and 2010 was six days and seven days, respectively.

Money Pool

ACE participates in the money pool operated by PHI under authorization received from the NJBPU. The money pool is a 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. Borrowings from the money pool are unsecured. 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 PHI may obtain 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 rates are lower than the 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. Information concerning the numbers of shares and the terms of ACE’s outstanding shares of Cumulative Preferred Stock as of December 31, 2011 and 2010, is set forth in Note (12), “Preferred Stock,” to the consolidated financial statements of ACE. As of December 31, 2011, ACE had no shares of preferred stock outstanding.

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ACE

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, 2011, 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, 2011, totaled $138 million. These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission. 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.

The following table shows ACE’s updated projected capital expenditures for the five-year period 2012 through 2016. ACE expects to fund these expenditures through internally generated cash, external financing and capital contributions from PHI.

	For the Year
	2012			2013			2014		2015		2016		Total
	(millions of dollars)
ACE
Distribution	$	144		$	159		$	146	$	147	$	144	$	740
Distribution—Blueprint for the Future		—			—			—		9		92		101
Transmission		53			74			82		77		71		357
Other		32			21			13		12		14		92
Sub-Total		229			254			241		245		321		1,290
DOE Capital Reimbursement Awards (a)		(4	)		(1	)		—		—		—		(5	)
Total ACE	$	225		$	253		$	241	$	245	$	321	$	1,285

(a) Reflects anticipated reimbursements pursuant to awards from the DOE under the American Recovery and Reinvestment Act of 2009.

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

Transmission and Distribution

The projected capital expenditures listed in the table for distribution (other than Blueprint for the Future) and transmission are primarily for facility replacements and upgrades to accommodate customer growth and reliability, including continued capital expenditures for reliability enhancement efforts.

Blueprint for the Future

ACE has undertaken programs to install smart meters (for which approval by the NJBPU has been deferred), further automate its electric distribution systems and enhance its communications infrastructure, which it refers to as the Blueprint for the Future. For a discussion of the Blueprint for the Future initiative, see PHI’s “Management’s Discussion and Analysis of Financial Condition and Results of Operations – General Overview—Blueprint for the Future.” The projected capital expenditures over the next five years are shown as Distribution—Blueprint for the Future in the table above.

Infrastructure Investment Plan

In 2009, the NJBPU approved ACE’s proposed Infrastructure Investment Plan and the revenue requirement associated with recovering the cost of the related projects, subject to a prudency review in the next rate case. The approved projects were designed to enhance reliability of ACE’s distribution system and support economic activity and job growth in New Jersey in the near term. ACE was granted cost recovery through an Infrastructure Investment Surcharge, which became effective on June 1, 2009. This approved plan was completed in 2011 and has added incremental capital spending of approximately $28 million since 2009. In 2011, ACE proposed a new Infrastructure Investment Plan that if approved by the NJBPU, would be expected to add an additional $63 million of capital spending for 2012, which is included in Distribution in the table above.

DOE Capital Reimbursement Awards

In 2009, the DOE announced a $168 million award to PHI under the American Recovery and Reinvestment Act of 2009 for the implementation of an advanced metering infrastructure system, direct load control, distribution automation, and communications infrastructure, of which $19 million was for ACE’s service territory.

In April 2010, PHI and the DOE signed agreements formalizing ACE’s $19 million share of the $168 million award. Of the $19 million, $12 million is expected to offset incurred and projected Blueprint for the Future and other capital expenditures of ACE. The remaining $7 million will be used to offset incremental expenses associated with direct load control and other programs. In 2011, ACE received award payments of $6 million. In 2010, ACE received award payments of $2 million.

Pension and Other Postretirement Benefit Plans

ACE participates in pension and OPEB plans sponsored by PHI for its employees. ACE contributed $30 million and zero to the PHI Retirement Plan during 2011 and 2010, respectively.

On January 31, 2012, ACE made a $30 million discretionary tax-deductible contribution to the PHI Retirement 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, Chief Operating Officer, 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,” Note (15), “Derivative Instruments and Hedging Activities” and Note (20), “Discontinued Operations” of the consolidated financial statements of PHI.

Pepco Holdings, Inc.

Commodity Price Risk

The Pepco Energy Services segment engages in commodity risk management activities to reduce its financial exposure to changes in the value of its assets and obligations due to commodity price fluctuations. Certain of these risk management activities are conducted using instruments classified as derivatives based on FASB guidance on derivatives and hedging, ASC 815. Pepco Energy Services also manages commodity risk with contracts that are not classified as derivatives. The primary risk management objective is to manage the spread between retail electricity and natural gas supply commitments and the cost of energy used to service those commitments in order to ensure stable and known cash flows and fix favorable prices and margins.

PHI’s risk management policies place oversight at the senior management level through the CRMC, which has the responsibility for establishing corporate compliance requirements for energy market participation. PHI collectively refers to these energy market activities, including its commodity risk management activities, as “energy commodity” activities. PHI uses a value-at-risk (VaR) model to assess the market risk of the energy commodity activities of Pepco Energy Services. PHI also uses other measures to limit and monitor risk in its energy commodity activities, including limits on the nominal size of positions and periodic loss limits. VaR represents the potential fair value loss on energy contracts or portfolios due to changes in market prices for a specified time period and confidence level. PHI uses a delta-gamma VaR estimation model. The other parameters include a 95 percent, one-tailed confidence level and a one-day holding period. Since VaR is an estimate, it is not necessarily indicative of actual results that may occur.

The table below provides the VaR associated with energy contracts of the Pepco Energy Services segment for the year ended December 31, 2011 in millions of dollars:

	VaR (a)
95% confidence level, one-day holding period, one-tailed
Period end	$	1
Average for the period	$	1
High	$	3
Low	$	1

(a) This column represents all energy derivative contracts, normal purchase and normal sales contracts, modeled generation output and fuel requirements, and modeled customer load obligations for Pepco Energy Services’ energy commodity activities.

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Pepco Energy Services purchases electric and natural gas futures, swaps, options and forward contracts to hedge price risk in connection with the purchase of physical natural gas and electricity for distribution to customers. Pepco Energy Services accounts for its derivatives as either cash flow hedges of forecasted transactions or they are marked to market through current earnings. Forward contracts that meet the requirements for normal purchase and normal sale accounting under FASB guidance on derivatives and hedging are recorded on an accrual basis.

Credit and Nonperformance Risk

Pepco Holdings’ subsidiaries attempt to minimize credit risk exposure to wholesale energy counterparties through, among other things, formal credit policies, regular assessment of counterparty creditworthiness and the establishment of a credit limit for each counterparty, monitoring procedures that include stress testing, the use of standard agreements which allow for the netting of positive and negative exposures associated with a single counterparty and collateral requirements under certain circumstances, and have established reserves for credit losses. As of December 31, 2011, credit exposure to wholesale energy counterparties was weighted 100% with investment grade counterparties. There were no investments with counterparties without external credit-quality ratings and no investments with non-investment grade counterparties.

The following table provides information on the credit exposure on competitive wholesale energy contracts, net of collateral, to wholesale counterparties as of December 31, 2011, in millions of dollars:

Rating	Exposure Before Credit Collateral (b)		Credit Collateral (c)		Net Exposure		Number of Counterparties Greater Than 10% (d)		Net Exposure of Counterparties Greater Than 10%
Investment Grade (a)	$	4	$	—	$	4		2	$	4
Non-Investment Grade		—		—		—		—		—
No External Ratings		—		—		—		—		—
Credit reserves						—

(a) Investment Grade—primarily determined using publicly available credit ratings of the counterparty. If the counterparty has provided a guarantee by a higher-rated entity (e.g., its parent), it is determined based upon the rating of its guarantor. Included in “Investment Grade” are counterparties with a minimum Standard & Poor’s or Moody’s Investor Service rating of BBB- or Baa3, respectively.

(b) Exposure before credit collateral—includes the marked to market energy contract net assets for open/unrealized transactions, the net receivable/payable for realized transactions and net open positions for contracts not marked to market. Amounts due from counterparties are offset by liabilities payable to those counterparties to the extent that legally enforceable netting arrangements are in place. Thus, this column presents the net credit exposure to counterparties after reflecting all allowable netting, but before considering collateral held.

(c) Credit collateral—the face amount of cash deposits, letters of credit and performance bonds received from counterparties, not adjusted for probability of default, and, if applicable, property interests (including oil and natural gas reserves).

(d) Using a percentage of the total exposure.

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 rates 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 less than $1 million as of December 31, 2011.

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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 rates 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, 2011.

Delmarva Power & Light Company

Commodity Price Risk

DPL uses derivative instruments (forward contracts, futures, swaps, and exchange-traded and over-the-counter options) primarily to reduce natural gas commodity price volatility while limiting its customers’ exposure to increases in the market price of natural gas. 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, 2011, after the effects of cash collateral and netting, DPL had a net derivative liability of $15 million, offset by a $17 million regulatory asset. At December 31, 2010, after the effects of cash collateral and netting, DPL had a net derivative liability of $23 million, offset by a $31 million regulatory asset.

Interest Rate Risk

DPL’s debt is subject to the risk of fluctuating interest rates in the normal course of business. DPL manages interest rates 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, 2011.

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 rates 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, 2011.

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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		129		217		251		290
Report of Independent Registered Public Accounting Firm		130		218		252		291
Consolidated Statements of Income		131		219		253		292
Consolidated Statements of Comprehensive Income		132		N/A		N/A		N/A
Consolidated Balance Sheets		133		220		254		293
Consolidated Statements of Cash Flows		135		222		256		295
Consolidated Statements of Equity		136		223		257		296
Notes to Consolidated Financial Statements		137		224		258		297

* Pepco and DPL have no operating subsidiaries and, therefore, their financial statements are not consolidated.

128

PEPCO HOLDINGS

Management’s Report on Internal Control over Financial Reporting

The management of 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 Holding’s internal control over financial reporting as of December 31, 2011 based on the framework in Internal Control – Integrated Framework 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, 2011.

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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PEPCO HOLDINGS

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, 2011 and December 31, 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011 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, 2011, based on criteria established in Internal Control—Integrated Framework 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.

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 23, 2012

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PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

For the Year Ended December 31,	2011			2010			2009
	(millions of dollars, except per share data)
Operating Revenue
Power Delivery	$	4,650		$	5,114		$	4,980
Pepco Energy Services		1,238			1,883			2,383
Other		32			42			39
Total Operating Revenue		5,920			7,039			7,402
Operating Expenses
Fuel and purchased energy		3,422			4,631			5,330
Other services cost of sales		172			140			85
Other operation and maintenance		914			884			819
Restructuring charge		—			30			—
Depreciation and amortization		426			393			349
Other taxes		451			434			368
Gain on early termination of finance leases held in trust		(39	)		—			—
Deferred electric service costs		(63	)		(108	)		(161	)
Impairment losses		—			—			4
Effects of Pepco divestiture-related claims		—			11			(40	)
Total Operating Expenses		5,283			6,415			6,754
Operating Income		637			624			648
Other Income (Expenses)
Interest and dividend income		1			—			2
Interest expense		(254	)		(306	)		(340	)
(Loss) gain from equity investments		(3	)		(1	)		2
Loss on extinguishment of debt		—			(189	)		—
Impairment losses		(5	)		—			—
Other income		33			22			16
Other expenses		—			—			(1	)
Total Other Expenses		(228	)		(474	)		(321	)
Income from Continuing Operations Before Income Tax Expense		409			150			327
Income Tax Expense Related to Continuing Operations		149			11			104
Net Income from Continuing Operations		260			139			223
(Loss) Income from Discontinued Operations, net of Income Taxes		(3	)		(107	)		12
Net Income	$	257		$	32		$	235
Basic and Diluted Share Information
Weighted average shares outstanding (millions)		226			224			221
Earnings per share of common stock from Continuing Operations	$	1.15		$	0.62		$	1.01
(Loss) earnings per share of common stock from Discontinued Operations		(0.01	)		(0.48	)		0.05
Basic and diluted earnings per share	$	1.14		$	0.14		$	1.06

The accompanying Notes are an integral part of these Consolidated Financial Statements.

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PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

For the Year Ended December 31,	2011			2010			2009
	(millions of dollars)
Net Income	$	257		$	32		$	235
Other Comprehensive Income (Loss) from Continuing Operations
Gains (losses) from continuing operations on commodity derivatives designated as cash flow hedges:
Losses arising during period		—			(100	)		(129	)
Amount of losses reclassified into income		81			135			166
Net gains on commodity derivatives		81			35			37
Losses on treasury rate locks reclassified into income		1			18			5
Amortization of losses for prior service cost		(7	)		—			(13	)
Prior service costs arising during period		(4	)		—			—
Other comprehensive income from continuing operations, before income taxes		71			53			29
Income tax expense related to other comprehensive income from continuing operations		28			21			12
Other comprehensive income from continuing operations, net of income taxes		43			32			17
Other Comprehensive Income from Discontinued Operations, Net of Income Taxes		—			103			4
Comprehensive Income	$	300		$	167		$	256

The accompanying Notes are an integral part of these Consolidated Financial Statements.

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PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	December 31, 2011			December 31, 2010
	(millions of dollars)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	109		$	20
Restricted cash equivalents		11			11
Accounts receivable, less allowance for uncollectible accounts of $49 million and $51 million, respectively		929			1,027
Inventories		132			126
Derivative assets		5			45
Prepayments of income taxes		74			276
Deferred income tax assets, net		59			90
Prepaid expenses and other		120			51
Conectiv Energy assets held for sale		—			111
Total Current Assets		1,439			1,757
INVESTMENTS AND OTHER ASSETS
Goodwill		1,407			1,407
Regulatory assets		2,196			1,915
Investment in finance leases held in trust		1,349			1,423
Income taxes receivable		84			114
Restricted cash equivalents		15			5
Assets and accrued interest related to uncertain tax positions		37			11
Other		163			169
Conectiv Energy assets held for sale		—			6
Total Investments and Other Assets		5,251			5,050
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		12,855			12,120
Accumulated depreciation		(4,635	)		(4,447	)
Net Property, Plant and Equipment		8,220			7,673
TOTAL ASSETS	$	14,910		$	14,480

The accompanying Notes are an integral part of these Consolidated Financial Statements.

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PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	December 31, 2011			December 31, 2010
	(millions of dollars, except shares)
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Short-term debt	$	732		$	534
Current portion of long-term debt and project funding		112			75
Accounts payable and accrued liabilities		549			587
Capital lease obligations due within one year		8			8
Taxes accrued		110			96
Interest accrued		47			45
Liabilities and accrued interest related to uncertain tax positions		3			3
Derivative liabilities		26			66
Other		274			321
Liabilities associated with Conectiv Energy assets held for sale		—			62
Total Current Liabilities		1,861			1,797
DEFERRED CREDITS
Regulatory liabilities		526			528
Deferred income taxes, net		2,863			2,714
Investment tax credits		22			26
Pension benefit obligation		424			332
Other postretirement benefit obligations		469			429
Income taxes payable		—			2
Liabilities and accrued interest related to uncertain tax positions		32			148
Derivative liabilities		6			21
Other		191			175
Liabilities associated with Conectiv Energy assets held for sale		—			10
Total Deferred Credits		4,533			4,385
LONG-TERM LIABILITIES
Long-term debt		3,794			3,629
Transition bonds issued by ACE Funding		295			332
Long-term project funding		13			15
Capital lease obligations		78			86
Total Long-Term Liabilities		4,180			4,062
COMMITMENTS AND CONTINGENCIES (NOTE 17)
EQUITY
Common stock, $.01 par value—authorized 400,000,000 shares, 227,500,190 and 225,082,252 shares outstanding, respectively		2			2
Premium on stock and other capital contributions		3,325			3,275
Accumulated other comprehensive loss		(63	)		(106	)
Retained earnings		1,072			1,059
Total Shareholders’ Equity		4,336			4,230
Non-controlling interest		—			6
Total Equity		4,336			4,236
TOTAL LIABILITIES AND EQUITY	$	14,910		$	14,480

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,	2011			2010			2009
	(millions of dollars)
OPERATING ACTIVITIES
Net income	$	257		$	32		$	235
Loss (income) from discontinued operations, net of income taxes		3			107			(12	)
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		426			393			349
Non-cash rents from cross-border energy lease investments		(55	)		(55	)		(54	)
Gain on early termination of finance leases held in trust		(39	)		—			—
Non-cash charge to reduce equity value of PHI’s cross-border energy lease investments		7			2			3
Effects of Pepco divestiture-related claims		—			11			(40	)
Changes in restricted cash equivalents related to Mirant settlement		—			—			102
Deferred income taxes		140			345			249
Net unrealized losses on Pepco Energy Services commodity derivatives		30			3			2
Losses on treasury rate locks reclassified into income		1			18			5
Other		(19	)		(20	)		(3	)
Changes in:
Accounts receivable		135			(12	)		136
Inventories		(6	)		(2	)		20
Prepaid expenses		(4	)		7			(17	)
Regulatory assets and liabilities, net		(148	)		(154	)		(221	)
Accounts payable and accrued liabilities		(90	)		73			(153	)
Pension contributions		(110	)		(100	)		(300	)
Pension benefit obligation, excluding contributions		53			68			95
Cash collateral related to derivative activities		9			13			24
Taxes accrued		11			(213	)		76
Other assets and liabilities		43			49			7
Net Conectiv Energy assets held for sale		42			248			103
Net Cash From Operating Activities		686			813			606
INVESTING ACTIVITIES
Investment in property, plant and equipment		(941	)		(802	)		(664	)
Department of Energy capital reimbursement awards received		52			13			—
Proceeds from sale of Conectiv Energy wholesale power generation business		—			1,640			—
Proceeds from early termination of finance leases held in trust		161			—			—
Changes in restricted cash equivalents		(10	)		(2	)		—
Proceeds from sale of assets		—			3			4
Net other investing activities		(9	)		4			—
Investment in property, plant and equipment associated with Conectiv Energy assets held for sale		—			(138	)		(200	)
Net Cash (Used By) From Investing Activities		(747	)		718			(860	)
FINANCING ACTIVITIES
Dividends paid on common stock		(244	)		(241	)		(238	)
Common stock issued for the Dividend Reinvestment Plan and employee-related compensation		47			47			49
Redemption of preferred stock of subsidiaries		(6	)		—			—
Issuances of long-term debt		235			383			110
Reacquisitions of long-term debt		(70	)		(1,726	)		(83	)
Issuances of short-term debt, net		198			4			65
Cost of issuances		(10	)		(7	)		(4	)
Net other financing activities		(1	)		(6	)		10
Net financing activities associated with Conectiv Energy assets held for sale		—			(10	)		7
Net Cash From (Used By) Financing Activities		149			(1,556	)		(84	)
Net Increase (Decrease) In Cash and Cash Equivalents		88			(25	)		(338	)
Cash and Cash Equivalents of Discontinued Operations		—			(1	)		(2	)
Cash and Cash Equivalents at Beginning of Year		21			46			384
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	109		$	20		$	44
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for interest (net of capitalized interest of $11 million, $9 million and $11 million, respectively)	$	240		$	310		$	353
Cash paid (received) for income taxes		4			(13	)		(76	)

The accompanying Notes are an integral part of these Consolidated Financial Statements.

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CONSOLIDATED STATEMENTS OF EQUITY

	Common Stock				Premium			Accumulated Other Comprehensive			Retained
(millions of dollars, except shares)	Stock Shares		Par Value		on Stock			(Loss) Income			Earnings			Total
BALANCE, DECEMBER 31, 2008		218,906,220	$	2	$	3,179		$	(262	)	$	1,271		$	4,190
Net Income		—		—		—			—			235			235
Other comprehensive income		—		—		—			21			—			21
Dividends on common stock ($1.08 per share)		—		—		—			—			(238	)		(238	)
Issuance of common stock:
Original issue shares, net		1,210,261		—		18			—			—			18
Shareholder DRP original shares		2,153,414		—		31			—			—			31
Net activity related to stock-based awards		—		—		(1	)		—			—			(1	)
BALANCE, DECEMBER 31, 2009		222,269,895		2		3,227			(241	)		1,268			4,256
Net Income		—		—		—			—			32			32
Other comprehensive income		—		—		—			135			—			135
Dividends on common stock ($1.08 per share)		—		—		—			—			(241	)		(241	)
Issuance of common stock:
Original issue shares, net		1,041,482		—		16			—			—			16
Shareholder DRP original shares		1,770,875		—		31			—			—			31
Net activity related to stock-based awards		—		—		1			—			—			1
BALANCE, DECEMBER 31, 2010		225,082,252		2		3,275			(106	)		1,059			4,230
Net Income		—		—		—			—			257			257
Other comprehensive income		—		—		—			43			—			43
Dividends on common stock ($1.08 per share)		—		—		—			—			(244	)		(244	)
Issuance of common stock:
Original issue shares, net		854,124		—		17			—			—			17
Shareholder DRP original shares		1,563,814		—		30			—			—			30
Net activity related to stock-based awards		—		—		3			—			—			3
BALANCE, DECEMBER 31, 2011		227,500,190	$	2	$	3,325		$	(63	)	$	1,072		$	4,336

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, primarily to commercial, industrial and government customers. Pepco Energy Services is in the process of winding down its competitive electricity and natural gas retail supply business. Pepco Energy Services constitutes a separate segment for financial reporting purposes.

PHI Service Company, a 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 a service agreement 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 methods set forth in the service agreement.

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 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 Office Service in Delaware, the District of Columbia and Maryland, and Basic Generation Service in New Jersey. In these Notes to the consolidated financial statements, these supply service obligations are referred to generally as Default Electricity Supply.

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Pepco Energy Services

Pepco Energy Services is engaged in the following businesses:

• providing energy efficiency services principally to federal, state and local government customers, and designing, constructing and operating combined heat and power and central energy plants,

• providing high voltage electric construction and maintenance services to customers throughout the United States and low voltage electric construction and maintenance services and streetlight construction and asset management services to utilities, municipalities and other customers in the Washington, D.C. metropolitan area, and

• retail supply of electricity and natural gas under its remaining contractual obligations.

Pepco Energy Services also owns and operates two oil-fired generation facilities that are scheduled for deactivation in May 2012.

In December 2009, PHI announced the wind-down of the retail energy supply component of the Pepco Energy Services business. Pepco Energy Services is implementing this wind-down by not entering into any new supply contracts while continuing to perform under its existing supply contracts through their respective expiration dates, the last of which is June 1, 2014. The retail energy supply business has historically generated a substantial portion of the operating revenues and net income of the Pepco Energy Services segment. Operating revenues related to the retail energy supply business for the years ended December 31, 2011, 2010 and 2009 were $0.9 billion, $1.6 billion and $2.3 billion, respectively, while operating income for the same periods was $11 million, $59 million and $88 million, respectively.

In connection with the operation of the retail energy supply business, Pepco Energy Services provided letters of credit of $1 million and posted cash collateral of $112 million as of December 31, 2011. These collateral requirements, which are based on existing wholesale energy purchase and sale contracts and current market prices, will decrease as the contracts expire, with the collateral expected to be no longer needed by June 1, 2014. The energy services business will not be affected by the wind-down of the retail energy supply business.

Other Business Operations

Through its subsidiary Potomac Capital Investment Corporation (PCI), PHI maintains a portfolio of cross-border energy lease investments. This activity constitutes a third operating segment for financial reporting purposes, which is designated as “Other Non-Regulated.” For a discussion of PHI’s cross-border energy lease investments, see Note (8), “Leasing Activities,” and Note (17), “Commitments and Contingencies –– PHI’s Cross-Border Energy Lease Investments.”

Discontinued Operations

In April 2010, the Board of Directors approved a plan for the disposition of PHI’s competitive wholesale power generation, marketing and supply business, which had been conducted through subsidiaries of Conectiv Energy Holding Company (collectively Conectiv Energy). On July 1, 2010, PHI completed the sale of Conectiv Energy’s wholesale power generation business to Calpine Corporation (Calpine) for $1.64 billion. The disposition of all of Conectiv Energy’s remaining assets and businesses, consisting of its load service supply contracts, energy hedging portfolio, certain tolling agreements and other assets not included in the Calpine sale, is substantially complete. The operations of Conectiv Energy are being accounted for as a discontinued operation and no longer constitute a separate segment for financial reporting purposes. Substantially all of the information in these Notes to the Consolidated Financial Statements with respect to the operations of the former Conectiv Energy segment has been consolidated in Note (20), “Discontinued Operations.”

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(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 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. Subsidiaries of PHI have the following contractual arrangements to which the guidance applies.

ACE Power Purchase Agreements

PHI, through its ACE subsidiary, is a party to three power purchase agreements (PPAs) with unaffiliated, non-utility generators (NUGs) totaling 459 megawatts. One of the agreements ends in 2016 and the other two end in 2024. PHI was 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, it applied the scope exemption from the consolidation guidance for enterprises that have not been able to obtain such information.

Net purchase activities with the NUGs for the years ended December 31, 2011, 2010 and 2009, were approximately $218 million, $292 million and $282 million, respectively, of which approximately $206 million, $270 million and $262 million, respectively, consisted of power purchases under the PPAs. The power purchase costs are recoverable from ACE’s customers through regulated rates.

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. PHI, through its DPL subsidiary, has entered into three land-based wind PPAs in the aggregate amount of 128 megawatts and one solar PPA with a 10 megawatt facility as of December 31, 2011. All of the facilities associated with these PPAs are operational, and DPL is obligated to purchase energy and RECs in amounts generated and delivered by the wind facilities and solar renewable energy credits (SRECs) from the solar facility at rates that are primarily fixed under these agreements. PHI has concluded that consolidation is not required for any of these agreements under the FASB guidance on the consolidation of variable interest entities.

DPL is obligated to purchase energy and RECs from one of the wind facilities through 2024 in amounts not to exceed 50 megawatts, the second of the wind facilities through 2031 in amounts not to exceed 40 megawatts, and the third facility through 2031 in amounts not to exceed 38 megawatts. DPL’s purchases under the three wind PPAs totaled $18 million and $12 million for the years ended December 31, 2011 and 2010, respectively. The term of the agreement with the solar facility is 20 years and DPL is obligated to purchase SRECs in an amount up to 70 percent of the energy output at a fixed price. DPL’s purchases under the agreement were $1 million for the year ended December 31, 2011.

In addition to the three land-based wind PPAs, PHI, through its DPL subsidiary, has also entered into an offshore wind PPA for a 200 megawatt facility that has not yet been constructed. In December 2011, the developer of the offshore wind facility notified DPL that it was terminating the wind PPA for this facility. DPL received a $2 million termination payment from the developer that will be refunded to DPL’s Delaware customers.

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 megawatts to be constructed by a qualified fuel cell provider. The tariff and the RPS establish that DPL would be an agent to collect payments in advance from its distribution customers and remit them to the qualified fuel cell provider for each megawatt hour of energy produced by the fuel cell facilities over 20 years. DPL would have no liability to the qualified fuel cell provider other than to remit payments collected from its distribution customers pursuant to the tariff. The RPS provides for a reduction in DPL’s REC requirements based upon the actual energy output of the facilities. PHI has concluded that DPL would account for this arrangement as an agency transaction.

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Atlantic City Electric Transition Funding LLC

Atlantic City Electric Transition Funding LLC (ACE Funding) was established in 2001 by ACE 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 have been transferred to ACE in exchange for the transfer by ACE to ACE Funding of the right to collect non-bypassable transition bond charges (the Transition Bond Charges) from ACE customers pursuant to bondable stranded costs rate orders issued by the New Jersey Board of Public Utilities (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). ACE collects the Transition Bond Charges from its customers on behalf of ACE Funding and the holders of the Transition Bonds. 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 the Transition Bonds have recourse only to the assets of ACE Funding. ACE owns 100 percent of the equity of ACE Funding and PHI consolidates ACE Funding in its financial statements as ACE is the primary beneficiary of ACE Funding under the variable interest entity consolidation guidance.

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. The SOCAs were established under a New Jersey law enacted to promote the construction of qualified electric generation facilities in New Jersey. The SOCAs are 15-year, financially settled transactions approved by the NJBPU that allow generators to receive payments from, or make payments to, ACE based on the difference between the fixed price in the SOCAs and the price for capacity that clears PJM Interconnection, LLC (PJM). Each of the other electricity distribution companies (EDCs) in New Jersey has entered into SOCAs having the same terms with the same generation companies. The annual share of payments or receipts for ACE and the other EDCs is based upon each company’s annual proportion of the total New Jersey load attributable to all EDCs. The NJBPU has approved full recovery from distribution customers of payments made by ACE and the other EDCs, and distribution customers would be entitled to any payments received by ACE and the other EDCs.

ACE and the other EDCs entered the SOCAs under protest based on concerns about the potential cost to distribution customers. In May 2011, the NJBPU denied a joint motion for reconsideration of its order requiring each of the EDCs to enter into the SOCAs. In June 2011, ACE and the other EDCs filed appeals related to the NJBPU orders with the Appellate Division of the New Jersey Superior Court. In February 2011, ACE joined other plaintiffs in an action filed in the United States District Court for the District of New Jersey challenging the constitutionality of the New Jersey law. ACE and the other plaintiffs filed a motion for summary judgment with the United States District Court for the District of New Jersey in December 2011.

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Two of the generation companies sent a notice of dispute under the SOCA to ACE. The notice of dispute alleges that certain actions taken by PJM have an adverse effect on the generation company’s ability to clear the PJM auction as required by the SOCA. In November 2011, one of the generation companies filed a petition with the NJBPU to change its SOCA. ACE does not believe that a dispute exists under the SOCAs.

Currently, PHI believes that FASB guidance on derivative accounting and the accounting for regulated operations would apply to ACE’s obligations under the SOCA once the related capacity has cleared a PJM auction. Once cleared, the gain (loss) associated with the fair value of a derivative would be offset by the recognition of a regulatory liability (asset). The next PJM capacity auction is scheduled for May 2012.

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 goodwill and long-lived assets for impairment, fair value calculations for certain derivative instruments, the costs of providing pension and other postretirement benefits, evaluation of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of self-insurance reserves for general and auto liability claims, accrual of interest related to income taxes, accrual of restructuring charges, recognition of changes in network service transmission rates for prior service year costs, and the recognition of income tax benefits for investments in finance leases held in trust associated with PHI’s portfolio of cross-border energy lease investments. 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.

Storm Costs

During 2011, Pepco, DPL and ACE incurred significant costs associated with Hurricane Irene that affected their respective service territories. Total incremental storm costs associated with Hurricane Irene were $43 million, with $28 million incurred for repair work and $15 million incurred as capital expenditures. Costs incurred for repair work of $22 million were deferred as regulatory assets to reflect the probable recovery of these storm costs in certain jurisdictions, and the remaining $6 million was charged to Other operation and maintenance expense. Approximately $6 million of these total incremental storm costs have been estimated for the cost of restoration services provided by outside contractors. Since the invoices for such services had not been received at December 31, 2011, actual invoices may vary from these estimates. PHI’s utility subsidiaries are seeking recovery of the incremental Hurricane Irene costs in each of their various jurisdictions in pending or planned distribution rate case filings.

Accrual of Interest Associated with 1996 to 2002 Federal Income Tax Returns

In November 2010, PHI reached final settlement with the Internal Revenue Service (IRS) with respect to its federal tax returns for the years 1996 to 2002 for all issues except its cross-border energy lease investments. PHI also reallocated certain amounts on deposit with the IRS since 2006 among liabilities in the settlement years and subsequent years. In connection with these activities, PHI has recalculated the estimated interest due for the tax years 1996 to 2002. These calculations resulted in the reversal of $15 million (after-tax) of previously accrued estimated interest due to the IRS which was recorded as an income tax benefit in the fourth quarter of 2010. PHI recorded a further $17 million (after-tax) income tax benefit in the second quarter of 2011.

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Restructuring Charge

In the second quarter of 2010, PHI commenced a comprehensive organizational review to identify opportunities to streamline the organization and to achieve certain reductions in corporate overhead costs allocated to its operating segments. The restructuring plan resulted in the elimination of 164 employee positions and the recording of an associated estimated accrued expense for termination benefits in the amount of $30 million. The calculation of these termination benefits, the majority of which were paid in 2011, was based on estimated severance costs and actuarial calculations of the present value of certain changes in pension and other postretirement benefits for terminated employees. There were no material changes to this accrual in 2011.

Network Service Transmission Rates

In May of each year, each of PHI’s utility subsidiaries provides its updated network service transmission rate to the Federal Energy Regulatory Commission (FERC) effective for the service year beginning June 1 of the current year and ending on May 31 of the following year. The network service transmission rate includes a true-up for costs incurred in the prior service year not yet reflected in rates charged to customers.

Investments in Finance Leases Held in Trust

As further discussed in Note (8), “Leasing Activities,” Note (12), “Income Taxes,” and Note (17), “Commitments and Contingencies — PHI’s Cross-Border Energy Lease Investments,” PHI maintains a portfolio of cross-border energy lease investments. The book equity value of these cross-border energy lease investments and the pattern of recognizing the related cross-border energy lease income are based on the estimated timing and amount of all cash flows related to the cross-border energy lease investments, including income tax-related cash flows. These investments are more commonly referred to as sale-in lease-out, or SILO, transactions. PHI currently derives tax benefits from these investments to the extent that rental income is exceeded by depreciation deductions based on the purchase price of the assets and interest deductions on the non-recourse debt financing (obtained to fund a substantial portion of the purchase price of the assets). The IRS has announced broadly its intention to disallow the tax benefits recognized by all taxpayers on these types of investments. More specifically, the IRS has disallowed interest and depreciation deductions claimed by PHI related to its cross-border energy lease investments on its 2001 through 2005 federal income tax returns, which currently are under audit and the IRS has sought to recharacterize the leases as loan transactions as to which PHI would be subject to original issue discount income.

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In the last several years, IRS challenges to certain cross-border energy lease investment transactions have been the subject of litigation. PHI believes that its tax position with regard to its cross-border energy lease investments was appropriate based on applicable statutes, regulations and case law. However, after evaluating the court rulings available at the time, there have been several decisions in favor of the IRS that were factored into PHI’s decision to adjust the values of the cross-border energy lease investments at certain points in time.

Revenue Recognition

Regulated Revenue

Power Delivery recognizes revenue upon distribution of electricity and gas to its customers, including unbilled revenue for services rendered but not yet billed. PHI’s unbilled revenue was $179 million and $218 million as of December 31, 2011 and 2010, 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 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 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 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. Excise tax related generally to the consumption of gasoline by PHI and its subsidiaries in the normal course of business is charged to operations, maintenance or construction, and is not material.

Pepco Energy Services Revenue

Pepco Energy Services has recognized revenue upon distribution of electricity and gas to the customer, including amounts for electricity and gas delivered, but not yet billed. Sales and purchases of electric power to independent system operators are netted hourly and classified as operating revenue or operating expenses, as appropriate. Unrealized derivative gains and losses are recognized in current earnings as revenue if the derivatives do not qualify for hedge accounting or normal purchases or normal sales treatment under FASB guidance on derivatives and hedging (ASC 815). Revenue for Pepco Energy Services’ energy services business is recognized using the percentage-of-completion method, for its construction activities, which recognizes revenue as work is completed on the contract. Revenues from its operation and maintenance activities and measurement and verification activities in its energy services business are recognized when earned.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in PHI’s gross revenues were $390 million, $373 million and $293 million for the years ended December 31, 2011, 2010 and 2009, respectively.

Accounting for Derivatives

PHI and its subsidiaries 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.

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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 unless designated as normal purchases or normal sales.

Changes in the fair value of derivatives held by PES and DPL that are not designated as hedges or do not qualify for hedge accounting are presented on the consolidated statements of income as Operating revenue or Fuel and purchased energy expense, respectively. Changes in the fair value of derivatives held by DPL are deferred as regulatory assets or liabilities under the accounting guidance for regulated activities.

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 as Operating revenue or as a Fuel and purchased energy expense.

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 as Operating revenue in the consolidated statements of income.

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 as Operating revenue or as a 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. See Note (15), “Derivative Instruments and Hedging Activities,” for more information about the components of unrealized and realized gains and losses on derivatives.

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 are used to determine fair value. For some custom and complex instruments, internal models are used to interpolate broker-quality price information. For certain long-dated instruments, broker or exchange data are extrapolated for future periods where limited market information is available. Models are also used to estimate volumes for certain transactions. See Note (15), “Derivative Instruments and Hedging Activities,” for more information about the types of derivatives employed by PHI and Note (16), “Fair Value Disclosures,” for the methodologies used to value them.

PHI designates certain commodity forwards as normal purchases or normal sales, which are not required to be recorded in the financial statements until they are settled. These commodity forwards are used in normal operations, settle physically and follow standard accrual accounting. Unrealized gains and losses on these contracts are not recorded in the financial statements. Examples of these commodity forwards include purchases by Pepco Energy Services of natural gas or electricity for delivery to customers. Normal sales transactions include agreements by Pepco Energy Services to deliver natural gas and electric power to customers. Normal purchases and normal sales transactions are separately presented on a gross basis when they settle, with normal sales recorded as Operating revenue and normal purchases recorded as Fuel and purchased energy expenses.

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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. In addition, compensation expense recognized includes the cost for all stock-based awards granted prior to, but not yet vested as of January 1, 2006, measured at the grant-date fair value. 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 and restricted stock awards, which are deductible only upon exercise and 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 units that were earned based on performance over a three-year period. Beginning in 2011, compensation awards have been granted solely in the form of restricted stock units. 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 three-year service or performance period.

PHI estimates the fair value of stock option awards on the date of grant using the Black-Scholes-Merton option pricing model. This model uses assumptions related to expected term, expected volatility, expected dividend yield, and the risk-free interest rate. PHI uses historical data to estimate award exercises and employee terminations within the valuation model; groups of employees that have similar historical exercise behavior are considered separately for valuation purposes.

PHI’s current policy is to issue new shares to satisfy both stock option exercises and 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 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 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 (12), “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.

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Restricted Cash Equivalents

The restricted cash equivalents included in Current Assets and the restricted cash equivalents included in Investments and 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

Pepco Holdings’ accounts receivable balances primarily consist of customer accounts receivable, other accounts receivable, and accrued unbilled revenue generated by subsidiaries in Power Delivery and at Pepco Energy Services. 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. 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. Although management 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

Inventory is valued at the lower of cost or market value. Included in inventories are generation, transmission and distribution materials and supplies, natural gas and fuel oil.

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 inventory are recorded in inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed.

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. Substantially all of Pepco Holdings’ goodwill was generated by Pepco’s acquisition of Conectiv in 2002 and is allocated entirely to Power Delivery for purposes of impairment testing based on the aggregation of its components because its utilities have similar characteristics. Pepco Holdings 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 reduce the fair value of a reporting unit below its carrying amount. 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 decline in PHI’s stock price causing market capitalization to fall below book value; an adverse regulatory action; or an impairment of long-lived assets in the reporting unit. PHI performed its annual impairment test on November 1, 2011 and its goodwill was not impaired as described in Note (6), “Goodwill.”

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Regulatory Assets and Regulatory Liabilities

The Power Delivery operations of Pepco are regulated by the District of Columbia Public Service Commission (DCPSC) and the Maryland Public Service Commission (MPSC). The Power Delivery 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 Power Delivery operations of ACE are regulated by the NJBPU. The transmission of electricity by Pepco, DPL, and ACE are 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. 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 mechanism (BSA) for retail customers of Pepco and DPL. Effective November 2009, the DCPSC approved a BSA for Pepco’s retail customers. See Note (7), “Regulatory Matters—Regulatory Proceedings.” 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 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 is an equity participant, is accounted for using the financing method. In accordance with the financing method, investments in leased property are recorded as a receivable from the lessee to be recovered through the collection of future rentals. Income, including investment tax credits, on leveraged equipment leases is recognized over the life of the lease at a constant rate of return on the positive net investment. Each quarter, PHI reviews the carrying value of each lease, which includes 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, would be 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 occur.

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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 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 are 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 gas property, plant and equipment is computed on a straight-line basis using composite rates by classes of depreciable property. Accumulated depreciation is charged with the cost of depreciable property retired, less salvage and other recoveries. Property, plant and equipment, other than electric and gas facilities, 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, 2011, 2010 and 2009.

	Transmission and Distribution									Generation
	2011			2010			2009			2011			2010			2009
Pepco		2.6	%		2.6	%		2.7	%		—			—			—
DPL		2.8	%		2.8	%		2.8	%		—			—			—
ACE		3.0	%		2.8	%		2.8	%		—			—			—
Pepco Energy Services (a)		—			—			—			10.2	%		16.9	%		11.4	%

(a) Percentages reflect accelerated depreciation of the Benning Road and Buzzard Point generating plants scheduled for retirement in May 2012.

In 2010, subsidiaries of PHI received awards from the U.S. Department of Energy under the American Recovery and Reinvestment Act of 2009. Pepco was awarded $149 million to fund a portion of the costs incurred for the implementation of an advanced metering infrastructure (AMI) system, direct load control, distribution automation and communications infrastructure in its Maryland and District of Columbia service territories. ACE was awarded $19 million 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 has elected to recognize the awards as a reduction in the carrying value of the assets acquired rather than grant income over the service period.

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Long-Lived Asset Impairment Evaluation

Pepco Holdings 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 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 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 can 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.

Pepco Holdings recorded AFUDC for borrowed funds of $11 million, $8 million and $7 million for the years ended December 31, 2011, 2010 and 2009, respectively.

Pepco Holdings recorded amounts for the equity component of AFUDC of $15 million, $10 million and $3 million for the years ended December 31, 2011, 2010 and 2009, 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 issues. 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 generally over the life of the original issue.

Asset Removal Costs

In accordance with FASB guidance, asset removal costs are recorded by PHI utility subsidiaries as regulatory liabilities. At December 31, 2011 and 2010, $388 million and $361 million of asset removal costs, respectively, are included in Regulatory liabilities in the accompanying consolidated balance sheets.

Pension and Postretirement Benefit Plans

Pepco Holdings sponsors the PHI Retirement Plan, a non-contributory, defined benefit pension plan that covers substantially all employees of Pepco, DPL, ACE and certain employees of other Pepco Holdings subsidiaries. Pepco Holdings also provides supplemental retirement benefits to certain eligible executives and key employees through a nonqualified retirement plan and provides certain postretirement health care and life insurance benefits for eligible retired employees.

Pepco Holdings accounts for the PHI Retirement Plan, the nonqualified retirement plans, and the retirement healthcare and life insurance benefit plans in accordance with FASB guidance on Retirement Benefits (ASC 715).

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See Note (10), “Pension and Other Postretirement Benefits,” for additional information.

Preferred Stock

As of December 31, 2011 and 2010, PHI had 40 million shares of preferred stock authorized for issuance, with a par value of $.01 per share. No shares of preferred stock were outstanding at December 31, 2011 and 2010.

Reclassifications and Adjustments

Certain prior period amounts have been reclassified in order to conform to current period presentation. The following adjustments have been recorded and are not considered material individually or in the aggregate:

Default Electricity Supply Revenue and Costs Adjustments

During 2011, DPL recorded adjustments associated with the accounting for Default Electricity Supply revenue and costs. These adjustments were primarily due to the under-recognition of allowed returns on working capital and under-recoveries of administrative costs, and resulted in a pre-tax decrease in Other operation and maintenance expense of $11 million for the year ended December 31, 2011.

Pepco Energy Services Derivative Accounting Adjustments

During 2011, PHI recorded an adjustment associated with an increase in the value of certain derivatives from October 1, 2010 to December 31, 2010, which had been erroneously recorded in other comprehensive income at December 31, 2010. This adjustment resulted in an increase in revenue and pre-tax earnings of $2 million for the year ended December 31, 2011.

Operating Expenses

During 2010, Pepco recorded an adjustment to correct certain errors related to other taxes which resulted in a decrease to Other taxes expense of $5 million (pre-tax).

As further described in Note (9), “Property, Plant and Equipment,” in the fourth quarter of 2010, PHI recorded an accrual of $4 million for the obligations associated with the planned deactivation of Pepco Energy Services’ two oil-fired generating facilities. Of this amount, $1 million should have been recorded in each of 2009, 2008 and 2007.

Income Tax Expense Related to Continuing Operations

During 2011, PHI recorded adjustments to correct certain income tax errors related to prior periods associated with the interest on uncertain tax positions. The adjustment resulted in an increase in income tax expense of $2 million.

During 2010, PHI recorded an adjustment to correct certain income tax errors related to prior periods. The adjustment resulted in a decrease in income tax expense of $5 million.

During 2009, PHI recorded certain adjustments to correct errors related to income taxes. These adjustments, which primarily resulted from the completion of additional analysis of the current and deferred income tax balances, resulted in a decrease in income tax expense of $6 million.

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(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Fair Value Measurements and Disclosures (ASC 820)

The FASB issued new disclosure requirements that require significant items within the reconciliation of the Level 3 valuation category to be presented in separate categories for purchases, sales, issuances and settlements. The guidance was effective beginning with PHI’s March 31, 2011 consolidated financial statements. PHI has included the new disclosure requirements in Note (16), “Fair Value Disclosures,” to its consolidated financial statements.

Goodwill (ASC 350)

The FASB issued new guidance on performing goodwill impairment tests that was effective beginning January 1, 2011 for PHI. Under the new guidance, the carrying value of the reporting unit must include the liabilities that are part of the capital structure of the reporting unit. PHI already allocates liabilities to the reporting unit when performing its goodwill impairment test, so the new guidance did not change PHI’s goodwill impairment test methodology.

Revenue Recognition (ASC 605)

The FASB issued new guidance to help determine separate units of accounting for multiple-deliverables within a single contract that was effective beginning January 1, 2011 for PHI. The energy services contracts of Pepco Energy Services are primarily impacted by this guidance because they often have multiple elements, which could include design, installation, operation and maintenance, and measurement and verification services. PHI and its subsidiaries adopted the new guidance, effective January 1, 2011, and it did not have a material impact on Pepco Energy Services’ revenue recognition methods or results of operations, nor did it have a material impact on PHI’s overall financial condition, results of operations or cash flows.

(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Fair Value Measurements and Disclosures (ASC 820)

In May 2011, the FASB issued new guidance on fair value measurement and disclosures that will be effective beginning with PHI’s March 31, 2012 consolidated financial statements. The new guidance will change how fair value is measured in specific instances and expand disclosures about fair value measurements. PHI expects that it will have to provide additional disclosures, but does not expect this guidance to have a significant impact on its fair value measurements.

Comprehensive Income (ASC 220)

In June 2011, the FASB issued new guidance that requires entities to report comprehensive income in one of two ways: (i) one single continuous statement that combines the income statement with the statement of other comprehensive income and totals to a comprehensive income amount; or (ii) in two separate but consecutive statements of income and other comprehensive income. In December 2011, the FASB indefinitely deferred the requirement that entities separately present items in their income statement that had been reclassified from other comprehensive income. PHI currently applies the second option in its consolidated financial statements, so PHI expects that this guidance will have minimal impact on its consolidated financial statements. The new guidance is effective beginning with PHI’s March 31, 2012 consolidated financial statements.

Goodwill (ASC 350)

In September 2011, the FASB issued new guidance that changes the annual and interim assessments of goodwill for impairment. The new guidance modifies the required annual impairment test by giving entities the option to perform a qualitative assessment of whether it is more likely than not that goodwill is impaired before performing a quantitative assessment. The new guidance also amends the events and

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circumstances that entities should assess to determine whether an interim quantitative impairment test is necessary. The new guidance is effective beginning January 1, 2012 for PHI as it did not elect the option to apply the guidance earlier. PHI did not employ the new qualitative assessment as part of its November 1, 2011 annual impairment test. PHI does not expect the new impairment guidance to have a material impact on its consolidated financial statements.

Balance Sheet (ASC 210)

In December 2011, the FASB issued new disclosure requirements for assets and liabilities, such as derivatives, that are subject to contractual netting arrangements. The new disclosures will include information about the gross exposures and net exposure under contractual netting arrangements as well as how the exposures are presented in the financial statements. The new disclosures are effective beginning with PHI’s March 31, 2013 consolidated financial statements. PHI is evaluating the impact of this new guidance on its consolidated financial statements.

(5) SEGMENT INFORMATION

Pepco Holdings’ management has identified its operating segments at December 31, 2011 as Power Delivery, Pepco Energy Services and Other Non-Regulated. 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. Segment financial information for continuing operations for the years ended December 31, 2011, 2010 and 2009, is as follows:

	Year Ended December 31, 2011
	(millions of dollars)
	Power Delivery		Pepco Energy Services		Other Non- Regulated			Corporate and Other (a)			PHI Consolidated
Operating Revenue	$	4,650	$	1,238	$	48		$	(16	)	$	5,920
Operating Expenses (b)		4,150		1,206		(30	)(c)		(43	)		5,283
Operating Income		500		32		78			27			637
Interest Income		1		1		4			(5	)		1
Interest Expense		208		3		13			30			254
Impairment Losses		—		—		—			(5	)		(5	)
Other Income (Expenses)		29		3		(4	)		2			30
Preferred Stock Dividends		—		—		3			(3	)		—
Income Tax Expense (d)		112		9		27			1			149
Net Income (Loss) from Continuing Operations		210		24		35	(c)		(9	)		260
Total Assets		11,008		565		1,499			1,838			14,910
Construction Expenditures	$	888	$	14	$	—		$	39		$	941

(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 the Corporate and Other segment and are allocated to Power Delivery once the assets are placed in service. Corporate and Other includes intercompany amounts of $(16) million for Operating Revenue, $(15) million for Operating Expense, $(22) million for Interest Income, $(22) million for Interest Expense, and $(3) million for Preferred Stock Dividends.

(b) Includes depreciation and amortization expense of $426 million, consisting of $394 million for Power Delivery, $17 million for Pepco Energy Services, $2 million for Other Non-Regulated, and $13 million for Corporate and Other.

(c) Includes $39 million pre-tax ($3 million after-tax) gain from the early termination of cross-border energy leases held in trust.

(d) Includes tax benefits of $14 million for Power Delivery primarily associated with an interest benefit related to federal tax liabilities and a $22 million reversal of previously recognized tax benefits for Other Non-Regulated associated with the early termination of cross-border energy leases held in trust.

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	Year Ended December 31, 2010
	(millions of dollars)
	Power Delivery			Pepco Energy Services		Other Non- Regulated			Corporate and Other (a)			PHI Consolidated
Operating Revenue	$	5,114		$	1,883	$	54		$	(12	)	$	7,039
Operating Expenses (b)(c)		4,611	(d)		1,812		6			(14	)		6,415
Operating Income		503			71		48			2			624
Interest Income		2			1		3			(6	)		—
Interest Expense		207			16		12			71			306
Other Income (Expenses)		20			2		(2	)		1			21
Loss on Extinguishment of Debt		—			—		—			(189	)(e)		(189	)
Preferred Stock Dividends		—			—		3			(3	)		—
Income Tax Expense (Benefit)		112	(f)		22		9			(132	)(g)		11
Net Income (Loss) from Continuing Operations		206			36		25			(128	)		139
Total Assets		10,621			623		1,537			1,582			14,363
Construction Expenditures	$	765		$	7	$	—		$	30		$	802

(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 the Corporate and Other segment and are allocated to Power Delivery once the assets are placed in service. Corporate and Other includes intercompany amounts of $(12) million for Operating Revenue, $(10) million for Operating Expense, $(36) million for Interest Income, $(36) million for Interest Expense, and $(3) million for Preferred Stock Dividends.

(b) Includes depreciation and amortization expense of $393 million, consisting of $357 million for Power Delivery, $24 million for Pepco Energy Services, $1 million for Other Non-Regulated, and $11 million for Corporate and Other.

(c) Includes restructuring charge of $30 million, consisting of $29 million for Power Delivery and $1 million for Corporate and Other.

(d) Includes $11 million expense related to effects of Pepco divestiture-related claims.

(e) Includes $174 million ($104 million after-tax) related to loss on extinguishment of debt and $15 million ($9 million after-tax) related to the reclassification of treasury rate lock losses from AOCL to income related to cash tender offers for debt made in 2010.

(f) Includes $12 million of net Federal and state income tax benefits primarily related to adjustments of accrued interest on uncertain and effectively settled tax positions.

(g) Includes $14 million of state tax benefits resulting from the restructuring of certain PHI subsidiaries and $17 million of state income tax benefits associated with the loss on extinguishment of debt, partially offset by a charge of $3 million to write off deferred tax assets related to the subsidy pursuant to the prescription drug benefit (Medicare Part D) under the Medicare Prescription Drug Improvement and Modernization Act of 2003 (the Medicare Act).

	Year Ended December 31, 2009
	(millions of dollars)
	Power Delivery			Pepco Energy Services		Other Non- Regulated		Corporate and Other (a)			PHI Consolidated
Operating Revenue	$	4,980		$	2,383	$	51	$	(12	)	$	7,402
Operating Expenses (b)		4,475	(c)		2,294		4		(19	)		6,754
Operating Income		505			89		47		7			648
Interest Income		3			1		4		(6	)		2
Interest Expense		211			30		14		85			340
Other Income		11			3		2		1			17
Preferred Stock Dividends		—			—		3		(3	)		—
Income Tax Expense (Benefit)		109			23		5		(33	)		104
Net Income (Loss) from Continuing Operations		199	(d)		40		31		(47	)		223
Total Assets		10,239			734		1,515		1,294			13,782
Construction Expenditures	$	622		$	12	$	—	$	30		$	664

(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 the Corporate and Other segment and are allocated to Power Delivery once the assets are placed in service. Corporate and Other includes intercompany amounts of $(12) million for Operating Revenue, $(4) million for Operating Expense, $(76) million for Interest Income, $(73) million for Interest Expense, and $(3) million for Preferred Stock Dividends.

(b) Includes depreciation and amortization expense of $349 million, consisting of $323 million for Power Delivery, $18 million for Pepco Energy Services, $2 million for Other Non-Regulated, and $6 million for Corporate and Other.

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(c) Includes $40 million ($24 million after-tax) gain related to effects of Pepco divestiture-related claims.

(d) Includes $11 million after-tax state income tax benefit, net of fees, related to a change in the tax reporting for the disposition of certain assets in prior years.

(6) GOODWILL

Substantially all of PHI’s $1.4 billion goodwill balance was generated by Pepco’s acquisition of Conectiv in 2002. The goodwill 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’s annual impairment test as of November 1, 2011 indicated that goodwill was not impaired.

In order to estimate the fair value of its Power Delivery reporting unit, PHI uses two valuation techniques: an income approach and a market approach. The income approach estimates fair value based on a discounted cash flow analysis using estimated future cash flows 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 market-based information for the cost of equity and cost of debt that is appropriate for Power Delivery 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 management believes is consistent with EBITDA multiples for comparable utilities. PHI has consistently used this valuation framework to estimate the fair value of Power Delivery.

The estimation of fair value is dependent on a number of factors that are derived from the Power Delivery reporting unit’s business forecast, 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 affect the results of impairment testing. Assumptions used in the models were consistent with historical experience, including assumptions concerning the recovery of operating costs and capital expenditures. 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, changes in forecasted revenues, higher operating and maintenance capital expenditure requirements, a significant increase in the cost of capital and other factors.

In addition to estimating the fair value of its Power Delivery reporting unit, PHI estimated the fair value of its other reporting units (Pepco Energy Services and Other Non-Regulated) at November 1, 2011. The sum of the fair value of all reporting units was reconciled to PHI’s market capitalization at November 1, 2011 to corroborate estimates of the fair value of its reporting units. The sum of the estimated fair values of all reporting units exceeded the market capitalization of PHI at November 1, 2011. PHI believes that the excess of the estimated fair value of PHI’s reporting units as compared to PHI’s market capitalization reflects a reasonable control premium that is comparable to control premiums observed in historical acquisitions in the utility industry during various economic environments.

As discussed in Note (1), “Organization,” in December 2009, PHI announced the wind-down of the Pepco Energy Services retail energy supply business. As a result of this decision, PHI determined that all goodwill allocated to this business was impaired and PHI recorded a goodwill impairment charge of $4 million in the fourth quarter of 2009 to write-off the goodwill associated with this business.

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PHI’s gross amount of goodwill, accumulated impairment losses and carrying amount of goodwill for the years ended December 31, 2011 and 2010 were as follows:

	2011						2010
	Gross Amount		Accumulated Impairment Losses		Carrying Amount		Gross Amount		Accumulated Impairment Losses		Carrying Amount
	(millions of dollars)
Beginning balance as of January 1	$	1,425	$	18	$	1,407	$	1,425	$	18	$	1,407
Impairment losses		—		—		—		—		—		—
Ending balance as of December 31	$	1,425	$	18	$	1,407	$	1,425	$	18	$	1,407

(7) REGULATORY MATTERS

Regulatory Assets and Regulatory Liabilities

The components of Pepco Holdings’ regulatory asset and liability balances at December 31, 2011 and 2010 are as follows:

	2011		2010
	(millions of dollars)
Regulatory Assets
Pension and OPEB costs (a)	$	1,037	$	848
Securitized stranded costs (a)		481		559
Deferred income taxes		145		139
Deferred energy supply costs (a)		124		61
Recoverable meter-related costs (a)		112		44
Deferred debt extinguishment costs (a)		57		61
Recoverable workers compensation and long-term disability costs		34		28
Blueprint for the Future		30		16
Deferred losses on gas derivatives		17		31
Other		159		128
Total Regulatory Assets	$	2,196	$	1,915
Regulatory Liabilities
Asset removal costs	$	388	$	361
Deferred income taxes due to customers		48		50
Deferred energy supply costs		33		35
Excess depreciation reserve		26		42
Other		31		40
Total Regulatory Liabilities	$	526	$	528

(a) A return is generally earned on these deferrals.

A description for each category of regulatory assets and regulatory liabilities follows:

Pension and OPEB Costs: Represents unrecognized amounts related to net actuarial losses, prior service cost (credit), and transition liability 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

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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 (10), “Pension and Other Postretirement Benefits,” for more information about the components of the unrecognized pension and OPEB costs.

Securitized Stranded Costs: Includes contract termination payments under a contract between ACE and an unaffiliated NUG and costs associated with the regulated operations of ACE’s electricity generation business which are no longer recoverable through customer rates. The recovery of these stranded costs has been securitized through the issuance of Transition Bonds by ACE Funding. A customer surcharge is collected by ACE to fund principal and interest payments on the Transition Bonds. The stranded costs are amortized over the life of the Transition Bonds, which mature between 2013 and 2023.

Deferred Income Taxes: Represents a receivable from Power Delivery’s customers for tax benefits applicable to utility operations of Pepco, DPL and ACE previously flowed through before the companies were ordered to account for 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 Default Electricity Supply costs incurred by Pepco, DPL and ACE that are probable of recovery in rates. 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 Meter-Related Costs: Represents costs associated with the installation of smart meters and the early retirement of existing meters throughout Pepco’s and DPL’s service territories as a result of the AMI project.

Deferred Debt Extinguishment Costs: Represents the costs of debt extinguishment of Pepco, DPL and ACE for which recovery through regulated utility rates is considered probable and, if approved, will be amortized to interest expense during the authorized rate recovery period.

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.

Blueprint for the Future: Includes costs associated with Blueprint for the Future initiatives which include programs to help customers better manage their energy use and to allow each utility to better manage their electrical and natural gas distribution systems.

Deferred Losses on Gas Derivatives: Represents losses associated with hedges of natural gas purchases that are recoverable through the Gas Cost Rate approved by the DPSC.

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. As such, 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.

Deferred Income Taxes Due to Customers: Represents the portions of deferred income tax liabilities applicable to utility operations of Pepco, DPL and 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.

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Excess Depreciation Reserve: The excess depreciation reserve was recorded as part of an ACE New Jersey rate case settlement. This excess reserve is the result of a change in estimated depreciable lives and a change in depreciation technique from remaining life to whole life that caused an over-recovery for depreciation expense from customers when the remaining life method has been used. The excess is being amortized over an 8.25 year period, which began in June 2005.

Other: Includes miscellaneous regulatory liabilities.

Regulatory Proceedings

District of Columbia Divestiture Case

In June 2000, the DCPSC approved a divestiture settlement under which Pepco is required to share with its District of Columbia customers the net proceeds realized by Pepco from the sale of its generation-related assets in 2000. This approval left unresolved issues of (i) whether Pepco should be required to share with customers the excess deferred income taxes (EDIT) and accumulated deferred investment tax credits (ADITC) associated with the sold assets and, if so, whether such sharing would violate the normalization provisions of the Internal Revenue Code and its implementing regulations and (ii) whether Pepco was entitled to deduct certain costs in determining the amount of proceeds to be shared.

In May 2010, the DCPSC issued an order addressing all of the remaining issues related to the sharing of the proceeds of Pepco’s divestiture of its generating assets. In the order, the DCPSC ruled that Pepco is not required to share EDIT and ADITC with customers. However, the order also disallowed certain items that Pepco had included in the costs deducted from the proceeds of the sale of the generation assets. The disallowance of these costs, together with interest on the disallowed amount, increased the aggregate amount Pepco was required to distribute to customers, pursuant to the sharing formula, by approximately $11 million, which Pepco recognized as an expense in 2010 and refunded the amounts to its customers. In June 2010, Pepco filed an application for reconsideration of the DCPSC’s order. In July 2010, the DCPSC denied Pepco’s application for reconsideration. In September 2010, Pepco filed an appeal of the DCPSC’s decision with the District of Columbia Court of Appeals. On April 12, 2011, the Court of Appeals affirmed the DCPSC order. Pepco determined not to appeal this decision.

Maryland Public Service Commission Reliability Investigation

In August 2010, following major storm events that occurred in July and August 2010, the MPSC initiated a proceeding for the purpose of investigating the reliability of Pepco’s distribution system and the quality of distribution service Pepco provided to its customers. On December 21, 2011, the MPSC issued an order in the proceeding imposing a fine on Pepco of $1 million, which Pepco has paid. In accordance with the order, Pepco filed a detailed work plan for the next five years, which provides a comprehensive description of Pepco’s reliability enhancement plan, its emergency response improvement project, and other communication and service restoration improvements. Pepco is also required to file quarterly updates and a year-end status report with the MPSC providing, among other things, detailed information about its reliability and emergency response improvement objectives; its progress in meeting such objectives, together with an analysis of trends concerning the measured duration and frequency of customer interruptions compared to 2010 baseline data; the amount of spending associated with such objectives; an explanation for any inability to meet such objectives; any proposed changes in funding these improvement projects; any changes to any of these projects; and interim and final results of Pepco’s system inspection program. In addition, Pepco must provide additional detail in these reports about its Estimated Time to Restoration Manager and the Customer Advocate, which personnel have been added by Pepco as part of its emergency response improvement project, and to explore the benefits of damage prediction models.

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Finally, Pepco was required to consider, the comments and suggestions of other interested parties in the reliability proceeding regarding improvements that Pepco might make to its reliability enhancement programs. In these reports, Pepco will be required to demonstrate that its reliability enhancement plan costs were prudently spent and produced a significant improvement in reliability, and if it is unable to do so, the MPSC may deny Pepco reimbursement for future reliability enhancement expenditures or impose additional fines.

The MPSC also stated in the order that it intends to review in Pepco’s pending electric distribution base rate case the recovery of reliability costs and to disallow incremental costs it determines to be the result of imprudent management. Pepco believes its reliability costs have been prudently incurred. Furthermore, Pepco believes that its reliability enhancement plan will enable Pepco to meet the MPSC’s requirements.

Rate Proceedings

Over the last several years, PHI’s utility subsidiaries have proposed in each of their respective service territories the adoption of a mechanism to decouple retail distribution revenue from the amount of power delivered to retail customers. To date:

• A BSA has been approved and implemented for Pepco and DPL electric service in Maryland and for Pepco electric service in the District of Columbia. The MPSC has issued an order requiring modification of the BSA in Maryland so that revenues lost as a result of major storm outages are not collected through the BSA if electric service is not restored to the pre-major storm levels within 24 hours of the start of a major storm (as discussed below).

• A modified fixed variable rate design (MFVRD) has been approved in concept for DPL electric service in Delaware, but the implementation has been deferred by the DPSC pending the development of an implementation plan and a customer education plan. DPL anticipates that the MFVRD will be in place for electric service by early 2013.

• A MFVRD has been approved in concept for DPL natural gas service in Delaware, but implementation likewise has been deferred until development of an implementation plan and a customer education plan. DPL anticipates that the MFVRD will be in place for natural gas service by early 2013.

• In New Jersey, a BSA proposed by ACE as part of a Phase 2 to the base rate proceeding filed in August 2009 was not included in the final settlement approved by the NJBPU on May 16, 2011. Accordingly, there is no BSA proposal currently pending in New Jersey.

Under the BSA, 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. The MFVRD approved in concept in Delaware provides for a fixed customer charge (i.e., not tied to the customer’s volumetric consumption) to recover the utility’s fixed costs, plus a reasonable rate of return. Although different from the BSA, PHI views the MFVRD as an appropriate distribution revenue decoupling mechanism.

Delaware

Gas Cost Rates

DPL makes an annual Gas Cost Rate (GCR) filing with the DPSC for the purpose of allowing DPL to recover natural gas procurement costs through customer rates. In August 2010, DPL made its 2010 GCR filing, which proposes rates that would allow DPL to recover an amount equal to a two-year amortization of currently under-recovered natural gas costs. In October 2010, the DPSC issued an order allowing DPL to place the new rates into effect on November 1, 2010, subject to refund and pending final DPSC

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approval. The effect of the proposed two-year amortization upon rates is an increase of 0.1% in the level of GCR. The parties in the proceeding submitted a proposed settlement to the hearing examiner on June 3, 2011, which includes the first year of DPL’s two-year amortization but provides that DPL will forego the interest ($171,000 for the 2011 to 2012 period covered by the GCR and $171,000 for the 2012 to 2013 period covered by the GCR) associated with that amortization. The proposed settlement was approved by the DPSC on October 18, 2011.

In August 2011, DPL made its 2011 GCR filing. The filing includes the second year of the effect of the proposed two-year amortization as proposed in DPL’s 2010 filing. On September 20, 2011, the DPSC issued an order allowing DPL to place the new rates into effect on November 1, 2011, subject to refund and pending final DPSC approval.

Natural Gas Distribution Base Rates

In July 2010, DPL submitted an application with the DPSC to increase its natural gas distribution base rates. As subsequently amended, the filing sought approval of an annual rate increase of approximately $10.2 million, based on a requested return on equity (ROE) of 11.0%, and requests approval of implementation of the MFVRD. As permitted by Delaware law, DPL placed an annual increase of approximately $2.5 million into effect, on a temporary basis, on August 31, 2010, and the remainder of approximately $7.7 million of the requested increase was placed into effect on February 2, 2011, in each case subject to refund and pending final DPSC approval. On June 21, 2011, the DPSC approved a settlement providing for an annual rate increase of approximately $5.8 million, based on an ROE of 10.0%. The decision deferred the implementation of the MFVRD until an implementation plan and a customer education plan are developed. As of December 31, 2011, the amount collected in excess of the approved rate has been refunded to customers through a bill credit.

Electric Distribution Base Rates

On December 2, 2011, DPL submitted an application with the DPSC to increase its electric distribution base rates. The filing seeks approval of an annual rate increase of approximately $31.8 million, based on a requested ROE of 10.75%, and requests approval of implementation of the MFVRD. DPL has requested that the rates become effective on January 31, 2012. In the effort to reduce the shortfall in revenues due to the delay in time or lag between when costs are incurred and when they are reflected in rates (regulatory lag), the filing includes a request for the DPSC to approve a reliability investment recovery mechanism (RIM) to recover reliability-related capital expenditures incurred between base rate cases. Through the RIM, DPL would collect in a surcharge the amount of its reliability-related capital expenditures based on its budget for the current year. The budgeted amount would be reconciled with actual capital expenditures on an annual basis and any over-recovery or under-recovery would be reflected in the next year’s surcharge. The work undertaken pursuant to the RIM would be subject to a prudency review by the DPSC in the next base rate case or at more frequent intervals as determined by the DPSC. DPL’s operating and maintenance costs and other capital expenditures would remain subject to recovery through the traditional ratemaking process. DPL has also requested DPSC approval of the use of fully forecasted test years in future DPL rate cases. On January 10, 2012, the DPSC entered an order suspending the full increase and allowing a temporary rate increase of $2.5 million to go into effect on January 31, 2012, subject to refund and pending final DPSC approval. As permitted by Delaware law, DPL intends to place the remainder of approximately $29.3 million of the requested increase into effect on July 2, 2012, subject to refund and pending final DPSC approval.

District of Columbia

On July 8, 2011, Pepco filed an application with the DCPSC to increase its electric distribution base rates by approximately $42 million annually, based on an ROE of 10.75%. In the effort to reduce regulatory lag, the filing includes a request for the DCPSC to approve a RIM to recover reliability-related capital

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expenditures incurred between base rate cases. Through the RIM, Pepco would collect in a surcharge the amount of its reliability-related capital expenditures based on its budget for the current year. The budgeted amount would be reconciled with actual capital expenditures on an annual basis and any over-recovery or under-recovery would be reflected in the next year’s surcharge. The work undertaken pursuant to the RIM would be subject to a prudency review by the DCPSC in the next base rate case or at more frequent intervals as determined by the DCPSC. Pepco’s operating and maintenance costs and other capital expenditures would remain subject to recovery through the traditional ratemaking process. A decision by the DCPSC is expected in the second quarter of 2012.

Maryland

DPL Electric Distribution Base Rates

On December 9, 2011, DPL submitted an application with the MPSC to increase its electric distribution base rates. The filing seeks approval of an annual rate increase of approximately $25.2 million, based on a requested ROE of 10.75%. In the effort to reduce regulatory lag, the filing includes a request for the MPSC to approve a RIM to recover reliability-related capital expenditures incurred between base rate cases. Through the RIM, DPL would collect in a surcharge the amount of its reliability-related capital expenditures based on its budget for the current year. The budgeted amount would be reconciled with actual capital expenditures on an annual basis and any over-recovery or under-recovery would be reflected in the next year’s surcharge. The work undertaken pursuant to the RIM would be subject to a prudency review by the MPSC in the next base rate case or at more frequent intervals as determined by the MPSC. DPL’s operating and maintenance costs and other capital expenditures would remain subject to recovery through the traditional ratemaking process. DPL has also requested MPSC approval of the use of fully forecasted test years in future DPL rate cases. A decision by the MPSC is expected in July 2012.

Pepco Electric Distribution Base Rates

On December 16, 2011, Pepco submitted an application with the MPSC to increase its electric distribution base rates. The filing seeks approval of an annual rate increase of approximately $68.4 million, based on a requested ROE of 10.75%. In the effort to reduce regulatory lag, the filing includes a request for the MPSC to approve a RIM to recover reliability-related capital expenditures incurred between base rate cases. Through the RIM, Pepco would collect in a surcharge the amount of its reliability-related capital expenditures based on its budget for the current year. The budgeted amount would be reconciled with actual capital expenditures on an annual basis and any over-recovery or under-recovery would be reflected in the next year’s surcharge. The work undertaken pursuant to the RIM would be subject to a prudency review by the MPSC in the next base rate case or at more frequent intervals as determined by the MPSC. Pepco’s operating and maintenance costs and other capital expenditures would remain subject to recovery through the traditional ratemaking process. Pepco also has requested MPSC approval of the use of fully forecasted test years in future Pepco rate cases. A decision by the MPSC is expected in July 2012.

Major Storm Damage Recovery Proceedings

In February 2011, the MPSC initiated proceedings involving Pepco and DPL, as well as unaffiliated utilities in Maryland, for the purpose of reviewing how the BSA operates to recover revenues lost as a result of major storm outages. On January 25, 2012, the MPSC issued an order modifying the BSA to prevent Pepco and DPL from collecting lost utility revenue through the BSA if electric service is not restored to the pre-major storm levels within 24 hours of the start of a major storm (defined by the MPSC as a weather-related event during which more than the lesser of 10% or 100,000 of an electric utility’s customers have a sustained outage for more than 24 hours). The period for which the lost utility revenue may not be collected through the BSA commences 24 hours after the start of the major storm and continues until all major storm-related outages are restored. The MPSC stated that waivers permitting

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collection of BSA revenues would be granted in rare and extraordinary circumstances where a utility can show that an outage was not due to inadequate emphasis on reliability and restoration efforts were reasonable under the circumstances. A similar provision excluding revenues lost as a result of major storm outages from the calculation of future BSA adjustments is already included in the BSA for Pepco in the District of Columbia as approved by the DCPSC. The financial impact of service interruptions due to a major storm as a result of this MPSC order would generally depend on the scope and duration of the outages.

New Jersey

Electric Distribution Base Rates

On August 5, 2011, ACE filed a petition with the NJBPU to increase its electric distribution rates by the net amount of approximately $58.9 million, based on a return on equity of 10.75% (the ACE 2011 Base Rate Case). The net increase consists of a rate increase proposal of approximately $70.5 million, less a deduction from base rates of approximately $17 million attributable to excess depreciation expenses, plus approximately a $4.9 million increase in sales-and-use taxes and an upward adjustment of approximately $0.5 million in the Regulatory Asset Recovery Charge. A decision in the electric distribution rate case is expected by the end of 2012.

Infrastructure Investment Program

In July 2009, the NJBPU approved certain rate recovery mechanisms in connection with ACE’s Infrastructure Investment Program (the IIP). In exchange for the increase in infrastructure investment, the NJBPU, through the IIP, allowed recovery of ACE’s infrastructure investment capital expenditures through a special rate outside the normal rate recovery mechanism of a base rate filing. The IIP was designed to stimulate the New Jersey economy and provide incremental employment in ACE’s service territory by increasing the infrastructure expenditures to a level above otherwise normal budgeted levels. In an October 18, 2011 petition (subsequently amended December 16, 2011) with the NJBPU, ACE requested an extension and expansion to the IIP under which ACE proposes to spend approximately $63 million, $94 million and $81 million in calendar years 2012, 2013 and 2014, respectively, on non-revenue reliability-related capital expenditures. As proposed, capital expenditures related to the proposed special rate would be subject to annual reconciliation and approval by the NJBPU. A decision by the NJBPU on ACE’s IIP filing is expected by the end of the third quarter 2012.

Storm Damage Restoration Costs Recovery

In August 2011, ACE filed a petition with the NJBPU seeking authorization for deferred accounting treatment of uninsured incremental storm damage restoration costs not otherwise recovered through base rates. In that petition, ACE sought deferred accounting treatment for recovery of storm costs of approximately $8 million incurred during Hurricane Irene, which impacted ACE’s service territory in the third quarter of 2011.

(8) LEASING ACTIVITIES

Investment in Finance Leases Held in Trust

As of December 31, 2011 and 2010, Pepco Holdings had cross-border energy lease investments of $1.3 billion and $1.4 billion, respectively, consisting of hydroelectric generation and coal-fired electric generation facilities and natural gas distribution networks located outside of the United States.

During 2011, PHI modified its tax cash flow assumptions under its cross-border energy lease investments for the periods 2011-2016, to reflect the anticipated timing of potential litigation with the IRS and to reflect the change in tax laws in the District of Columbia as further discussed in Note (17), “Commitments and Contingencies – District of Columbia Tax Legislation.” Accordingly, PHI recalculated the equity investment and recorded a $7 million pre-tax ($3 million after-tax) charge.

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During 2010 and 2009, PHI reassessed the sustainability of its tax position and revised its assumptions regarding the estimated timing of tax benefits generated from its cross-border energy lease investments. Based on these reassessments, PHI recorded a reduction in its cross-border energy lease investment revenue of $2 million and $3 million in 2010 and 2009, respectively. For additional discussion, see Note (17), “Commitments and Contingencies—PHI’s Cross-Border Energy Lease Investments.”

During 2011, PHI entered into early termination agreements with two lessees involving all of the leases comprising one of the eight lease investments and a small portion of the leases comprising a second lease investment. The early terminations of the leases were negotiated at the request of the lessees. PHI received net cash proceeds of $161 million (net of a termination payment of $423 million used to retire the non-recourse debt associated with the terminated leases) and recorded a pre-tax gain of $39 million, representing the excess of the net cash proceeds over the carrying value of the lease investments.

With respect to the terminated leases, PHI had previously made certain business assumptions regarding foreign investment opportunities available at the end of the full lease terms. Because the leases were terminated prior to the end of the stated term, management decided not to pursue these opportunities and $22 million in certain Federal income tax benefits recognized previously were reversed. The after-tax gain on the lease terminations was $3 million, reflecting an income tax provision at the statutory federal rate of $14 million and the income tax benefit reversal. PHI has no intent to terminate early any other leases in the lease portfolio. With respect to certain of these remaining leases, management’s assumption continues to be that the foreign earnings recognized at the end of the lease term will remain invested abroad.

The components of the cross-border energy lease investments, as of December 31, are summarized below:

	2011			2010
	(millions of dollars)
Scheduled lease payments to PHI, net of non-recourse debt	$	2,120		$	2,265
Less: Unearned and deferred income		(771	)		(842	)
Investment in finance leases held in trust		1,349			1,423
Less: Deferred income tax liabilities		(793	)		(816	)
Net investment in finance leases held in trust	$	556		$	607

Income recognized from cross-border energy lease investments, excluding the gain on the terminated leases discussed above, is comprised of the following for the years ended December 31:

	2011			2010			2009
	(millions of dollars)
Pre-tax income from PHI’s cross-border energy lease investments (included in Other Revenue)	$	55		$	55		$	54
Non-cash charge to reduce equity value of PHI’s cross-border energy lease investments		(7	)		(2	)		(3	)
Pre-tax income from PHI’s cross-border energy lease investments after adjustment		48			53			51
Income tax expense		10			14			16
Net income from PHI’s cross-border energy lease investments	$	38		$	39		$	35

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Scheduled lease payments from the cross-border energy lease investments are net of non-recourse debt. Minimum lease payments receivable from the cross-border energy lease investments are zero for each year 2012 through 2016, and $1,349 million thereafter.

To ensure credit quality, PHI regularly monitors the financial performance and condition of the lessees under its cross-border energy lease investments. Changes in credit quality are also assessed to determine if they should be reflected in the carrying value of the leases. PHI reviews each lessee’s performance versus annual compliance requirements set by the terms and conditions of the leases. This includes a comparison of published credit ratings to minimum credit rating requirements in the leases for lessees with public credit ratings. In addition, PHI routinely meets with senior executives of the lessees to discuss their company and asset performance. If the annual compliance requirements or minimum credit ratings are not met, remedies are available under the leases. At December 31, 2011, all lessees were in compliance with the terms and conditions of their lease agreements.

The table below shows PHI’s net investment in these leases by the published credit ratings of the lessees as of December 31:

Lessee Rating (a)	2011		2010
	(millions of dollars)
Rated Entities
AA/Aa and above	$	737	$	709
A		612		549
Total		1,349		1,258
Non Rated Entities		—		165
Total	$	1,349	$	1,423

(a) Excludes the credit ratings of collateral posted by the lessees in these transactions.

Lease Commitments

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. This lease is treated as an operating lease for rate-making purposes.

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Capital lease assets recorded within Property, Plant and Equipment at December 31, 2011 and 2010, in millions of dollars, are comprised of the following:

	Original Cost		Accumulated Amortization		Net Book Value
At December 31, 2011
Transmission	$	76	$	33	$	43
Distribution		76		33		43
General		3		3		—
Total	$	155	$	69	$	86
At December 31, 2010
Transmission	$	76	$	29	$	47
Distribution		76		29		47
General		3		3		—
Total	$	155	$	61	$	94

The approximate annual commitments under all capital leases are $15 million for each year 2012 through 2016, and $46 million thereafter.

Rental expense for operating leases was $46 million, $45 million, and $45 million for the years ended December 31, 2011, 2010, and 2009, respectively.

Total future minimum operating lease payments for Pepco Holdings as of December 31, 2011, are $39 million in 2012, $36 million in 2013, $35 million in 2014, $32 million in 2015, $29 million in 2016 and $359 million thereafter.

(9) 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, 2011
Generation	$	108	$	82	$	26
Distribution		7,832		2,848		4,984
Transmission		2,462		834		1,628
Gas		429		133		296
Construction work in progress		742		—		742
Non-operating and other property		1,282		738		544
Total	$	12,855	$	4,635	$	8,220
At December 31, 2010
Generation	$	105	$	72	$	33
Distribution		7,567		2,749		4,818
Transmission		2,307		793		1,514
Gas		413		125		288
Construction work in progress		553		—		553
Non-operating and other property		1,175		708		467
Total	$	12,120	$	4,447	$	7,673

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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, 2011 and 2010, PHI’s subsidiaries had a net book value ownership interest of $13 million and $14 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. PHI is responsible for providing its share of the financing for the above jointly-owned facilities.

Deactivation of Pepco Energy Services’ Generating Facilities

Pepco Energy Services owns and operates two oil-fired generating facilities. The facilities are located in Washington, D.C. and have a generating capacity of approximately 790 megawatts. Pepco Energy Services sells the output of these facilities into the wholesale market administered by PJM. In February 2007, Pepco Energy Services provided notice to PJM of its intention to deactivate these facilities by the end of May 2012. PJM has informed Pepco Energy Services that these facilities will not be needed for reliability after May 2012; therefore, decommissioning plans are currently underway and on-schedule. During the years ended December 31, 2011 and 2010, PHI has recorded decommissioning costs of $2 million and $4 million, respectively, related to these generating facilities.

(10) PENSION AND OTHER POSTRETIREMENT BENEFITS

Pension Benefits and Other Postretirement Benefits

Pepco Holdings sponsors the PHI Retirement Plan, which covers substantially all employees of Pepco, DPL, ACE and certain employees of other Pepco Holdings’ subsidiaries. Pepco Holdings also provides supplemental retirement benefits to certain eligible executive and key employees through nonqualified retirement plans.

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

Net periodic benefit cost is included in other operation and maintenance expense, net of the portion of the net periodic benefit cost that is 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.

Pepco Holdings accounts for the PHI Retirement Plan, nonqualified retirement plans, and its postretirement health care and life insurance benefits for eligible employees in accordance with FASB guidance on retirement benefits. PHI’s financial statement disclosures are also prepared in accordance with FASB guidance on retirement benefits.

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	Pension Benefits						Other Postretirement Benefits
At December 31,	2011			2010			2011			2010
	(millions of dollars)
Change in Benefit Obligation
Projected benefit obligation at beginning of year	$	1,970		$	1,796		$	704		$	651
Service cost		35			35			5			5
Interest cost		107			110			37			39
Amendments		18			(7	)		7			—
Actuarial loss		176			179			36			42
Benefits paid (a)		(182	)		(146	)		(40	)		(39	)
Termination benefits		—			3			1			6
Projected benefit obligation at end of year	$	2,124		$	1,970		$	750		$	704
Change in Plan Assets
Fair value of plan assets at beginning of year	$	1,632		$	1,500		$	275		$	242
Actual return on plan assets		127			173			—			26
Company contributions		117			105			46			46
Benefits paid (a)		(182	)		(146	)		(40	)		(39	)
Fair value of plan assets at end of year	$	1,694		$	1,632		$	281		$	275
Funded Status at end of year (plan assets less plan obligations)	$	(430	)	$	(338	)	$	(469	)	$	(429	)

(a) Other Postretirement Benefits paid is net of Medicare Part D subsidy receipts of $2 million in 2011 and $3 million in 2010.

At December 31, 2011, PHI Retirement Plan assets were $1.7 billion and the accumulated benefit obligation was approximately $2.0 billion. At December 31, 2010, PHI’s Retirement Plan assets were approximately $1.6 billion and the accumulated benefit obligation was approximately $1.9 billion.

The following table provides the amounts recognized in PHI’s consolidated balance sheets as of December 31, 2011 and 2010:

	Pension Benefits						Other Postretirement Benefits
	2011			2010			2011			2010
	(millions of dollars)
Regulatory asset	$	794		$	655		$	243		$	193
Current liabilities		(6	)		(6	)		—			—
Pension benefit obligation		(424	)		(332	)		—			—
Other postretirement benefit obligations		—			—			(469	)		(429	)
Deferred income taxes, net		15			12			—			—
Accumulated other comprehensive loss, net of tax		24			17			—			—
Net amount recognized	$	403		$	346		$	(226	)	$	(236	)

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Amounts included in AOCL (pre-tax) and regulatory assets at December 31, 2011 and 2010 consist of:

	Pension Benefits					Other Postretirement Benefits
	2011		2010			2011			2010
	(millions of dollars)
Unrecognized net actuarial loss	$	822	$	692		$	247		$	208
Unamortized prior service cost (credit)		11		(8	)		(5	)		(17	)
Unamortized transition liability		—		—			1			2
Total	$	833	$	684		$	243		$	193
Accumulated other comprehensive loss ($24 million and $17 million, net of tax, at December 31, 2011 and 2010, respectively)	$	39	$	29		$	—		$	—
Regulatory assets		794		655			243			193
Total	$	833	$	684		$	243		$	193

The estimated net actuarial loss and prior service cost for the defined benefit pension plans that will be amortized from AOCL into net periodic benefit cost over the next reporting year are $55 million and $1 million, respectively. The estimated net loss and prior service credit for the OPEB plan that will be amortized from AOCL into net periodic benefit cost over the next reporting year are $18 million and $5 million, respectively.

The table below provides the components of net periodic benefit costs recognized for the years ended December 31, 2011, 2010 and 2009:

	Pension Benefits									Other Postretirement Benefits
	2011			2010			2009			2011			2010			2009
	(millions of dollars)
Service cost	$	35		$	35		$	36		$	5		$	5		$	7
Interest cost		107			110			111			37			39			40
Expected return on plan assets		(128	)		(117	)		(101	)		(19	)		(16	)		(13	)
Amortization of prior service cost		—			—			—			(5	)		(5	)		(4	)
Amortization of net actuarial loss		47			42			56			14			13			16
Recognition of benefit contract		—			—			1			—			—			—
Plan amendments		—			1			—			—			—			—
Termination benefits		—			3			—			1			6			—
Net periodic benefit cost	$	61		$	74		$	103		$	33		$	42		$	46

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, 2011, 2010 and 2009:

	2011		2010		2009
	(millions of dollars)
Pepco	$	43	$	40	$	38
DPL		23		28		25
ACE		21		23		20
Other subsidiaries		7		25		66
Total	$	94	$	116	$	149

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The following weighted average assumptions were used to determine the benefit obligations at December 31:

	Pension Benefits						Other Postretirement Benefits
	2011			2010			2011			2010
Discount rate		5.00	%		5.65	%		4.90	%		5.60	%
Rate of compensation increase		5.00	%		5.00	%		5.00	%		5.00	%
Health care cost trend rate assumed for current year		—			—			8.00	%		7.50	%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)		—			—			5.00	%		5.00	%
Year that the cost trend rate reaches the ultimate trend rate		—			—			2017			2015

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	$	2	$	(1	)
Increase (decrease) in postretirement benefit obligation	$	32	$	(28	)

The following weighted average assumptions were used to determine the net periodic benefit cost for the years ended December 31:

	Pension Benefits									Other Postretirement Benefits
	2011			2010			2009			2011			2010			2009
Discount rate		5.65	%		6.40	%		6.50	%		5.60	%		6.30	%		6.50	%
Expected long-term return on plan assets		7.75	%		8.00	%		8.25	%		7.75	%		8.00	%		8.25	%
Rate of compensation increase		5.00	%		5.00	%		5.00	%		5.00	%		5.00	%		5.00	%

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 plan assets was 7.75% and 8.00% as of December 31, 2011 and 2010, respectively. 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 plan assets consist of equity, fixed income, real estate and private equity investments, and when viewed over a long-term horizon, are expected to yield a return on assets of 7.75% at December 31, 2011. PHI periodically reviews its asset mix and rebalances assets back to the target allocation.

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In addition, for the 2011 Other Postretirement Benefit Plan valuation, the health care cost trend rate was changed to 8.0% from 2011 to 2012, declining 0.5% per year to a rate of 5.0% for 2017 to 2018 and beyond. The 2010 valuation assumption was 7.0% from 2011 to 2012, declining 0.5% per year to a rate of 5.0% for 2015 to 2016 and beyond. No changes were made for the 2010 and 2009 valuations.

Benefit Plan Modifications

In the third quarter of 2011, PHI’s Board of Directors approved revisions to certain of PHI’s existing benefit programs, including the PHI Retirement Plan. The changes to the PHI Retirement Plan were effected by PHI in order to establish a more unified approach to PHI’s retirement programs and to further align the benefits offered under PHI’s retirement programs. The changes to the PHI Retirement Plan were effective on or after July 1, 2011 and affect the retirement benefits payable to approximately 750 of PHI’s employees. All full time employees of PHI and certain subsidiaries are eligible to participate in the PHI Retirement Plan. Retirement benefits for all other employees remain unchanged.

In the third quarter of 2011, PHI’s Board also approved a new, non-qualified Supplemental Executive Retirement Plan (SERP) which replaced PHI’s two pre-existing supplemental retirement plans, effective August 1, 2011. As of the effective date of the new SERP, the Conectiv SERP and the PHI Combined SERP were closed to new participants. The establishment of the new SERP is consistent with PHI’s efforts to align retirement benefits for PHI and its subsidiaries with current market practices and to provide similarly situated participants with retirement benefits that are the same or similar in value as compared to the benefits provided under the prior SERPs.

In the fourth quarter of 2011, PHI approved an increase in the medical benefit limits for certain employees in its postretirement health care benefit plan to align the limits with those provided to other employees. The amendment affects approximately 1,400 employees, of which 400 are retirees and 1,000 are active union employees. The effective date of the plan modification is January 1, 2012.

The additional liabilities and expenses for the benefit plan modifications described above did not have a material impact on PHI’s overall consolidated financial condition, results of operations, or cash flows.

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.

• 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.

In the first quarter of 2011, PHI modified its pension investment policy and strategy to reduce the effects of future volatility of the fair value of its pension assets relative to its pension liabilities. The new asset-liability management strategy was implemented during the second quarter of 2011. Under the new asset-liability management strategy, the plan’s allocation to fixed income investments, primarily high quality, longer-maturity fixed income securities was increased, with a reduction in the allocation to equity investments. As a result of this modification, during the second quarter of 2011, PHI allocated approximately 54% of its pension plan assets to longer-maturity fixed income investments, 38% to public equity investments and 8% to alternative investments (real estate, private equity). At December 31, 2010, the PHI pension trust’s asset allocation included 40% in fixed income investments (intermediate maturity fixed income), 53% in public equity investments and 7% in alternative investments (real estate, private equity). PHI anticipates further increases in the allocation to fixed income investments, with a corresponding reduction in the allocation to equity and alternative investments as the funded status of its plan increases.

The change in overall investment strategy may result in a lower expected long-term rate of return assumption because of the shift in allocation from equities and alternative investments to fixed income. PHI’s 2011 pension costs are based on a 7.75% expected long-term rate of return assumption.

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The PHI Retirement Plan asset allocations at December 31, 2011 and 2010, by asset category, were as follows:

	Plan Assets at December 31,						Target Plan Asset Allocation
	2011			2010			2011			2010
Asset Category
Equity		36	%		53	%		38	%		60	%
Fixed Income		56	%		40	%		54	%		30	%
Other (real estate, private equity)		8	%		7	%		8	%		10	%
Total		100	%		100	%		100	%		100	%

PHI’s other postretirement benefit plan asset allocations at December 31, 2011 and 2010, by asset category, were as follows:

	Plan Assets at December 31,						Target Plan Asset Allocation
	2011			2010			2011			2010
Asset Category
Equity		62	%		61	%		60	%		60	%
Fixed Income		36	%		35	%		35	%		35	%
Cash		2	%		4	%		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

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Fair Value of Plan Assets

As defined in the FASB guidance on fair value measurement and disclosures (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, 2011 and 2010.

The following tables present the fair values of PHI’s pension and other postretirement benefit plan assets by asset category within the fair value hierarchy levels, as of December 31, 2011 and 2010:

	Fair Value Measurements at December 31, 2011
	(millions of dollars)
	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Asset Category
Pension Plan Assets:
Equity
Domestic (a)	$	411	$	165	$	221	$	25
International (b)		196		192		2		2
Fixed Income (c)		939		—		930		9
Other
Private Equity		64		—		—		64
Real Estate		65		—		—		65
Cash Equivalents (d)		19		19		—		—
Pension Plan Assets Subtotal		1,694		376		1,153		165
Other Postretirement Plan Assets:
Equity (e)		174		150		24		—
Fixed Income (f)		101		101		—		—
Cash Equivalents		6		6		—		—
Postretirement Plan Assets Subtotal		281		257		24		—
Total Pension and Other Postretirement Plan Assets	$	1,975	$	633	$	1,177	$	165

(a) Predominantly includes domestic common stock and commingled funds.

(b) Predominantly includes foreign common and preferred stock and warrants.

(c) Predominantly includes corporate bonds, government bonds, municipal bonds, and commingled funds.

(d) Predominantly includes cash investment in short term investment funds.

(e) Includes domestic and international commingled funds.

(f) Includes fixed income commingled funds.

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	Fair Value Measurements at December 31, 2010
	(millions of dollars)
	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Asset Category
Pension Plan Assets:
Equity
Domestic (a)	$	573	$	334	$	212	$	27
International (b)		270		265		2		3
Fixed Income (c)		604		397		204		3
Other
Private Equity		62		—		—		62
Real Estate		55		—		—		55
Cash Equivalents (d)		68		68		—		—
Pension Plan Assets Subtotal		1,632		1,064		418		150
Other Postretirement Plan Assets:
Equity (e)		168		145		23		—
Fixed Income (f)		96		96		—		—
Cash Equivalents		11		11		—		—
Postretirement Plan Assets Subtotal		275		252		23		—
Total Pension and Other Postretirement Plan Assets	$	1,907	$	1,316	$	441	$	150

(a) Predominantly includes domestic common stock and commingled funds.

(b) Predominantly includes foreign common and preferred stock and warrants.

(c) Predominantly includes corporate bonds, government bonds, municipal/provincial bonds, collateralized mortgage obligations, asset backed securities and commingled funds.

(d) Predominantly includes cash investment in short term investment funds.

(e) Includes domestic and international commingled funds.

(f) Includes fixed income commingled funds.

There were no significant concentrations of risk in pension and OPEB plan assets at December 31, 2011 and 2010.

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.

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, the fair value of the investment is the net asset value (NAV) per fund share, derived from the underlying securities’ quoted prices in active markets, and are classified as level 2 investments. Investments in commingled funds with redemption restrictions and use NAV are classified as level 3 investments.

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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.

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, the fair value of the investment is the NAV per fund share, derived from the underlying securities’ quoted prices in active markets, and are classified as level 2 investments. Investments in commingled funds with redemption restrictions and use NAV are classified as level 3 investments.

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. As a result, PHI classifies these investments as level 3 investments.

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, 2011 and 2010 totaled $28 million and $42 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, 2011 and 2010 are shown below:

	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
	(millions of dollars)
	Equity			Fixed Income			Private Equity			Real Estate			Total Level 3
Beginning balance as of January 1, 2011	$	30		$	3		$	62		$	55		$	150
Transfer in (out) of Level 3		—			—			—			—			—
Purchases		2			—			11			9			22
Sales		(5	)		(1	)		—			—			(6	)
Settlements		—			7			(11	)		(6	)		(10	)
Unrealized (loss)/gain		(1	)		—			(4	)		9			4
Realized gain/(loss)		1			—			6			(2	)		5
Ending balance as of December 31, 2011	$	27		$	9		$	64		$	65		$	165

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	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
	(millions of dollars)
	Equity			Fixed Income			Private Equity			Real Estate			Total Level 3
Beginning balance as of January 1, 2010	$	—		$	12		$	55		$	40		$	107
Transfer in (out) of Level 3		23			—			—			—			23
Purchases		4			3			8			16			31
Sales		(2	)		(3	)		—			—			(5	)
Settlements		1			(7	)		(3	)		(1	)		(10	)
Unrealized gain/(loss)		4			(3	)		(2	)		—			(1	)
Realized gain		—			1			4			—			5
Ending balance as of December 31, 2010	$	30		$	3		$	62		$	55		$	150

Cash Flows

Contributions—PHI Retirement Plan

PHI satisfied the minimum required contribution rules under the Pension Protection Act during 2011 and 2010. Pepco, DPL and ACE made discretionary tax-deductible contributions to the PHI Retirement Plan in the amounts of $40 million, $40 million and $30 million, respectively. In 2010, PHI Service Company made discretionary tax-deductible contributions totaling $100 million to the PHI Retirement Plan.

On January 31, 2012, Pepco, DPL and ACE made discretionary tax-deductible contributions to the PHI Retirement Plan in the amounts of $85 million, $85 million and $30 million, respectively, which is expected to bring the PHI Retirement Plan assets to at least the funding target level for 2012 under the Pension Protection Act.

Contributions—Other Postretirement Benefit Plan

In 2011 and 2010, Pepco contributed $7 million and $10 million, respectively, DPL contributed $6 million and $9 million, respectively, and ACE contributed $7 million and $8 million, respectively, to the other postretirement benefit plan. In 2011 and 2010, contributions of $13 million and $8 million, respectively, were made by other PHI 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		Expected Medicare Part D Subsidies
	(millions of dollars)
2012	$	126	$	47	$	2
2013		125		49		2
2014		129		50		3
2015		133		52		3
2016		137		52		3
2017 through 2021	$	732	$	261	$	15

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Medicare Prescription Drug Improvement and Modernization Act of 2003

On December 8, 2003, the Medicare Act became effective. The Medicare Act introduced Medicare Part D, as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. Pepco Holdings sponsors postretirement health care plans that provide prescription drug benefits that PHI plan actuaries have determined are actuarially equivalent to Medicare Part D. In 2011 and 2010, Pepco Holdings received $2 million and $3 million, respectively, in federal Medicare prescription drug subsidies.

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 $11 million, $11 million, and $12 million for the years ended December 31, 2011, 2010 and 2009, respectively.

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(11) DEBT

Long-Term Debt

The components of long-term debt are shown below.

	At December 31,
Interest Rate	Maturity	2011		2010
		(millions of dollars)
First Mortgage Bonds
Pepco:
4.95% (a)(b)	2013	$	200	$	200
4.65% (a)(b)	2014		175		175
6.20% (a)(b)(c)	2022		110		110
5.375% (a)	2024		38		38
5.75% (a)(b)	2034		100		100
5.40% (a)(b)	2035		175		175
6.50% (a)(b)(c)	2037		500		500
7.90%	2038		250		250
ACE:
7.63%	2014		7		7
6.63%	2013		69		69
7.68%	2015 -2016		17		17
7.75%	2018		250		250
6.80% (a)	2021		39		39
4.35%	2021		200		—
5.60% (a)	2025		4		4
4.875% (a)(b)(c)	2029		23		23
5.80% (a)(b)	2034		120		120
5.80% (a)(b)	2036		105		105
DPL:
6.40%	2013		250		250
5.22% (a)	2016		100		100
5.20% (a)	2019		31		31
0.75%-4.90% (a)(e)	2026		35		35
Total First Mortgage Bonds			2,798		2,598
Unsecured Tax-Exempt Bonds
DPL:
1.80% (d)	2025		15		15
2.30% (f)	2028		16		16
5.40%	2031		78		78
Total Unsecured Tax-Exempt Bonds		$	109	$	109

(a) Represents a series of first mortgage bonds issued by the indicated company (Collateral First Mortgage Bonds) as collateral for an outstanding series of senior notes issued by the company or tax-exempt bonds issued for the benefit of the company. The maturity date, optional and mandatory prepayment provisions, if any, interest rate, and interest payment dates on each series of senior notes or the company’s obligations in respect of the tax-exempt bonds are identical to the terms of the corresponding series of Collateral First Mortgage Bonds. Payments of principal and interest on a series of senior notes or the company’s obligations in respect of the tax-exempt bonds satisfy the corresponding payment obligations on the related series of Collateral First Mortgage Bonds. Because each series of senior notes or the company’s obligations in respect of the tax-exempt bonds and the corresponding series of Collateral First Mortgage Bonds securing that series of senior notes or tax-exempt bonds obligations effectively represents a single financial obligation, the senior notes and the tax-exempt bonds are not separately shown on the table.

(b) Represents a series of Collateral First Mortgage Bonds issued by the indicated company that in accordance with its terms will, at such time as there are no first mortgage bonds of the issuing company outstanding (other than Collateral First Mortgage Bonds securing payment of senior notes), cease to secure the corresponding series of senior notes and will be cancelled.

(c) Represents a series of Collateral First Mortgage Bonds as to which the indicated company has agreed in connection with the issuance of the corresponding series of senior notes that, notwithstanding the terms of the Collateral First Mortgage Bonds described in footnote (b) above, it will not permit the release of the Collateral First Mortgage Bonds as security for the series of senior notes for so long as the senior notes remain outstanding, unless the company delivers to the senior note trustee comparable secured obligations to secure the senior notes.

(d) On July 1, 2010, DPL purchased this series of tax-exempt bonds issued for the benefit of DPL by the Delaware Economic Development Authority (DEDA) pursuant to a mandatory repurchase provision in the indenture for the bonds that was triggered by the expiration of the original interest period for the bonds. While DPL held the bonds, they remained outstanding as a contractual matter, but were considered extinguished for accounting purposes. On December 1, 2010, DPL resold the bonds to the public, at which time the interest rate on the bonds was changed from 5.50% to a fixed rate of 1.80%. The bonds are subject to mandatory purchase by DPL on June 1, 2012.

(e) These bonds bearing an interest rate of 4.90% were repurchased. On June 1, 2011, DPL resold these bonds that were subject to mandatory repurchase on May 1, 2011 at an interest rate of 0.75%. The bonds are currently subject to mandatory tender on June 1, 2012.

(f) On July 1, 2010, DPL purchased this series of tax-exempt bonds issued for the benefit of DPL by DEDA pursuant to a mandatory repurchase provision in the indenture for the bonds that was triggered by the expiration of the original interest period for the bonds. While DPL held the bonds, they remained outstanding as a contractual matter, but were considered extinguished for accounting purposes. On December 1, 2010, DPL resold the bonds to the public, at which time the interest rate on the bonds was changed from 5.65% to a fixed rate of 2.30%. The bonds are subject to mandatory purchase by DPL on June 1, 2012.

NOTE: Schedule is continued on next page.

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			At December 31,
Interest Rate	Maturity		2011			2010
			(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
Recourse Debt
PCI:
6.59% - 6.69%		2014		11			11
Notes (secured)
Pepco Energy Services:
7.35% - 7.47%		2017		15			11
Notes (unsecured)
PHI:
2.70%		2015		250			250
5.90%		2016		190			190
6.125%		2017		81			81
7.45%		2032		185			185
DPL:
5.00%		2014		100			100
5.00%		2015		100			100
Total Notes (unsecured)				906			906
Total Long-Term Debt				3,879			3,675
Other long-term debt				—			2
Net unamortized discount				(12	)		(12	)
Current portion of long-term debt				(73	)		(36	)
Total Net Long-Term Debt			$	3,794		$	3,629
Transition Bonds Issued by ACE Funding
4.21%		2013	$	—		$	9
4.46%		2016		29			39
4.91%		2017		102			118
5.05%		2020		54			54
5.55%		2023		147			147
Total				332			367
Net unamortized discount				—			—
Current portion of long-term debt				(37	)		(35	)
Total Net Long-Term Transition Bonds issued by ACE Funding			$	295		$	332

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PEPCO HOLDINGS

The outstanding First Mortgage Bonds issued by each of Pepco, DPL and ACE are subject to a lien on substantially all of the issuing company’s property, plant and equipment.

For a description of the Transition Bonds issued by ACE Funding, see Note (2), “Significant Accounting Policies—Consolidation of Variable Interest Entities—ACE Transition Funding, LLC.” The aggregate amounts of maturities for long-term debt and Transition Bonds outstanding at December 31, 2011, are $110 million in 2012, $558 million in 2013, $334 million in 2014, $409 million in 2015, $338 million in 2016, and $2,462 million thereafter.

PHI’s long-term debt is subject to certain covenants. As of December 31, 2011, PHI and its subsidiaries were in compliance with all such covenants.

Long-Term Project Funding

As of December 31, 2011 and 2010, Pepco Energy Services had outstanding total long-term project funding (including current maturities) of $15 million and $19 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, 2011, are $2 million for each year 2012 through 2014, $1 million for 2015 and 2016, and $7 million thereafter.

Tax-Exempt Bonds

On June 1, 2011, DPL resold $35 million of Pollution Control Refunding Revenue Bonds (Delmarva Power & Light Company Project) Series 2001C due 2026 (the “Series 2001C Bonds”). The Series 2001C Bonds were issued for the benefit of DPL in 2001 and were repurchased by DPL on May 2, 2011, pursuant to a mandatory repurchase provision in the indenture for the Series 2001C Bonds triggered by the expiration of the original interest rate period specified by the Series 2001C Bonds.

First Mortgage Bonds

On April 5, 2011, ACE issued $200 million of 4.35% first mortgage bonds due April 1, 2021. The net proceeds were used to repay short-term debt and for general corporate purposes.

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. A detail of the components of PHI’s short-term debt at December 31, 2011 and 2010 is as follows:

	2011		2010
	(millions of dollars)
Commercial paper	$	586	$	388
Variable rate demand bonds		146		146
Total	$	732	$	534

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Commercial Paper

PHI maintains an ongoing commercial paper program which had a maximum capacity of $875 million through December 31, 2011. In January 2012, the Board of Directors approved an increase in the maximum to $1.25 billion. Pepco, DPL, and ACE have ongoing commercial paper programs of up to $500 million, $500 million and $250 million, respectively. The commercial paper programs of each of PHI, Pepco, DPL and ACE are backed by each company’s borrowing capacity under PHI’s $1.5 billion credit facility, which is described below under the heading Credit Facility.

PHI, Pepco and DPL had $465 million, $74 million and $47 million, respectively, of commercial paper outstanding at December 31, 2011. ACE had no commercial paper outstanding at December 31, 2011. The weighted average interest rate for commercial paper issued by PHI, Pepco, DPL and ACE during 2011 was 0.64%, 0.35%, 0.34% and 0.33%, respectively. The weighted average maturity of all commercial paper issued by PHI, Pepco, DPL and ACE in 2011 was eleven, two, two and six days, respectively.

Variable Rate Demand Bonds

PHI’s utility subsidiaries DPL and ACE, as well as Pepco Energy Services, each have 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 credit worthiness 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, 2011, $105 million of VRDBs issued by DPL (of which $72 million was secured by Collateral First Mortgage Bonds issued by DPL), $23 million of VRDBs issued by ACE, and $18 million of VRDBs issued by Pepco Energy Services were outstanding.

The VRDBs outstanding at December 31, 2011 mature as follows: 2014 to 2017 ($49 million), 2024 ($33 million) and 2028 to 2031 ($64 million). The weighted average interest rate for VRDBs was 0.44% during 2011 and 0.45% during 2010.

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, 2011, PHI, Pepco, DPL and ACE entered into an amended and restated credit agreement with respect to the facility, which among other changes, extended the expiration date of the facility to August 1, 2016.

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 initial credit sublimit for PHI is $750 million 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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PEPCO HOLDINGS

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 one month 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 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 financial covenants under this facility as of December 31, 2011.

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.

At December 31, 2011 and 2010, the amount of cash plus unused borrowing capacity under the primary credit facility available to meet the future liquidity needs of PHI and its utility subsidiaries on a consolidated basis totaled $1 billion and $1.2 billion, respectively. PHI’s utility subsidiaries had combined cash and unused borrowing capacity under the $1.5 billion credit facility of $711 million and $462 million at December 31, 2011 and 2010, respectively.

Loss on Extinguishment of Debt

During the year ended December 31, 2010, PHI recorded a pre-tax loss on extinguishment of debt of $189 million ($113 million after-tax), which is further discussed below.

In July 2010, PHI purchased, pursuant to a cash tender offer, $640 million in principal amount of its 6.45% Senior Notes due 2012 (6.45% Notes), redeemed the remaining $110 million of outstanding 6.45% Notes, and purchased, pursuant to a cash tender offer, $129 million of its 6.125% Senior Notes due 2017 (6.125% Notes) and $65 million of 7.45% Senior Notes due 2032 (7.45% Notes). In connection with these transactions, PHI recorded a pre-tax loss on extinguishment of debt of $120 million in the third quarter of 2010.

In October 2010, PHI purchased, pursuant to a cash tender offer, an additional $40 million of outstanding 6.125% Notes. In November 2010, PHI redeemed all of its $200 million 6% Notes due 2019 and $10 million of its 5.9% Notes due 2016. PHI recorded a pre-tax loss on extinguishment of debt of approximately $54 million in the fourth quarter of 2010 in connection with this transaction.

In connection with the purchases of the 6.45% Notes and the 7.45% Notes, PHI accelerated the recognition of $15 million of pre-tax hedging losses attributable to the issuance of the 6.45% Notes and 7.45% Notes by reclassifying these hedging losses from AOCL to income. These hedging losses originally arose when PHI entered into several treasury rate lock transactions in June 2002 to hedge changes in interest rates related to the anticipated issuance in August 2002 of several series of senior notes, including the 6.45% Notes and the 7.45% Notes. Upon issuance of the fixed rate debt in August 2002, the rate locks were terminated at a loss that has been deferred in AOCL and is being recognized in income over the life of the debt issued as interest payments on the debt are made. The accelerated recognition of these losses has also been included as a component of pre-tax loss on extinguishment of debt.

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PEPCO HOLDINGS

Collateral Requirements of Pepco Energy Services

In the ordinary course of its energy supply business which is in the process of winding down, Pepco Energy Services enters into various contracts to buy and sell electricity, fuels and related products, including derivative instruments, designed to reduce its financial exposure to changes in the value of its assets and obligations due to energy price fluctuations. These contracts typically have collateral requirements. Depending on the contract terms, the collateral required to be posted by Pepco Energy Services can be of varying forms, including cash and letters of credit.

In conducting its retail energy supply business, Pepco Energy Services, during periods of declining energy prices, has been exposed to the asymmetrical risk of having to post collateral under its wholesale purchase contracts without receiving a corresponding amount of collateral from its retail customers. To partially address these asymmetrical collateral obligations, Pepco Energy Services, in the first quarter of 2009, entered into a credit intermediation arrangement with Morgan Stanley Capital Group, Inc. (MSCG). Under this arrangement, MSCG, in consideration for the payment to MSCG of certain fees, (i) assumed, by novation, the electricity purchase obligations of Pepco Energy Services in years 2009 through 2011 under several wholesale purchase contracts, and (ii) supplied electricity to Pepco Energy Services on the same terms as the novated transactions, but without imposing on Pepco Energy Services any obligation to post collateral based on changes in electricity prices. The upfront fees incurred by Pepco Energy Services in 2009 in the amount of $25 million was amortized into expense in declining amounts over the life of the arrangement based on the fair value of the underlying contracts at the time of the novation. For the years ended December 31, 2011, 2010 and 2009, approximately $1 million, $8 million and $16 million, respectively, of the fees have been amortized and reflected in Interest expense.

As of December 31, 2011, Pepco Energy Services had posted net cash collateral of $112 million and letters of credit of $1 million. At December 31, 2010, Pepco Energy Services had posted net cash collateral of $117 million and letters of credit of $113 million.

At December 31, 2011 and 2010, the amount of cash, plus borrowing capacity under the credit facilities available to meet the future liquidity needs of Pepco Energy Services totaled $283 million and $728 million, respectively.

(12) 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 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 tax liabilities (assets) are shown below.

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PEPCO HOLDINGS

Provision for Consolidated Income Taxes – Continuing Operations

	For the Year Ended December 31,
	2011			2010			2009
	(millions of dollars)
Current Tax Expense (Benefit)
Federal	$	9		$	(270	)	$	(160	)
State and local		4			(50	)		(32	)
Total Current Tax Expense (Benefit)		13			(320	)		(192	)
Deferred Tax Expense (Benefit)
Federal		121			300			261
State and local		19			34			39
Investment tax credit amortization		(4	)		(3	)		(4	)
Total Deferred Tax Expense		136			331			296
Total Consolidated Income Tax Expense Related to Continuing Operations	$	149		$	11		$	104

Reconciliation of Consolidated Income Tax Expense – Continuing Operations

	For the Year Ended December 31,
	2011					2010					2009
	(millions of dollars)
Income tax at Federal statutory rate	$	143		35.0	%	$	52		35.0	%	$	114		35.0	%
Increases (decreases) resulting from
Depreciation		—		—			(3	)	(2.0	)%		6		1.8	%
State income taxes, net of Federal effect		22		5.4	%		—		—			19		5.7	%
State tax benefits related to prior years’ asset dispositions		(4	)	(1.0	)%		—		—			(13	)	(4.0	)%
Cross-border energy lease investments		16		3.9	%		(5	)	(3.3	)%		(6	)	(1.7	)%
Change in estimates and interest related to uncertain and effectively settled tax positions		(11	)	(2.7	)%		(6	)	(4.0	)%		(1	)	(0.4	)%
Investment tax credits		(4	)	(1.0	)%		(4	)	(2.7	)%		(4	)	(1.2	)%
Deferred tax basis adjustments		2		0.2	%		(3	)	(2.0	)%		(4	)	(1.2	)%
Reversal of valuation allowances		—		—			(8	)	(5.3	)%		—		—
Change in state deferred tax balances as a result of restructuring		—		—			(6	)	(4.0	)%		—		—
Other, net		(15	)	(3.4	)%		(6	)	(4.4	)%		(7	)	(2.2	)%
Consolidated Income Tax Expense Related to Continuing Operations	$	149		36.4	%	$	11		7.3	%	$	104		31.8	%

Year ended December 31, 2011

PHI’s effective income tax rate in 2011 was significantly affected by changes in estimates and interest related to uncertain and effectively settled tax positions. In 2011, PHI reached a settlement with the IRS with respect to interest due on its federal tax liabilities related to the November 2010 audit settlement (discussed below) for years 1996 through 2002. In connection with this agreement, PHI reallocated certain amounts that have been on deposit with the IRS since 2006 among liabilities in the settlement years and subsequent years. Primarily related to the settlement and reallocations, PHI recorded an additional tax benefit of $17 million (after-tax) which was recorded in the second quarter of 2011. Further, PHI recalculated interest on its uncertain tax positions for open tax years using different assumptions related to the application of its deposit made with the IRS in 2006, which resulted in additional tax expense of $3 million (after-tax).

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PEPCO HOLDINGS

As discussed further in Note (8), “Leasing Activities,” during the second quarter of 2011, PHI terminated early its interest in certain cross-border energy leases prior to the end of their stated terms. As a result of the early terminations, PHI reversed $22 million of previously recognized federal tax benefits associated with those leases which will not be realized.

In addition, as discussed further in Note (17), “Commitments and Contingencies – District of Columbia Tax Legislation,” on June 14, 2011, the Council of the District of Columbia approved the Fiscal Year 2012 Budget Support Act of 2011 (the Budget Support Act). The Budget Support Act includes a provision that requires corporate taxpayers in the District of Columbia to calculate taxable income allocable or apportioned to the District by reference to the income and apportionment factors applicable to commonly controlled entities organized within the United States that are engaged in a unitary business. Previously, only the income of companies with direct nexus to the District of Columbia was taxed. As a result of the change, during 2011 PHI recorded additional state income tax expense of $2 million.

Year ended December 31, 2010

In April 2010, as part of an ongoing effort to simplify PHI’s organizational structure, certain of PHI’s subsidiaries were converted from corporations to single member limited liability companies. In addition to increased organizational flexibility and reduced administrative costs, converting these entities to limited liability companies allows PHI to include income or losses in the former corporations in a single state income tax return, thus increasing the utilization of state income tax attributes. As a result of inclusions of income or losses in a single state return as discussed above, PHI recorded an $8 million benefit by reversing valuation allowances on certain state net operating losses and an additional benefit of $6 million resulting from changes to certain state deferred income tax benefits. In addition, conversion to limited liability companies caused PHI’s separate company losses (primarily related to the loss on the extinguishment of debt) to be subjected to state income taxes in new jurisdictions, resulting in minimal consolidated state taxable income in 2010.

In November 2010, PHI reached final settlement with the IRS with respect to its federal tax returns for the years 1996 to 2002 for all issues except its cross-border energy lease investments. In connection with the settlement, PHI reallocated certain amounts on deposit with the IRS since 2006 among liabilities in the settlement years and subsequent years. In light of the settlement and reallocations, PHI recalculated the estimated interest due for the tax years 1996 to 2002. The revised estimate resulted in the reversal of $15 million (after-tax) of estimated interest due to the IRS. This reversal was recorded as an income tax benefit in the fourth quarter of 2010 and PHI recorded an additional tax benefit of $17 million (after-tax) in the second quarter of 2011 when the IRS finalized its calculation of the amount due. Offsetting the 2010 benefit was the reversal of $6 million (after-tax) of erroneously accrued state interest receivable recorded in the first quarter of 2010 and $2 million (after-tax) of other adjustments.

Also in the fourth quarter of 2010, PHI corrected the tax accounting for software amortization. Accordingly, a regulatory asset was established and income tax expense was reduced by $4 million.

Year ended December 31, 2009

During 2009, PHI recorded a decrease to income tax expense of $13 million resulting from the receipt of a refund of $6 million (after-tax) of state income taxes and the establishment of a state tax benefit carryforward of $7 million (after-tax), related to a change in tax reporting for certain asset dispositions occurring in prior years.

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During 2009, the IRS issued a Revenue Agent’s Report for the audit of PHI’s consolidated federal income tax returns for the calendar years 2003 to 2005. The IRS has proposed adjustments to PHI’s tax returns, including adjustments to PHI’s deductions related to cross-border energy lease investments, the capitalization of overhead costs for tax purposes and the deductibility of certain casualty losses. PHI has appealed certain of the proposed adjustments and believes it has adequately reserved for the adjustments proposed in the Revenue Agents Report. See Note (17), “Commitments and Contingencies – PHI’s Cross-Border Energy Lease Investments,” for additional information.

During 2009, PHI received a refund of taxes paid in prior years of approximately $138 million, a substantial portion of which is associated with PHI’s utility subsidiaries. The refund resulted from the carryback of a 2008 net operating loss for tax reporting purposes that reflected, among other things, significant tax deductions related to accelerated depreciation, the pension plan contributions made in 2009 (which were deductible for 2008) and the cumulative effect of adopting a new method of tax reporting for certain repairs.

Components of Consolidated Deferred Tax Liabilities (Assets)

	At December 31,
	2011			2010
	(millions of dollars)
Deferred Tax Liabilities (Assets)
Depreciation and other basis differences related to plant and equipment	$	1,871		$	1,680
Deferred electric service and electric restructuring liabilities		131			154
Cross-border energy lease investments		793			816
Federal and state net operating losses		(220	)		(46	)
Valuation allowances on state net operating losses		21			21
Pension and other postretirement benefits		130			70
Deferred taxes on amounts to be collected through future rates		47			43
Other		32			(113	)
Total Deferred Tax Liabilities, net		2,805			2,625
Deferred tax assets included in Current Assets		59			90
Deferred tax liabilities included in Other Current Liabilities		(1	)		(1	)
Total Consolidated Deferred Tax Liabilities, net non-current	$	2,863		$	2,714

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.

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 continues to be amortized to income over the useful lives of the related property.

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Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits

	2011			2010			2009
	(millions of dollars)
Beginning balance as of January 1,	$	395		$	246		$	255
Tax positions related to current year:
Additions		2			150			(1	)
Reductions		—			—			(2	)
Tax positions related to prior years:
Additions		20			35			77
Reductions		(57	)		(36	)		(83	)
Settlements		(3	)		—			—
Ending balance as of December 31,	$	357		$	395		$	246

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, 2011 included $29 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, 2011, 2010 and 2009, PHI recognized $23 million of pre-tax interest income ($14 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 related to continuing operations. As of December 31, 2011, 2010 and 2009, PHI had $4 million, $12 million and $13 million, respectively, of accrued interest payable 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 PHI’s uncertain tax positions will significantly increase or decrease within the next 12 months. The possible settlement of the cross-border energy lease investments issue, the 2003 to 2005 federal audit, the methodology change for deduction of capitalized construction costs, or state audits could impact the balances and related interest accruals significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.

Tax Years Open to Examination

PHI’s Federal income tax liabilities for Pepco legacy companies for all years through 2002, and for Conectiv legacy companies for all years through 2002, 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. PHI has not reached final settlement with the IRS with respect to the cross-border energy lease deductions. 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.

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Resolution of Certain IRS Audit Matters

In 2010, PHI resolved all tax matters that were raised in IRS audits related to the 2001 and 2002 tax years except for the cross-border energy lease issue. Adjustments recorded relating to these resolved tax matters resulted in a $1 million increase to income tax expense exclusive of interest.

Other Taxes

Other taxes for continuing operations are shown below. The annual amounts include $445 million, $427 million and $358 million for the years ended December 31, 2011, 2010 and 2009, respectively, related to Power Delivery, which are recoverable through rates.

	2011		2010		2009
	(millions of dollars)
Gross Receipts/Delivery	$	145	$	145	$	142
Property		71		70		68
County Fuel and Energy		170		154		94
Environmental, Use and Other		65		65		64
Total	$	451	$	434	$	368

(13) NON-CONTROLLING INTEREST

The outstanding preferred stock issued by subsidiaries of PHI as of December 31, 2011 and 2010 consisted of the following series of serial preferred stock issued by ACE. The shares of each of the series were redeemable solely at the option of the issuer. During 2011, ACE redeemed all of its outstanding cumulative preferred stock at the redemption prices indicated in the table below.

	Redemption Price		Shares Outstanding				December 31,
			2011		2010		2011		2010
							(millions of dollars)
4.0% Series of 1944, $100 per share par value	$	105.50		—		24,268	$	—	$	2
4.35% Series of 1949, $100 per share par value	$	101.00		—		2,942		—		—
4.35% Series of 1953, $100 per share par value	$	101.00		—		1,680		—		—
4.10% Series of 1954, $100 per share par value	$	101.00		—		20,504		—		2
4.75% Series of 1958, $100 per share par value	$	101.00		—		8,631		—		1
5.0% Series of 1960, $100 per share par value	$	100.00		—		4,120		—		1
Total Preferred Stock of Subsidiaries				—		62,145	$	—	$	6

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(14) STOCK-BASED COMPENSATION, DIVIDEND RESTRICTIONS, AND CALCULATIONS OF EARNINGS PER SHARE OF COMMON STOCK

Stock-Based Compensation

PHI maintains a Long-Term Incentive Plan (LTIP), the objective of which is to increase shareholder value by providing a long-term incentive to reward officers and key employees of Pepco Holdings and its subsidiaries and to increase the ownership of Pepco Holdings’ common stock by such individuals. Any officer or key employee of Pepco Holdings or its subsidiaries may be designated by the PHI Board of Directors as a participant in the LTIP. Under the LTIP, awards to officers and key employees may be in the form of restricted stock, restricted stock units, stock options, performance units, stock appreciation rights, unrestricted stock, and dividend equivalents. At inception, 10 million shares of common stock were authorized for issuance under the LTIP.

Total stock-based compensation expense recorded in the consolidated statements of income for the years ended December 31, 2011, 2010 and 2009 was $6 million, $5 million and $5 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, 2011, 2010 and 2009.

Restricted Stock and Restricted Stock Unit Awards

Description of awards

A number of programs have been established under the LTIP involving the issuance of restricted stock and restricted stock unit awards, including awards of performance-based restricted stock units, time-based restricted stock and restricted stock units, retention restricted stock and the Conectiv performance accelerated restricted stock (PARS). 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 0% to 200% of the target award, and dividends accrued thereon.

• Generally, time-based restricted stock and restricted stock unit award opportunities have a requisite service period of 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 three-year service period.

• In connection with the acquisition of Conectiv by Pepco in 2002, PARS previously issued to Conectiv employees were converted to shares of Pepco Holdings restricted stock. These shares typically vested over periods of 5 to 7 years. In January 2009, all 6,669 of the remaining PARS outstanding fully vested.

• In September 2007, retention awards in the form of 9,015 shares of restricted stock were granted to certain PHI executives, with vesting periods of two or three years. In September 2009, 5,409 of these shares vested. In September 2010, all 3,606 of the remaining shares outstanding vested.

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Activity for the year

The 2011 activity for non-vested, time-based restricted stock, restricted stock units and performance-based restricted stock unit awards is summarized in the table below. For performance-based restricted stock unit awards, the table reflects awards projected to achieve 100% of targeted performance criteria for the 2010-2012 and 2011-2013 award cycles.

	Number of Shares			Total Number of Shares			Weighted Average Grant Date Fair Value
Balance at January 1, 2011
Time-based restricted stock		316,194					$	18.15
Performance-based restricted stock units		586,883						20.75
Total					903,077
Granted during 2011
Time-based restricted stock units		177,895						18.87
Performance-based restricted stock units		354,979						19.56
Total					532,874
Vested during 2011
Time-based restricted stock		(63,764	)					23.70
Time-based restricted stock units		(173	)					18.84
Performance-based restricted stock units		(144,451	)					25.36
Total					(208,388	)
Forfeited during 2011
Time-based restricted stock		(10,741	)					17.06
Time-based restricted stock units		(7,191	)					18.84
Performance-based restricted stock units		(32,272	)					21.78
Total					(50,204	)
Balance at December 31, 2011
Time-based restricted stock		241,689						16.74
Time-based restricted stock units		170,531						18.87
Performance-based restricted stock units		765,139						19.28
Total					1,177,359

Grants included in the table above reflect 2011 grants of performance-based restricted stock units and time-based restricted stock units. PHI recognizes compensation expense related to performance-based restricted stock unit awards and time-based restricted stock and 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 of those awards granted during each of the years ended December 31, 2011, 2010 and 2009:

	2011		2010		2009
Weighted average grant-date fair value of each performance-based restricted stock unit granted during the year	$	19.56	$	20.11	$	17.51
Weighted average grant-date fair value of each award of time-based restricted stock granted during the year	$	—	$	16.55	$	17.18
Weighted average grant-date fair value of each time-based restricted stock unit granted during the year	$	18.87	$	—	$	—

As of December 31, 2011, there was approximately $9 million of future compensation cost (net of estimated forfeitures) related to non-vested restricted stock awards and restricted stock unit awards granted under the 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 must have an exercise price at least equal to the fair market value of the underlying stock on the grant date. Stock options that have been granted under the LTIP generally have become exercisable on a specified vesting date or dates. All stock options have an expiration date of no greater than ten years from the date of grant. No options have been granted under the LTIP since May 1, 2002.

Non-employee directors are entitled, under the terms of the LTIP, to a grant on May 1 of each year of a nonqualified stock option for 1,000 shares of common stock. However, the Board of Directors has determined that these grants will not be made.

Stock option activity for the year ended December 31, 2011 is summarized below:

	Number of Options			Weighted Average Exercise Price			Weighted Average Remaining Contractual Term (Years)		Aggregate Intrinsic Value
Outstanding at January 1, 2011		280,266		$	22.30			0.70
Options granted		—			—			—
Options exercised		(81,918	)		19.03			—
Options forfeited or expired		(167,423	)		24.19			—
Outstanding at December 31, 2011		30,925			20.75			0.03	$	—
Exercisable at December 31, 2011		30,925			20.75	(a)		0.03	$	—

(a) The range of exercise prices is $19.03 to $22.69

Total intrinsic value and tax benefits recognized for stock options exercised in 2011, 2010 and 2009 were immaterial.

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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 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 each of the years ended December 31, 2011, 2010 and 2009 was not material.

Compensation expense recognized in respect of dividends and the increase in fair value for each of the years ended December 31, 2011, 2010 and 2009 was not material. The deferred compensation balance under this program was approximately $1 million at December 31, 2011 and 2010.

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 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, 2011. 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 $1,072 million and $1,059 million of retained earnings free of restrictions at December 31, 2011 and 2010, respectively. These amounts represent the total retained earnings balances at those dates.

For the years ended December 31, Pepco Holdings received dividends from its subsidiaries as follows:

Subsidiary	2011		2010		2009
	(millions of dollars)
Pepco	$	25	$	115	$	—
DPL		60		23		28
ACE		—		35		64
Total	$	85	$	173	$	92

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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 Years Ended December 31 ,
	2011			2010			2009
	(millions of dollars, except per share data)
Income (Numerator):
Net income from continuing operations	$	260		$	139		$	223
Net (loss) income from discontinued operations		(3	)		(107	)		12
Net income	$	257		$	32		$	235
Shares (Denominator) (in millions):
Weighted average shares outstanding for basic computation:
Average shares outstanding		226			224			221
Adjustment to shares outstanding		—			—			—
Weighted Average Shares Outstanding for Computation of Basic Earnings Per Share of Common Stock		226			224			221
Net effect of potentially dilutive shares (a)		—			—			—
Weighted Average Shares Outstanding for Computation of Diluted Earnings Per Share of Common Stock		226			224			221
Basic and diluted earnings per share of common stock from continuing operations	$	1.15		$	0.62		$	1.01
Basic and diluted (loss) earnings per share of common stock from discontinued operations		(0.01	)		(0.48	)		0.05
Basic and diluted earnings per share	$	1.14		$	0.14		$	1.06

(a) The number of options to purchase shares of common stock that were excluded from the calculation of diluted earnings per share as they are considered to be anti-dilutive were 14,900, 280,266 and 334,966 for the years ended December 31, 2011, 2010 and 2009, respectively.

Shareholder Dividend Reinvestment Plan

PHI maintains a Shareholder Dividend Reinvestment Plan (DRP) through which shareholders may reinvest cash dividends. In addition, both existing shareholders and new investors can make purchases of shares of PHI common stock through the investment of not less than $25 each calendar month nor more than $200,000 each calendar year. Shares of common stock purchased through the DRP may be new shares or, at the election of PHI, shares purchased in the open market. Approximately 2 million new shares were issued and sold under the DRP in each of 2011, 2010 and 2009.

Pepco Holdings Common Stock Reserved and Unissued

The following table presents Pepco Holdings’ common stock reserved and unissued at December 31, 2011:

Name of Plan	Number of Shares
DRP		3,448,048
Conectiv Incentive Compensation Plan (a)		1,093,701
Potomac Electric Power Company Long-Term Incentive Plan (a)		327,059
Pepco Holdings Long-Term Incentive Plan		7,791,543
Pepco Holdings Non-Management Directors Compensation Plan		462,429
Pepco Holdings Retirement Savings Plan		1,298,849
Total		14,421,629

(a) No further awards will be made under this plan.

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(15) DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Derivatives are used by Pepco Energy Services and Power Delivery to hedge commodity price risk, as well as by PHI, from time to time, to hedge interest rate risk.

The retail energy supply business of Pepco Energy Services, which is in the process of being wound down, enters into energy commodity contracts in the form of electricity and natural gas futures, swaps, options and forward contracts to hedge commodity price risk in connection with the purchase of physical natural gas and electricity for distribution to customers. The primary risk management objective is to manage the spread between retail sales commitments and the cost of supply used to service those commitments to ensure stable cash flows and lock in favorable prices and margins when they become available.

Pepco Energy Services’ commodity contracts that are not designated for hedge accounting, do not qualify for hedge accounting, or do not meet the requirements for normal purchase and normal sale accounting, are marked to market through current earnings. Forward contracts that meet the requirements for normal purchase and normal sale accounting are recorded on an accrual basis.

In Power Delivery, DPL uses derivative instruments in the form of swaps and over-the-counter options 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. DPL’s capacity contracts are not classified as derivatives. 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.

PHI also uses derivative instruments from time to time to mitigate the effects of fluctuating interest rates on debt issued in connection with the operation of their 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 income over the life of the debt issued as interest payments are made. As further described in Note (11), “Debt,” $15 million of these pre-tax losses ($9 million after-tax) was reclassified into income during 2010.

The tables below identify the balance sheet location and fair values of derivative instruments as of December 31, 2011 and 2010:

	As of December 31, 2011
Balance Sheet Caption	Derivatives Designated as Hedging Instruments(a)			Other Derivative Instruments(b)			Gross Derivative Instruments			Effects of Cash Collateral and Netting			Net Derivative Instruments
	(millions of dollars)
Derivative assets (current assets)	$	17		$	6		$	23		$	(18	)	$	5
Derivative assets (non-current assets)		—			1			1			(1	)		—
Total Derivative assets		17			7			24			(19	)		5
Derivative liabilities (current liabilities)		(55	)		(48	)		(103	)		77			(26	)
Derivative liabilities (non-current liabilities)		(11	)		(10	)		(21	)		15			(6	)
Total Derivative liabilities		(66	)		(58	)		(124	)		92			(32	)
Net Derivative (liability) asset	$	(49	)	$	(51	)	$	(100	)	$	73		$	(27	)

(a) Amounts included in Derivatives Designated as Hedging Instruments primarily consist of derivatives that were designated as cash flow hedges prior to Pepco Energy Services’ election to discontinue cash flow hedge accounting for these derivatives.

(b) Amounts included in Other Derivative Instruments include gains or losses on derivatives that are not accounted for as cash flow hedges subsequent to Pepco Energy Services’ election to discontinue cash flow hedge accounting.

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	As of December 31, 2010
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)	$	40		$	43		$	83		$	(38	)	$	45
Derivative assets (non-current assets)		16			3			19			(19	)		—
Total Derivative assets		56			46			102			(57	)		45
Derivative liabilities (current liabilities)		(125	)		(63	)		(188	)		122			(66	)
Derivative liabilities (non-current liabilities)		(68	)		(10	)		(78	)		57			(21	)
Total Derivative liabilities		(193	)		(73	)		(266	)		179			(87	)
Net Derivative (liability) asset	$	(137	)	$	(27	)	$	(164	)	$	122		$	(42	)

Under FASB guidance on the offsetting of balance sheet accounts (ASC 210-20), PHI offsets the fair value amounts recognized for derivative instruments and the fair value amounts recognized for related collateral positions executed with the same counterparty under master netting agreements. The amount of cash collateral that was offset against these derivative positions is as follows:

	December 31, 2011		December 31, 2010
	(millions of dollars)
Cash collateral pledged to counterparties with the right to reclaim (a)	$	73	$	122

(a) Includes cash deposits on commodity brokerage accounts.

As of December 31, 2011 and 2010, 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

Pepco Energy Services

For energy commodity contracts that are designated and qualify as cash flow hedges, the effective portion of the gain or loss on the derivative is reported as a component of AOCL and is reclassified into income in the same period or periods during which the hedged transactions affect income. Gains and losses on the derivative that are related to hedge ineffectiveness or the forecasted hedged transaction being probable not to occur, are recognized in income. Pepco Energy Services has elected to no longer apply cash flow hedge accounting to certain of its electricity derivatives and all of its natural gas derivatives. Amounts included in AOCL for these cash flow hedges as of December 31, 2011 represent net losses on derivatives prior to the election to discontinue cash flow hedge accounting less amounts reclassified into income as the hedged transactions occur or because the hedged transactions were deemed probable not to occur. Gains or losses on these derivatives after the election to discontinue cash flow hedge accounting are recognized in income. The cash flow hedge activity during the years ended December 31, 2011, 2010 and 2009 is provided in the tables below:

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	For the Year Ended December 31,
	2011		2010			2009
	(millions of dollars)
Amount of net pre-tax loss arising during the period included in accumulated other comprehensive loss	$	—	$	(100	)	$	(129	)
Amount of net pre-tax (gain) loss reclassified into income:
Effective portion:
Fuel and purchased energy		80		135			164
Ineffective portion: (a)
Revenue		1		—			2
Total net pre-tax (gain) loss reclassified into income		81		135			166
Net pre-tax gain (loss) on commodity derivatives included in other comprehensive loss	$	81	$	35		$	37

(a) Included in the above table is a loss of $1 million and $2 million for the years ended December 31, 2011 and 2009, respectively, which were reclassified from AOCL to income because the forecasted hedged transactions were deemed probable not to occur.

As of December 31, 2011 and 2010, Pepco Energy Services had the following types and quantities of outstanding energy commodity contracts employed as cash flow hedges of forecasted purchases and forecasted sales.

	Quantities
Commodity	December 31, 2011		December 31, 2010
Forecasted Purchases Hedges
Natural gas (One Million British Thermal Units (MMBtu))		—		8,597,106
Electricity (Megawatt hours (MWh))		614,560		2,677,640
Electric capacity (MW-Days)		—		34,730
Forecasted Sales Hedges
Electricity (MWh)		614,560		2,517,200

Power Delivery

All premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all of DPL’s gains and losses related to hedging activities, are deferred under FASB guidance on regulated operations until recovered from customers based on the fuel adjustment clause approved by the DPSC. The following table indicates the amount of the net unrealized derivative losses arising during the period included in Regulatory assets and the realized losses recognized in the consolidated statements of income for the years ended December 31, 2011, 2010 and 2009 associated with cash flow hedges:

	For the Year Ended December 31,
	2011			2010			2009
	(millions of dollars)
Net unrealized losses arising during the period included in Regulatory assets	$	—		$	(9	)	$	(20	)
Net realized losses recognized in Fuel and purchased energy expense		(5	)		(13	)		(41	)

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As of December 31, 2011 and 2010, DPL had the following outstanding commodity forward contracts that were entered into to hedge forecasted transactions:

	Quantities
Commodity	December 31, 2011		December 31, 2010
Forecasted Purchases Hedges
Natural gas (MMBtu)		—		1,840,000

Effective October 1, 2011, DPL elected to no longer apply cash flow hedge accounting to its natural gas derivatives. These derivatives will continue to be employed as part of DPL’s natural gas hedging activities under the hedging program approved by the DPSC, and their dedesignation as cash flow hedges has not resulted in a change to the historical financial statement presentation because all of DPL’s gains and losses on these derivatives are recoverable from customers through the fuel adjustment clause approved by the DPSC.

Cash Flow Hedges Included in Accumulated Other Comprehensive Loss

The tables below provide details regarding effective cash flow hedges included in PHI’s consolidated balance sheet as of December 31, 2011 and 2010. Cash flow hedges are marked to market on the balance sheet with corresponding adjustments to AOCL for effective cash flow hedges. As of December 31, 2011, $42 million of the losses in AOCL were associated with derivatives that Pepco Energy Services previously designated as cash flow hedges. Although Pepco Energy Services no longer designates these derivatives as cash flow hedges, gains or losses previously deferred in AOCL prior to the decision to discontinue cash flow hedge accounting will remain in AOCL until the hedged forecasted transaction occurs unless it is deemed probable that the hedged forecasted transaction will not occur. The data in the following tables indicate the cumulative net loss after-tax related to effective 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, 2011				Maximum Term
	Accumulated Other Comprehensive Loss After-tax		Portion Expected to be Reclassified to Income during the Next 12 Months
	(millions of dollars)
Energy commodity (a)	$	29	$	23		29 months
Interest rate		10		1		248 months
Total	$	39	$	24

(a) The unrealized derivative losses recorded in AOCL relate to forecasted natural gas and electricity physical purchases which are used to supply retail natural gas and electricity contracts that are in gain positions and subject to accrual accounting. Under accrual accounting, no asset is recorded on the balance sheet and the purchase cost is not recognized until the period of distribution.

Contracts	As of December 31, 2010				Maximum Term
	Accumulated Other Comprehensive Loss After-tax		Portion Expected to be Reclassified to Income during the Next 12 Months
	(millions of dollars)
Energy commodity (a)	$	78	$	48		41 months
Interest rate		11		1		260 months
Total	$	89	$	49

(a) The unrealized derivative losses recorded in AOCL relate to forecasted natural gas and electricity physical purchases which are used to supply retail natural gas and electricity contracts that are in gain positions and subject to accrual accounting. Under accrual accounting, no asset is recorded on the balance sheet and the purchase cost is not recognized until the period of distribution.

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Other Derivative Activity

Pepco Energy Services

Pepco Energy Services holds certain derivatives that are not in hedge accounting relationships nor are they designated as normal purchases or normal sales. These derivatives are recorded at fair value on the balance sheet with changes in fair value recorded through income.

For the years ended December 31, 2011, 2010 and 2009, the amount of the derivative gain (loss) for Pepco Energy Services recognized in income as part of revenue is provided in the table below:

	For the Year Ended December 31,
	2011			2010			2009
	(millions of dollars)
Realized gains (losses)	$	—		$	2		$	(2	)
Unrealized mark-to-market losses		(30	)		(3	)		(2	)
Total net losses	$	(30	)	$	(1	)	$	(4	)

As of December 31, 2011 and 2010, Pepco Energy Services had the following net outstanding commodity forward contract quantities and net position on derivatives that did not qualify for hedge accounting:

	December 31, 2011				December 31, 2010
Commodity	Quantity		Net Position		Quantity		Net Position
Financial transmission rights (MWh)		267,480		Long		381,215		Long
Electric capacity (MW-Days)		12,920		Long		2,265		Long
Electricity (MWh)		788,280		Long		1,455,800		Long
Natural gas (MMBtu)		24,550,257		Long		45,889,486		Long

Power Delivery

DPL holds certain derivatives that are not in hedge accounting relationships nor are they 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 the change in fair value recorded in income. In accordance with FASB guidance on regulated operations, offsetting regulatory liabilities or regulatory assets 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 the year ended December 31, 2011, 2010 and 2009, the net unrealized derivative losses arising during the period included in Regulatory assets and the net realized losses recognized in the consolidated statements of income are provided in the table below:

	For the Year Ended December 31,
	2011			2010			2009
	(millions of dollars)
Net unrealized losses arising during the period included in Regulatory assets	$	(13	)	$	(20	)	$	(18	)
Net realized losses recognized in Fuel and purchased energy expense		(22	)		(26	)		(11	)

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As of December 31, 2011 and 2010, DPL had the following net outstanding natural gas commodity forward contracts that did not qualify for hedge accounting:

	December 31, 2011				December 31, 2010
Commodity	Quantity		Net Position		Quantity		Net Position
Natural gas (MMBtu)		6,161,200		Long		8,236,500		Long

Contingent Credit Risk Features

The primary contracts used by Pepco Energy Services and Power Delivery segments for derivative transactions are entered into under the International Swaps and Derivatives Association Master Agreement (ISDA) or similar agreements that closely mirror the principal credit provisions of the ISDA. The ISDAs include a Credit Support Annex (CSA) that governs the mutual posting and administration of collateral security. The failure of a party to comply with an obligation under the CSA, including an obligation to transfer collateral security when due or the failure to maintain any required credit support, constitutes an event of default under the ISDA for which the other party may declare an early termination and liquidation of all transactions entered into under the ISDA, including foreclosure against any collateral security. In addition, some of the ISDAs have cross default provisions under which a default by a party under another commodity or derivative contract, or the breach by a party of another borrowing obligation in excess of a specified threshold, is a breach under the ISDA.

Under the ISDA or similar agreements, the parties establish a dollar threshold of unsecured credit for each party in excess of which the party would be required to post collateral to secure its obligations to the other party. The amount of the unsecured credit threshold varies according to the senior, unsecured debt rating of the respective parties or that of a guarantor of the party’s obligations. The fair values of all transactions between the parties are netted under the master netting provisions. Transactions may include derivatives accounted for on-balance sheet as well as those designated as normal purchases and normal sales that are accounted for off-balance sheet. If the aggregate fair value of the transactions in a net loss position exceeds the unsecured credit threshold, then collateral is required to be posted in an amount equal to the amount by which the unsecured credit threshold is exceeded. The obligations of Pepco Energy Services are usually guaranteed by PHI. The obligations of DPL are stand-alone obligations without the guaranty of PHI. If PHI’s or DPL’s credit rating were to fall below “investment grade,” the unsecured credit threshold would typically be set at zero and collateral would be required for the entire net loss position. Exchange-traded contracts are required to be fully collateralized without regard to the credit rating of the holder.

The gross fair value of PHI’s derivative liabilities, excluding the impact of offsetting transactions or collateral under master netting agreements, with credit risk-related contingent features on December 31, 2011 and 2010, was $54 million and $156 million, respectively, before giving effect to the impact of a credit rating downgrade that would increase these amounts or offsetting transactions that are encompassed within master netting agreements that would alter these amounts. As of December 31, 2011, PHI had posted cash collateral of $1 million against the gross derivative liability resulting in a net liability of $53 million. As of December 31, 2010, PHI had not posted any cash collateral against the gross derivative liability. PHI’s net settlement amount in the event of a downgrade of PHI’s and DPL’s senior unsecured debt rating to below investment grade as of December 31, 2011 and 2010, would have been approximately $124 million and $182 million, respectively, after taking into consideration the master netting agreements. At December 31, 2011 and 2010, normal purchase and normal sale contracts in a loss position increased PHI’s obligation.

PHI’s primary sources for posting cash collateral or letters of credit are its credit facilities. At December 31, 2011 and 2010, the aggregate amount of cash plus borrowing capacity under the primary credit facilities available to meet the future liquidity needs of PHI and its subsidiaries totaled $1 billion and $1.2 billion, respectively, of which $283 million and $728 million, respectively, was available to Pepco Energy Services.

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(16) FAIR VALUE DISCLOSURES

Financial Instruments Measured at Fair Value on a Recurring Basis

PHI applies FASB guidance on fair value measurement and disclosures (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). 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 New York Mercantile Exchange (NYMEX).

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.

PHI’s level 2 derivative instruments primarily consist of electricity derivatives at December 31, 2011. Level 2 power swap values are provided by a pricing service that uses liquid trading hub prices or liquid hub prices plus a congestion adder to estimate the fair value at zonal locations within trading hubs.

Executive deferred compensation plan assets consist of life insurance policies that are categorized as level 2 assets because they are priced 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, 2011. 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.

Level 3 – Pricing inputs include significant inputs that are 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 categorized as level 3 include natural gas options purchased by DPL as part of a natural gas hedging program approved by the DPSC and natural gas physical basis contracts held by Pepco Energy Services. The valuation of the options is based, in part, on internal volatility assumptions extracted from historical NYMEX prices over a certain period of time. The physical basis contracts are valued using liquid hub prices plus a congestion adder that is internally derived from historical data and experience.

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Executive deferred compensation plan assets and liabilities that are classified as level 3 include certain life insurance policies that are valued using the cash surrender value of the policies, net of loans against those policies, which does not represent a quoted price in an active market.

The following tables set forth, by level within the fair value hierarchy, PHI’s financial assets and liabilities (excluding Conectiv Energy assets and liabilities held for sale) that were accounted for at fair value on a recurring basis as of December 31, 2011 and 2010. 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, 2011
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 (b)
Electricity (c)	$	—	$	—	$	—	$	—
Cash equivalents
Treasury Fund		114		114		—		—
Executive deferred compensation plan assets
Money Market Funds		18		18		—		—
Life Insurance Contracts		60		—		43		17
	$	192	$	132	$	43	$	17
LIABILITIES
Derivative instruments (b)
Electricity (c)	$	32	$	—	$	32	$	—
Natural Gas (d)		67		50		—		17
Capacity		1		—		1		—
Executive deferred compensation plan liabilities
Life Insurance Contracts		28		—		28		—
	$	128	$	50	$	61	$	17

(a) There were no significant transfers of instruments between level 1 and level 2 valuation categories.

(b) The fair value of derivative assets and liabilities reflect netting by counterparty before the impact of collateral.

(c) Represents wholesale electricity futures and swaps that are used mainly as part of Pepco Energy Services’ retail energy supply business.

(d) Level 1 instruments represent wholesale gas futures and swaps that are used mainly as part of Pepco Energy Services’ retail energy supply business and level 3 instruments represent natural gas options 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, 2010
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 (b)
Electricity (c)	$	22	$	—	$	22	$	—
Cash equivalents
Treasury Fund		17		17		—		—
Executive deferred compensation plan assets
Money Market Funds		9		9		—		—
Life Insurance Contracts		66		—		47		19
	$	114	$	26	$	69	$	19
LIABILITIES
Derivative instruments (b)
Electricity (c)	$	88	$	—	$	88	$	—
Natural Gas (d)		98		75		—		23
Executive deferred compensation plan liabilities
Life Insurance Contracts		30		—		30		—
	$	216	$	75	$	118	$	23

(a) There were no significant transfers of instruments between level 1 and level 2 categories.

(b) The fair value of derivative assets and liabilities reflect netting by counterparty before the impact of collateral.

(c) Represents wholesale electricity futures and swaps that are used mainly as part of Pepco Energy Services’ retail energy supply business.

(d) Level 1 instruments represent wholesale gas futures and swaps that are used mainly as part of Pepco Energy Services’ retail energy supply business and level 3 instruments represent natural gas options purchased by DPL as part of a natural gas hedging program approved by the DPSC.

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, 2011 and 2010 are shown below:

	Year Ended December 31, 2011
	Natural Gas			Life Insurance Contracts
	(millions of dollars)
Beginning balance as of January 1, 2011	$	(23	)	$	19
Total gains (losses) (realized and unrealized):
Included in income		(4	)		6
Included in accumulated other comprehensive loss		—			—
Included in regulatory liabilities		(10	)		—
Purchases		—			—
Issuances		—			(3	)
Settlements		19			(5	)
Transfers in (out) of Level 3		1			—
Ending balance as of December 31, 2011	$	(17	)	$	17

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	Year Ended December 31, 2010
	Natural Gas			Life Insurance Contracts
	(millions of dollars)
Beginning balance as of January 1, 2010	$	(29	)	$	19
Total gains (losses) (realized and unrealized):
Included in income		—			3
Included in accumulated other comprehensive loss		—			—
Included in regulatory liabilities		(20	)		—
Purchases		—			—
Issuances		—			(3	)
Settlements		26			—
Transfers in (out) of Level 3		—			—
Ending balance as of December 31, 2010	$	(23	)	$	19

The breakdown of realized and unrealized gains or (losses) 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,
	2011		2010
	(millions of dollars)
Total net gains included in income for the period	$	2	$	3
Change in unrealized gains relating to assets still held at reporting date	$	2	$	3

Other Financial Instruments

The estimated fair values of PHI’s issued debt and equity instruments at December 31, 2011 and 2010 are shown below:

	December 31, 2011				December 31, 2010
	(millions of dollars)
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	3,867	$	4,577	$	3,665	$	4,045
Transition Bonds issued by ACE Funding		332		380		367		406
Long-Term Project Funding		15		15		19		19
Redeemable Serial Preferred Stock		—		—		6		5

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The fair value of Long-Term Debt was based on actual trade prices (where available), bid prices obtained from brokers and validated by PHI, or a discounted cash flow model. Prices obtained from brokers include observable market data on the target security or historical correlation and direct observation methodologies of similar debt securities.

The fair value of Transition Bonds issued by ACE Funding, including amounts due within one year, were derived based on actual trade prices as of December 31, 2011. Bid prices obtained from brokers and validated by PHI were used at December 31, 2010, because actual trade prices were not available.

The fair value of the Redeemable Serial Preferred Stock, was derived based on quoted market prices.

The carrying amounts of all other financial instruments in the accompanying financial statements approximate fair value.

(17) COMMITMENTS AND CONTINGENCIES

General Litigation

In 1993, Pepco was served with Amended Complaints filed in the state Circuit Courts of Prince George’s County, Baltimore City and Baltimore County, Maryland in separate ongoing, consolidated proceedings known as “In re: Personal Injury Asbestos Case.” Pepco and other corporate entities were brought into these cases on a theory of premises liability. Under this theory, the plaintiffs argued that Pepco was negligent in not providing a safe work environment for employees or its contractors, who allegedly were exposed to asbestos while working on Pepco’s property. Initially, a total of approximately 448 individual plaintiffs added Pepco to their complaints. While the pleadings are not entirely clear, it appears that each plaintiff sought $2 million in compensatory damages and $4 million in punitive damages from each defendant.

As of December 31, 2011, there are approximately 180 cases still pending against Pepco in the Maryland State Courts, of which approximately 90 cases were filed after December 19, 2000, and were tendered to Mirant Corporation (Mirant) for defense and indemnification in connection with the sale by Pepco of its generation assets to Mirant in 2000. While the aggregate amount of monetary damages sought in the remaining suits (excluding those tendered to Mirant) is approximately $360 million, PHI and Pepco believe the amounts claimed by the remaining plaintiffs are greatly exaggerated. The amount of total liability, if any, and any related insurance recovery cannot be determined at this time. If an unfavorable decision were rendered against Pepco, it could have a material adverse effect on Pepco’s and PHI’s financial condition, results of operations and cash flows.

In September 2011, an asbestos complaint was filed in the New Jersey Superior Court, Law Division, against ACE (among other defendants) asserting claims under New Jersey’s Wrongful Death and Survival statutes. The complaint, filed by the estate of a decedent who was the wife of a former employee of ACE, alleges that the decedent’s mesothelioma was caused by exposure to asbestos brought home by her husband on his work clothes. Unlike the other jurisdictions to which PHI subsidiaries are subject, New Jersey courts have recognized a cause of action against a premise owner in a so-called “take home” case if it can be shown that the harm was foreseeable. In this case, the complaint seeks recovery of an unspecified amount of damages for the decedent’s past medical expenses, loss of earnings, and pain and suffering between the time of injury and death, and asserts a punitive damage claim. At this time, ACE cannot estimate an amount or range of reasonably possible loss to which it may be exposed that may be associated with the claims raised in this complaint. Such an estimate of reasonably possible loss must await further internal investigation and discovery procedures.

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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 the operating utilities, 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 of PHI and its subsidiaries described below at December 31, 2011 are summarized as follows:

				Legacy Generation
	Transmission and Distribution			Regulated			Non-Regulated		Other		Total
	(millions of dollars)
Beginning balance as of January 1	$	13		$	9		$	10	$	2	$	34
Accruals		3			—			—		—		3
Payments		(1	)		(1	)		—		—		(2	)
Ending balance as of December 31		15			8			10		2		35
Less amounts in Other Current Liabilities		2			2			—		2		6
Amounts in Other Deferred Credits	$	13		$	6		$	10	$	—	$	29

Conectiv Energy Wholesale Power Generation Sites

On July 1, 2010, PHI sold the Conectiv Energy wholesale power generation business to 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 preliminary 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 under the column entitled Legacy Generation – Non-Regulated.

On September 14, 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 January 1, 2001 and July 1, 2010, to demonstrate compliance with the Clean Air Act’s new source review permitting program. The data request covers the period from February 2004 to July 1, 2010. 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 this inquiry to have a material effect on its financial position or results of operations.

The sale of the Conectiv Energy wholesale power generation business to Calpine did not include a coal ash landfill site located at the Edge Moor generating facility, which PHI intends to close. The preliminary estimate of the costs to PHI to close the coal ash landfill ranges from approximately $2 million to $3 million, plus annual post-closure operations, maintenance and monitoring costs, estimated to range between $120,000 and $193,000 per year for 30 years. The amounts accrued by PHI for this matter are included in the table above under the column entitled Legacy Generation – Non-Regulated.

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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 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 estimates the additional cost for future response measures will be approximately $6 million. ACE believes that EPA sent similar general notice letters to three other companies and various individuals.

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 Peck’s 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 a Federal Register notice published on November 4, 2009, EPA placed the Peck Iron and Metal site on the National Priorities List (NPL). The NPL, among other things, serves as a guide to EPA in determining which sites warrant further investigation to assess the nature and extent of the human health and environmental risks associated with a site. In September 2011, EPA initiated a remedial investigation/feasibility study (RI/FS) using federal funds. Pepco cannot at this time estimate an amount or range of reasonably possible loss associated with the 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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Ward Transformer Site

In April 2009, a group of PRPs with respect to the Ward Transformer site in Raleigh, North Carolina, filed a complaint in the U.S. District Court for the Eastern District of North Carolina, alleging cost recovery and/or contribution claims against a number of entities, including ACE, DPL and Pepco with respect to past and future response costs incurred by the PRP group in performing a removal action at the site. In a March 2010 order, the court denied the defendants’ motion to dismiss. The next step in the litigation will be the filing of summary judgment motions regarding liability for certain “test case” defendants other than ACE, DPL and Pepco. The case has been stayed as to the remaining defendants pending rulings upon the test cases. Although PHI cannot at this time estimate an amount or range of reasonably possible losses to which it may be exposed, PHI does not believe that any of its three utility subsidiaries had extensive business transactions, if any, with the Ward Transformer site and therefore, costs incurred to resolve this matter are not expected to be material.

Benning Road Site

In September 2010, PHI received a letter from EPA stating that EPA and the District of Columbia Department of the Environment (DDOE) have identified the Benning Road location, consisting of a transmission and distribution facility operated by Pepco and a generation facility operated by Pepco Energy Services, as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. The letter stated that the principal contaminants of concern are polychlorinated biphenyls and polycyclic aromatic hydrocarbons, that EPA is monitoring the efforts of DDOE and that EPA intends to use federal authority to address the Benning Road site if an agreement for a comprehensive study to evaluate (and, if necessary, to clean up) the facility is not reached. In January 2011, Pepco and Pepco Energy Services entered into a proposed consent decree with DDOE that requires Pepco and Pepco Energy Services to conduct a RI/FS for the Benning Road site and an approximately 10-15 acre portion of the adjacent Anacostia River. The RI/FS will form the basis for DDOE’s selection of a remedial action for the Benning Road site and for the Anacostia River sediment associated with the site. In February 2011, the District of Columbia filed a complaint against Pepco and Pepco Energy Services in the United States District Court for the District of Columbia for the purpose of obtaining judicial approval of the consent decree. The complaint asserted claims under CERCLA, the Resource Conservation and Recovery Act, and District of Columbia law seeking to compel Pepco and Pepco Energy Services to take actions to investigate and clean up contamination allegedly originating from the Benning Road site, and to reimburse the District of Columbia for its response costs. On December 1, 2011, the District Court issued an order granting the motion to enter a revised consent decree. The District Court’s order entering the consent decree requires DDOE to solicit and consider public comment on the key RI/FS documents prior to final approval, requires DDOE to make final versions of all approved RI/FS documents available to the public, and requires the parties to submit a written status report to the District Court on May 24, 2013 regarding the implementation of the requirements of the consent decree and any related plans for remediation. In addition, if the RI/FS has not been completed by May 24, 2013, the status report must provide an explanation and a showing of good cause for why the work has not been completed.

Pepco and Pepco Energy Services commenced work on the RI/FS upon entry of the consent decree. On December 21, 2011, they submitted a draft RI/FS Scope of Work and a draft Community Involvement Plan to DDOE for review. DDOE has solicited public comment on these documents, which were due by February 13, 2012, with respect to the draft Scope of Work, and are due by March 7, 2012 with respect to the draft Community Involvement Plan. Depending on the nature and extent of public comments received, Pepco and Pepco Energy Services anticipate that these documents will be approved and a draft RI/FS work plan will be submitted by the end of the first quarter of 2012. The field work will commence after final work plan approval by DDOE.

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The amount of remediation costs accrued for this matter is included in the table above under the column entitled Transmission and Distribution.

Price’s Pit Site

ACE owns a transmission and distribution right-of-way that traverses the Price’s Pit superfund site in Egg Harbor Township, New Jersey. EPA placed Price’s Pit on the NPL in 1983 and the New Jersey Department of Environmental Protection (NJDEP) undertook an environmental investigation to identify and implement remedial action at the site. NJDEP’s investigation revealed that landfill waste had been disposed on ACE’s right-of-way and NJDEP determined that ACE was a responsible party as the owner of a facility on which a hazardous substance has been deposited. ACE, EPA and NJDEP entered into a settlement agreement effective on August 11, 2011 to resolve ACE’s alleged liability. Under the settlement agreement, ACE made a payment of approximately $1 million (the amount accrued by ACE in 2010) to the EPA Hazardous Substance Superfund, and donated a four-acre parcel of land adjacent to the site to NJDEP.

Indian River Oil Release

In 2001, DPL entered into a consent agreement 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 resulting from an oil release at the Indian River generating facility, which was sold in June 2001. The amount of remediation costs accrued for this matter is included in the table above under the column entitled Legacy Generation—Regulated.

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.

The release falls within the regulatory jurisdiction of multiple federal and state agencies. Beginning in March 2011, DDOE issued a series of compliance directives that require Pepco to prepare an incident report, provide certain records, and prepare and implement plans for sampling surface water and river sediments and assessing ecological risks and natural resources damages. Pepco has submitted an incident report and is providing the requested records. In December 2011, Pepco completed field sampling and anticipates submitting a report to DDOE during the second quarter of 2012.

On March 16, 2011, the Virginia Department of Environmental Quality (VADEQ) requested documentation regarding the release and the preparation of an emergency response report, which Pepco submitted to the agency on April 20, 2011. On March 25, 2011, Pepco received a notice of violation from VADEQ and in December 2011, VADEQ executed a consent agreement that had been executed by Pepco in August, pursuant to which Pepco paid a civil penalty of approximately $40,000.

During March 2011, EPA conducted an inspection of the Potomac River substation to review compliance with federal regulations regarding Spill Prevention, Control, and Countermeasure (SPCC) plans for facilities using oil-containing equipment in proximity to surface waters. As a result, EPA identified several potential violations of the SPCC regulations relating to SPCC plan content, recordkeeping, and secondary containment, which EPA advised may lead to an EPA demand for noncompliance penalties. As a result of the oil release, Pepco submitted a revised SPCC plan to EPA in August 2011 and implemented certain interim operational changes to the secondary containment systems at the facility which involve pumping accumulated storm water to an aboveground holding tank for off-site disposal. In December 2011, Pepco completed the installation of a treatment system designed to allow automatic discharge of accumulated

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storm water from the secondary containment system. Pepco is currently seeking DDOE’s approval to commence operation of the new system and, after receiving such approval, will submit a further revised SPCC plan to EPA. In the meantime, Pepco will continue to use the above ground holding tank to manage storm water from the secondary containment system.

The U.S. Coast Guard assessed a $5,000 penalty against Pepco for the release of oil into the waters of the United States, which Pepco has paid.

In addition to the cost to remediate impacts to the river and shoreline, Pepco also may be liable for non-compliance penalties and/or natural resource damages in addition to those it has already paid. It is not possible to accurately estimate an amount or range of reasonably possible loss to which it may be exposed associated with this liability at this time; however, based on current information, PHI and Pepco do not believe this matter will have a material adverse effect on their respective financial conditions, results of operations or cash flows.

The amounts accrued for these matters are included in the table above under the column entitled Transmission and Distribution.

Fauquier County Landfill Site

On October 7, 2011, Pepco Energy Services received a notice of violation dated October 5, 2011, from the VADEQ, which advised Pepco Energy Services of information on which VADEQ may rely to institute an administrative or judicial enforcement action in connection with alleged violation of Virginia air pollution control law and regulations at the facility of Pepco Energy Services’ subsidiary Fauquier County Landfill Gas, L.L.C. in Warrenton, Virginia. The notice of violation is based on an on-site VADEQ inspection during which VADEQ observed certain alleged deficiencies relating to the facility’s permit to construct and operate. On February 6, 2012, VADEQ sent Pepco Energy Services a proposed consent order pursuant to which Pepco Energy Services would agree to perform certain remedial actions and agree to pay a civil charge of approximately $10,000. Pepco Energy Services is presently reviewing the proposed consent order.

PHI’s Cross-Border Energy Lease Investments

Between 1994 and 2002, PCI entered into eight cross-border energy lease investments involving public utility assets (primarily consisting of hydroelectric generation and coal-fired electric generation facilities and natural gas distribution networks) located outside of the United States. Each of these investments is comprised of multiple leases and each investment is structured as a sale and leaseback transaction commonly referred to by the IRS as a sale-in, lease-out, or SILO transaction.

As more fully discussed in Note (8), “Leasing Activities,” PHI entered into early termination agreements with two lessees, at their request, with respect to all of the leases comprising one cross-border energy lease investment and a small portion of the leases comprising another cross-border energy lease investment in the second quarter of 2011. PHI received net cash proceeds of $161 million (net of a termination payment of $423 million used to retire the non-recourse debt associated with the terminated leases) and recorded a pre-tax gain of $39 million, representing the excess of the net cash proceeds over the carrying value of the lease investments. In the future, PHI anticipates that it will receive annual tax benefits from these lease investments of approximately $51 million. As of December 31, 2011, the book value of PHI’s investment in its cross-border energy lease investments was approximately $1.3 billion. After taking into consideration the $74 million paid with the 2001-2002 audit (as discussed below), the net federal and state tax benefits received for the remaining leases from January 1, 2001, the earliest year that remains open to audit, to December 31, 2011, has been approximately $510 million.

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Since 2005, PHI’s 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 and 2003-2005 income tax returns, respectively, the IRS disallowed the depreciation and interest deductions in excess of rental income claimed by PHI with respect to each of its cross-border energy lease investments. In addition, the IRS has sought to recharacterize each of the leases as a loan transaction as to which PHI would be subject to original issue discount income. PHI disagrees with the IRS’ proposed adjustments and in August 2006 and May 2009 filed protests of these findings with the Office of Appeals of the IRS. Effective November 2010, PHI entered into a settlement agreement with the IRS for the 2001 and 2002 tax years 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 claim for refund was 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. Absent a settlement, any litigation against the IRS may take several years to resolve. The 2003-2005 income tax return review continues to be in process with the IRS Office of Appeals and at present, will not be a part of any U.S. Court of Federal Claims litigation discussed above.

In the event that the IRS were to be successful in disallowing 100% of the tax benefits associated with these leases and recharacterizing these leases as loans, PHI estimates that, as of December 31, 2011, it would be obligated to pay approximately $643 million in additional federal and state taxes and $121 million of interest on the remaining leases. The $643 million in additional federal and state taxes is net of the $74 million tax payment made in January 2011. In addition, the IRS could require PHI to pay a penalty of up to 20% on the amount of additional taxes due.

PHI anticipates that any additional taxes that it would be required to pay as a result of the disallowance of prior deductions or a re-characterization of the leases as loans would be recoverable in the form of lower taxes over the remaining terms of the affected leases. Moreover, the entire amount of any additional federal and state tax would not be due immediately, but rather, the federal and state taxes would be payable when the open audit years are closed and PHI amends subsequent tax returns not then under audit. To mitigate the taxes due in the event of a total disallowance of tax benefits, PHI could elect to liquidate all or a portion of its seven remaining cross-border energy lease investments, which PHI estimates could be accomplished over a period of six months to one year. Based on current market values, PHI estimates that liquidation of the remaining portfolio would generate sufficient cash proceeds to cover the estimated $764 million in federal and state taxes and interest due as of December 31, 2011, in the event of a total disallowance of tax benefits and a recharacterization of the leases as loans. If payments of additional taxes and interest preceded the receipt of liquidation proceeds, the payments would be funded by currently available sources of liquidity.

To the extent that PHI does not prevail in this matter and suffers a disallowance of the tax benefits and incurs imputed original issue discount income, PHI would be required under FASB guidance on leases (ASC 840) to recalculate the timing of the tax benefits generated by the cross-border energy lease investments and adjust the equity value of the investments, which would result in a non-cash charge to earnings.

District of Columbia Tax Legislation

On June 14, 2011, the Council of the District of Columbia approved the Budget Support Act. The Budget Support Act includes a provision requiring that corporate taxpayers in the District of Columbia calculate taxable income allocable or apportioned to the District of Columbia by reference to the income and apportionment factors applicable to commonly controlled entities organized within the United States that are engaged in a unitary business. This new reporting method was enacted on September 14, 2011 and is effective for tax years beginning on or after December 31, 2010. In the aggregate, this new tax reporting method negatively affected pre-tax earnings by $7 million ($5 million after-tax), which is reflected in PHI’s consolidated results of operations, as

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further discussed in Note (8), “Leasing Activities,” and Note (12), “Income Taxes.” The District of Columbia Office of Tax and Revenue issued proposed regulations on January 20, 2012, to implement this reporting method. PHI will continue to analyze these regulations and will record the impact, if any, of such regulations on PHI’s results of operations in the period in which the proposed regulations are adopted as final regulations.

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, 2011, PHI and its subsidiaries were parties to a variety of agreements pursuant to which they were guarantors for standby letters of credit, energy procurement obligations, and other commitments and obligations. The commitments and obligations, in millions of dollars, were as follows:

	Guarantor
	PHI		Pepco		DPL		ACE		Total
Energy procurement obligations of Pepco Energy Services (a)	$	175	$	—	$	—	$	—	$	175
Guarantees associated with disposal of Conectiv Energy assets (b)		23		—		—		—		23
Guaranteed lease residual values (c)		1		3		5		3		12
Total	$	199	$	3	$	5	$	3	$	210

(a) PHI has contractual commitments for performance and related payments of Pepco Energy Services to counterparties under routine energy sales and procurement obligations.

(b) Represents guarantees by PHI in connection with transfers of Conectiv Energy’s tolling agreements and derivatives portfolio. The tolling agreement guarantees cover the payment by the entity to which the tolling agreement was assigned. The guaranteed amounts on the transferred tolling agreements totaled $10 million at December 31, 2011, which decline until the termination of the guarantees. The derivative portfolio guarantee is currently $13 million and covers Conectiv Energy’s performance prior to the assignment. This guarantee will remain in effect until the end of 2015.

(c) Subsidiaries of PHI have guaranteed residual values that could be in excess of fair value of certain equipment and fleet vehicles held through lease agreements. As of December 31, 2011, obligations under the guarantees were approximately $12 million. Assets leased under agreements subject to residual value guarantees are typically for periods ranging from 2 years to 10 years. Historically, payments under the guarantees have not been made by the guarantor as, under normal conditions, the contract runs to full term at which time the residual value is immaterial. As such, 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 Savings Performance Contracts

Pepco Energy Services has a diverse portfolio of energy savings performance contracts that are associated with the installation of energy savings equipment for federal, state and local government customers. As part of those contracts, Pepco Energy Services typically guarantees that the equipment or systems installed by Pepco Energy Services will generate a specified amount of energy savings on an annual basis over a multi-year period. As of December 31, 2011, Pepco Energy Services’ energy savings guarantees on both completed projects and projects under construction totaled $435 million over the life of the performance contracts with the longest remaining term being 15 years. On an annual basis, Pepco Energy Services

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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. Pepco Energy Services recognizes a liability for the value of the estimated energy savings shortfall when it is probable that the guaranteed energy savings will not be achieved and the amount is reasonably estimable. As of December 31, 2011, Pepco Energy Services did not have an accrued liability for energy savings performance contracts. There was no significant change in the type of contracts issued for the year ended December 31, 2011. Based on its historical experience, Pepco Energy Services believes the probability of incurring a material loss under its energy savings performance contracts is remote.

Dividends

On January 26, 2012, Pepco Holdings’ Board of Directors declared a dividend on common stock of 27 cents per share payable March 30, 2012, to shareholders of record on March 12, 2012.

Contractual Obligations

As of December 31, 2011, Pepco Holdings’ contractual obligations under non-derivative fuel and purchase power contracts were $553 million in 2012, $716 million in 2013 to 2014, $708 million in 2015 to 2016, and $2,125 million in 2017 and thereafter.

(18) ACCUMULATED OTHER COMPREHENSIVE LOSS

A detail of the components of Pepco Holdings’ AOCL relating to continuing operations is as follows. For additional information, see the consolidated statements of comprehensive income.

	Commodity Derivatives			Treasury Lock			Other			Accumulated Other Comprehensive Loss
	(millions of dollars)
Balance, December 31, 2008	$	(120	)	$	(25	)	$	(10	)	$	(155	)
Current year change		21			3			(7	)		17
Balance, December 31, 2009		(99	)		(22	)		(17	)		(138	)
Current year change		21			11			—			32
Balance, December 31, 2010		(78	)		(11	)		(17	)		(106	)
Current year change		49			1			(7	)		43
Balance, December 31, 2011	$	(29	)	$	(10	)	$	(24	)	$	(63	)

A detail of the income tax expense (benefit) allocated to the components of Pepco Holdings’ AOCL relating to continuing operations for each year is as follows.

For the Year Ended:	Commodity Derivatives		Treasury Lock			Other			Accumulated Other Comprehensive Loss
	(millions of dollars)
December 31, 2009	$	15		$	2	$	(5	)	$	12
December 31, 2010	$	14		$	7	$	—		$	21
December 31, 2011	$	32		$	—	$	(4	)	$	28

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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, differences between summer and winter rates, and the scheduled downtime and maintenance of electric generating units. 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 common shares outstanding during the year.

	2011
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(millions, except per share amounts)
Total Operating Revenue	$	1,634		$	1,409		$	1,643		$	1,234		$	5,920
Total Operating Expenses		1,485			1,207	(a)		1,448			1,143			5,283
Operating Income		149			202			195			91			637
Other Expenses		(53	)		(53	)		(60	)		(62	)		(228	)
Income From Continuing Operations Before Income Tax Expense		96			149			135			29			409
Income Tax Expense Related to Continuing Operations (b)		34			54			55			6			149
Net Income From Continuing Operations		62			95	(a)		80			23			260
Income (Loss) From Discontinued Operations, net of taxes		2			(1	)		—			(4	)		(3	)
Net Income	$	64		$	94		$	80		$	19		$	257
Basic and Diluted Earnings Per Share of Common Stock
Earnings Per Share of Common Stock from Continuing Operations		0.27			0.42			0.35			0.10			1.15
Earnings (Loss) Per Share of Common Stock from Discontinued Operations		0.01			—			—			(0.02	)		(0.01	)
Basic and Diluted Earnings Per Share of Common Stock		0.28			0.42			0.35			0.08			1.14
Cash Dividends Per Common Share		0.27			0.27			0.27			0.27			1.08

(a) Includes $39 million pre-tax ($3 million after-tax) gain from the early termination of cross-border energy leases held in trust.

(b) Includes tax benefits of $14 million in the second quarter primarily associated with an interest benefit related to federal tax liabilities and a $22 million reversal of previously recognized tax benefits in the second quarter associated with the early termination of cross-border energy leases held in trust.

	2010
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(millions, except per share amounts)
Total Operating Revenue	$	1,819		$	1,636		$	2,067		$	1,517		$	7,039
Total Operating Expenses (a) (b)		1,688			1,443			1,855			1,429			6,415
Operating Income		131			193			212			88			624
Other Expenses (c)		(78	)		(84	)		(197	)		(115	)		(474	)
Income (Loss) From Continuing Operations Before Income Tax Expense		53			109			15			(27	)		150
Income Tax Expense (Benefit) Related to Continuing Operations		25	(d)		33	(e)		(6	)(f)		(41	)(f)		11
Net Income From Continuing Operations		28			76			21			14			139
Income (Loss) From Discontinued Operations, net of taxes		8			(130	)		(4	)		19			(107	)
Net Income (Loss)	$	36		$	(54	)	$	17		$	33		$	32
Basic and Diluted Earnings Per Share of Common Stock
Earnings Per Share of Common Stock from Continuing Operations		0.13			0.34			0.09			0.06			0.62
Earnings (Loss) Per Share of Common Stock from Discontinued Operations		0.03			(0.58	)		(0.01	)		0.08			(0.48	)
Basic and Diluted Earnings (Loss) Per Share of Common Stock		0.16			(0.24	)		0.08			0.14			0.14
Cash Dividends Per Common Share		0.27			0.27			0.27			0.27			1.08

(a) Includes restructuring charges of $14 million and $16 million in the third and fourth quarters, respectively.

(b) Includes expenses of $2 million and $9 million in the second and third quarters, respectively, related to the effects of Pepco divestiture-related claims.

(c) Includes debt extinguishment costs of $135 million and $54 million in the third and fourth quarters, respectively.

(d) Includes an $8 million reversal of accrued interest income on uncertain and effectively settled state tax positions and a $4 million reversal of deferred tax assets related to the Medicare Part D subsidy, partially offset by state income tax benefits of $8 million resulting from the planned restructuring of certain PHI subsidiaries.

(e) Includes state income tax benefits of $8 million resulting from the restructuring of certain PHI subsidiaries.

(f) Includes state income tax benefits of $13 million and $4 million in the third and fourth quarters, respectively, associated with the loss on extinguishment of debt and a $18 million Federal tax benefit in the fourth quarter related primarily to reversals of previously accrued interest on uncertain and effectively settled tax positions due to the final settlement with the IRS of the 1996-2002 tax years.

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(20) DISCONTINUED OPERATIONS

In April 2010, the Board of Directors approved a plan for the disposition of PHI’s competitive wholesale power generation, marketing and supply business, which has been conducted through subsidiaries of Conectiv Energy Holding Company (collectively Conectiv Energy). On July 1, 2010, PHI completed the sale of Conectiv Energy’s wholesale power generation business to Calpine Corporation (Calpine). The disposition of all of Conectiv Energy’s remaining assets and businesses, consisting of its load service supply contracts, energy hedging portfolio, certain tolling agreements and other assets not included in the Calpine sale, is substantially complete.

PHI is reporting the results of operations of the former Conectiv Energy segment in discontinued operations in all periods presented in the accompanying consolidated statements of income. Further, the assets and liabilities of Conectiv Energy, excluding the related current and deferred income tax accounts and certain retained liabilities, are reported as held for sale as of each date presented in the accompanying consolidated balance sheets.

The remaining net assets of Conectiv Energy are zero at December 31, 2011. Net assets at December 31, 2010 of $45 million included accounts receivable of $81 million, inventory of $20 million, net derivative liabilities of $18 million and other miscellaneous receivables and payables. At December 31, 2011, there were no derivative assets and liabilities or financial assets and liabilities that would be accounted for at fair value on a recurring basis. At December 31, 2010, Conectiv Energy had $7 million of financial assets (with $4 million and $3 million categorized within levels 2 and 3 of the fair value hierarchy, respectively) and $90 million of financial liabilities accounted for at fair value on a recurring basis (with $10 million and $80 million categorized within levels 1 and 2 of the fair value hierarchy, respectively).

Operating Results

The operating results of Conectiv Energy for the years ended December 31, 2011, 2010 and 2009 are as follows:

	2011			2010			2009
	(millions of dollars)
(Loss) income from operations of discontinued operations, net of income taxes	$	(1	)	$	6		$	12
Net losses from dispositions of assets and businesses of discontinued operations, net of income taxes		(2	)		(113	)		—
(Loss) income from discontinued operations, net of income taxes	$	(3	)	$	(107	)	$	12

(Loss) income from operations of discontinued operations, net of income taxes, for the year ended December 31, 2011, includes adjustments of $4 million to certain remaining miscellaneous assets and liabilities and certain accrued expenses for obligations associated with the sale of the wholesale power generation business to Calpine to reflect the actual amounts paid to Calpine during 2011.

Net losses from dispositions of assets and businesses of discontinued operations, net of income taxes for the year ended December 31, 2011 includes an after-tax loss associated with state income taxes payable on the sale of the wholesale power generation business and after-tax income of $1 million related to the sale of a tolling agreement in May 2011, which is offset by an expense of approximately $1 million (after-tax) which was incurred in connection with a financial transaction entered into with a third party on January 6, 2011, under which Conectiv Energy transferred to the third party its remaining portfolio of derivatives, including financially settled natural gas and electric power transactions, for all remaining periods from February 1, 2011 forward. In connection with the closing of the transaction, Conectiv Energy paid the third party $82 million, primarily representing the fair value of the derivatives at February 1, 2011, and an after-tax administrative fee of $1 million. Substantially all of the mark-to-market gains and losses associated with these derivatives were recorded in earnings through December 31, 2010 and accordingly no additional material gain or loss was recognized as a result of this transaction in 2011.

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(Loss) income from operations of discontinued operations for the year ended December 31, 2010, net of income taxes, also includes after-tax expenses for employee severance and retention benefits of $9 million and after-tax accrued expenses for certain obligations associated with the sale of the wholesale power generation business to Calpine of $12 million.

Net losses from dispositions of assets and businesses of discontinued operations, net of income taxes, for the year ended December 31, 2010, includes (i) the after-tax loss on the sale of the wholesale power generation business to Calpine of $74 million, (ii) after-tax net losses on sales of assets and businesses not sold to Calpine of $13 million (inclusive of the recognition of after-tax unrealized losses on derivative contracts considered no longer probable to occur of $50 million recorded in the second quarter of 2010), and (iii) tax charges aggregating $26 million for the establishment of valuation allowances against certain deferred tax assets primarily associated with state net operating losses, the remeasurement of deferred taxes for expected changes in state income tax apportionment factors, and the write-off of certain tax credit carryforwards no longer expected to be realized.

Derivative Instruments and Hedging Activities

Conectiv Energy historically used derivative instruments primarily to reduce its financial exposure to changes in the value of its assets and obligations due to commodity price fluctuations. The derivative instruments used included forward contracts, futures, swaps, and exchange-traded and over-the-counter options. The two primary risk management objectives were: (i) to manage the spread between the cost of fuel used to operate electric generation facilities and the revenue received from the sale of the power produced by those facilities, and (ii) to manage the spread between wholesale sale commitments and the cost of supply used to service those commitments to ensure stable cash flows and lock in favorable prices and margins when they became available.

As of December 31, 2011, Conectiv Energy had disposed of all energy commodity contracts and all cash collateral associated with these contracts had been returned.

Through June 30, 2010, Conectiv Energy purchased energy commodity contracts in the form of futures, swaps, options and forward contracts to hedge price risk in connection with the purchase of physical natural gas, oil and coal to fuel its generation assets for sale to customers. Conectiv Energy also purchased energy commodity contracts in the form of electricity swaps, options and forward contracts to hedge price risk in connection with the purchase of electricity for distribution to requirements-load customers. Conectiv Energy accounted for most of its futures, swaps and certain forward contracts as cash flow hedges of forecasted transactions, and accordingly, the effective portion of the gains or losses on these derivatives were reflected as a component of AOCL and were reclassified into income in the same period or periods during which the hedged transactions occurred. Gains and losses on the derivatives representing hedge ineffectiveness, the forecasted hedged transaction being deemed probable not to occur, or hedge components excluded from the assessment of effectiveness were recognized in current income.

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The amounts of pre-tax loss on commodity derivatives included in other comprehensive loss for Conectiv Energy for the years ended December 31, 2011, 2010 and 2009 are provided in the table below:

	2011		2010			2009
Amount of net pre-tax loss arising during the period included in accumulated other comprehensive loss	$	—	$	(73	)	$	(216	)
Amount of net pre-tax loss reclassified into income:
Effective portion:
Loss from discontinued operations, net of income taxes		—		(164	)		(224	)
Ineffective portion:
Loss from discontinued operations, net of income taxes (a)		—		(82	)		—
Total net pre-tax loss reclassified into income		—		(246	)		(224	)
Net pre-tax gain on commodity derivatives included in accumulated other comprehensive loss comprehensive loss	$	—	$	173		$	8

(a) For the years ended December 31, 2010 and 2009, amounts of $86 million and $3 million, respectively, were reclassified from AOCL to income because the forecasted transactions were deemed probable not to occur.

To the extent that Conectiv Energy held certain derivatives that did not qualify as hedges, these derivatives were recorded at fair value on the balance sheet with changes in fair value recognized in income. The amounts of realized and unrealized derivative gains (losses) for Conectiv Energy included in (Loss) income from discontinued operations, net of income taxes, for the years ended December 31, 2011, 2010 and 2009 are provided in the table below:

	2011		2010			2009
Realized mark-to-market gains	$	—	$	26		$	47
Unrealized mark-to-market losses		—		(16	)		(57	)
Total net mark-to-market gains (losses)	$	—	$	10		$	(10	)

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(21) RESTRUCTURING CHARGE

With the ongoing wind-down of the retail energy supply business of Pepco Energy Services and the disposition of Conectiv Energy, PHI repositioned itself as a regulated transmission and distribution company during 2010. In connection with this repositioning, PHI completed a comprehensive organizational review in 2010 that identified opportunities to streamline the organization and to achieve certain reductions in corporate overhead costs that are allocated to its operating segments, which resulted in the adoption of a restructuring plan. PHI began implementation of the plan during 2010, identifying 164 employee positions that were eliminated. The plan also includes additional cost reduction opportunities that are being implemented through process improvements and operational efficiencies.

In connection with the restructuring plan, PHI recorded a pre-tax restructuring charge related to severance, pension, and health and welfare benefits for employee terminations of $30 million in 2010. The severance, pension, and health and welfare benefits were estimated based on the years of service and compensation levels of the employees associated with the 164 eliminated positions. The restructuring charge was allocated to PHI’s operating segments and was reflected as a separate line item in the consolidated statement of income for the year ended December 31, 2010.

A reconciliation of PHI’s accrued restructuring charges for the year ended December 31, 2011 is as follows:

	Year Ended December 31, 2011
	(millions of dollars)
	Power Delivery			Corporate and Other			PHI Consolidated
Beginning balance as of January 1, 2011	$	28		$	1		$	29
Restructuring charge		—			—			—
Cash payments		(23	)		(1	)		(24	)
Ending balance as of December 31, 2011	$	5		$	—		$	5

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Management’s Report on Internal Control over Financial Reporting

The management of 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, 2011 based on the framework in Internal Control – Integrated Framework 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, 2011.

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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, 2011 and December 31, 2010, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2011 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 23, 2012

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POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF INCOME

For the Year Ended December 31,	2011			2010			2009
	(millions of dollars)
Operating Revenue	$	2,078		$	2,288		$	2,231
Operating Expenses
Purchased energy		893			1,152			1,223
Other operation and maintenance		420			354			328
Restructuring charge		—			15			—
Depreciation and amortization		171			162			145
Other taxes		382			364			302
Effects of divestiture-related claims		—			11			(40	)
Total Operating Expenses		1,866			2,058			1,958
Operating Income		212			230			273
Other Income (Expenses)
Interest and dividend income		—			1			1
Interest expense		(94	)		(98	)		(100	)
Other income		17			12			9
Other expenses		—			—			(1	)
Total Other Expenses		(77	)		(85	)		(91	)
Income Before Income Tax Expense		135			145			182
Income Tax Expense		36			37			76
Net Income	$	99		$	108		$	106

The accompanying Notes are an integral part of these Financial Statements.

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POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

	December 31, 2011			December 31, 2010
	(millions of dollars)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	12		$	88
Accounts receivable, less allowance for uncollectible accounts of $18 million and $20 million, respectively		339			373
Inventories		50			44
Prepayments of income taxes		7			95
Income taxes receivable		31			37
Prepaid expenses and other		32			34
Total Current Assets		471			671
INVESTMENTS AND OTHER ASSETS
Regulatory assets		299			191
Prepaid pension expense		289			274
Investment in trust		31			25
Income taxes receivable		24			34
Other		55			57
Total Investments and Other Assets		698			581
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		6,578			6,185
Accumulated depreciation		(2,704	)		(2,609	)
Net Property, Plant and Equipment		3,874			3,576
TOTAL ASSETS	$	5,043		$	4,828

The accompanying Notes are an integral part of these Financial Statements.

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POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

	December 31, 2011		December 31, 2010
	(millions of dollars, except shares)
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Short-term debt	$	74	$	—
Accounts payable and accrued liabilities		209		194
Accounts payable due to associated companies		57		75
Capital lease obligations due within one year		8		8
Taxes accrued		63		62
Interest accrued		17		18
Other		110		119
Total Current Liabilities		538		476
DEFERRED CREDITS
Regulatory liabilities		169		147
Deferred income taxes, net		1,039		958
Investment tax credits		5		7
Other postretirement benefit obligations		66		67
Income taxes payable		—		3
Liabilities and accrued interest related to uncertain tax positions		38		52
Other		68		64
Total Deferred Credits		1,385		1,298
LONG-TERM LIABILITIES
Long-term debt		1,540		1,540
Capital lease obligations		78		86
Total Long-Term Liabilities		1,618		1,626
COMMITMENTS AND CONTINGENCIES (NOTE 13)
EQUITY
Common stock, $.01 par value, 200,000,000 shares authorized, 100 shares outstanding		—		—
Premium on stock and other capital contributions		705		705
Retained earnings		797		723
Total Equity		1,502		1,428
TOTAL LIABILITIES AND EQUITY	$	5,043	$	4,828

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,	2011			2010			2009
	(millions of dollars)
OPERATING ACTIVITIES
Net Income	$	99		$	108		$	106
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		171			162			145
Effects of divestiture-related claims		—			11			(40	)
Changes in restricted cash equivalents related to Mirant settlement		—			—			102
Deferred income taxes		73			74			122
Investment tax credit amortization		(2	)		(2	)		(2	)
Changes in:
Accounts receivable		33			(15	)		23
Inventories		(6	)		(1	)		2
Prepaid expenses		1			3			(9	)
Regulatory assets and liabilities, net		(43	)		(34	)		(66	)
Accounts payable and accrued liabilities		(27	)		15			4
Pension contributions		(40	)		—			(170	)
Prepaid pension expense, excluding contributions		24			22			17
Taxes accrued		73			6			77
Interest accrued		(1	)		(1	)		(1	)
Other assets and liabilities		2			11			21
Net Cash From Operating Activities		357			359			331
INVESTING ACTIVITIES
Investment in property, plant and equipment		(521	)		(359	)		(288	)
Department of Energy capital reimbursement awards received		48			11			—
Changes in restricted cash equivalents		—			1			(1	)
Net other investing activities		(7	)		3			(1	)
Net Cash Used By Investing Activities		(480	)		(344	)		(290	)
FINANCING ACTIVITIES
Dividends paid to Parent		(25	)		(115	)		—
Capital contribution from Parent		—			—			94
Issuances of long-term debt		—			—			110
Reacquisitions of long-term debt		—			(16	)		(50	)
Issuances (Repayments) of short-term debt, net		74			—			(125	)
Net other financing activities		(2	)		(9	)		(3	)
Net Cash From (Used by) Financing Activities		47			(140	)		26
Net (Decrease) Increase in Cash and Cash Equivalents		(76	)		(125	)		67
Cash and Cash Equivalents at Beginning of Year		88			213			146
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	12		$	88		$	213
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for interest (net of capitalized interest of $8 million, $4 million and $4 million, respectively)	$	91		$	94		$	97
Cash received for income taxes		(108	)		(20	)		(126	)

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, DECEMBER 31, 2008		100	$	—	$	611	$	624		$	1,235
Net Income		—		—		—		106			106
Capital contribution from Parent		—		—		94		—			94
BALANCE, DECEMBER 31, 2009		100		—		705		730			1,435
Net Income		—		—		—		108			108
Dividends on common stock		—		—		—		(115	)		(115	)
BALANCE, DECEMBER 31, 2010		100		—		705		723			1,428
Net Income		—		—		—		99			99
Dividends on common stock		—		—		—		(25	)		(25	)
BALANCE, DECEMBER 31, 2011		100	$	—	$	705	$	797		$	1,502

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).

(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 evaluations, pension and other postretirement benefits assumptions, unbilled revenue calculations, the assessment of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of restructuring charges, recognition of changes in network service transmission rates for prior service year costs, accrual of self-insurance reserves for general and auto 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.

Storm Costs

During 2011, Pepco incurred significant costs associated with Hurricane Irene that affected its service territory. Total incremental storm costs associated with Hurricane Irene were $18 million, with $12 million incurred for repair work and $6 million incurred as capital expenditures. Costs incurred for repair work of $10 million were deferred as a regulatory asset to reflect the probable recovery of these storm costs in Pepco’s jurisdictions, and the remaining $2 million was charged to Other operation and maintenance expense. Pepco is seeking recovery of the incremental Hurricane Irene costs in each of its jurisdictions in pending or planned distribution rate case filings.

Restructuring Charge

PHI commenced a comprehensive organizational review in the second quarter of 2010 to identify opportunities to streamline the organization and to achieve certain reductions in corporate overhead costs allocated to its operating segments. The restructuring plan resulted in the elimination of 164 employee positions. Pepco’s accrual of $15 million in costs associated with termination benefits was based on estimated severance costs and actuarial calculations of the present value of certain changes in pension and other postretirement benefits for terminated employees. There were no material changes to this accrual in 2011.

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Network Service Transmission Rates

In May of each year, Pepco provides its updated network service transmission rate to the Federal Energy Regulatory Commission (FERC) effective for the service year beginning June 1 of the current year and ending May 31 of the following year. The network service transmission rate includes a true-up for costs incurred in the prior service year that had not yet been reflected in rates charged to customers.

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 $82 million and $95 million as of December 31, 2011 and 2010, 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 its 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. Excise tax related generally to the consumption of gasoline by Pepco in the normal course of business is charged to operations, maintenance or construction, and is not material.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in Pepco’s gross revenues were $350 million, $333 million and $254 million for the years ended December 31, 2011, 2010 and 2009, 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 an asset is being used or its physical condition. A long-lived asset to be held and used is written down to 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 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 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 and the restricted cash equivalents included in Investments and 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

Pepco’s accounts receivable balance primarily consists of customer accounts receivable, 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).

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PEPCO

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. Although management 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 inventory 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 Maryland Public Service Commission (MPSC) and the District of Columbia Public Service Commission (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. 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 mechanism (BSA) for retail customers. Effective November 2009, the DCPSC approved a BSA for retail customers. See Note (6), “Regulatory Matters – Regulatory Proceedings.” 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.

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PEPCO

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 are 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 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. Accumulated depreciation is charged with the cost of depreciable property retired, less salvage and other recoveries. Property, plant and equipment other than electric facilities is generally depreciated on a straight-line basis over the useful lives of the assets. The system-wide composite depreciation rates for 2011, 2010 and 2009 for Pepco’s transmission and distribution system property were approximately 2.6%, 2.6% and 2.7%, respectively.

In 2010, Pepco received an award from the U.S. Department of Energy under the American Recovery and Reinvestment Act of 2009. Pepco was awarded $149 million to fund a portion of the costs incurred for the implementation of an advanced metering infrastructure system, direct load control, distribution automation and communications infrastructure in its Maryland and District of Columbia service territories. Pepco has elected to recognize the awards as a reduction in the carrying value of the assets acquired rather than grant income over the service period.

Capitalized Interest and Allowance for Funds Used During Construction

In accordance with FASB guidance on regulated operations (ASC 980), utilities can 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 $8 million, $4 million and $4 million for the years ended December 31, 2011, 2010 and 2009, respectively.

Pepco recorded amounts for the equity component of AFUDC of $12 million, $6 million and $3 million for the years ended December 31, 2011, 2010 and 2009, 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.

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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 issues. 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, asset removal costs are recorded as regulatory liabilities. At December 31, 2011 and 2010, $144 million and $122 million of asset removal costs, respectively, are included in Regulatory liabilities in the accompanying balance sheets.

Pension and Postretirement Benefit Plans

Pepco Holdings sponsors the PHI Retirement Plan, a non-contributory, defined benefit pension plan that covers substantially all employees of Pepco and certain employees of other Pepco Holdings subsidiaries. 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 $797 million and $723 million of retained earnings available for payment of common stock dividends at December 31, 2011 and 2010, respectively. These amounts represent the total retained earnings balances at those dates.

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Reclassifications and Adjustments

Certain prior period amounts have been reclassified in order to conform to current period presentation. The following adjustments have been recorded and are not considered material individually or in the aggregate:

Income Tax Adjustments

During 2011, Pepco recorded an adjustment to correct certain income tax errors related to prior periods associated with the interest on uncertain tax positions. The adjustment resulted in an increase in income tax expense of $1 million.

Operating Expense

In 2010, Pepco recorded an adjustment to correct certain errors related to other taxes which resulted in a decrease to Other taxes expense of $5 million (pre-tax).

(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Fair Value Measurements and Disclosures (ASC 820)

The FASB issued new disclosure requirements that require significant items within the reconciliation of the Level 3 valuation category to be presented in separate categories for purchases, sales, issuances and settlements. The guidance was effective beginning with Pepco’s March 31, 2011 financial statements. Pepco has included the new disclosure requirements in Note (12), “Fair Value Disclosures,” to its financial statements.

Compensation Retirement Benefits—Multiemployer Plans (ASC 715-80)

In September 2011, the FASB issued new disclosure requirements for participants in multiemployer pension and postretirement benefit plans that would be effective beginning with Pepco’s December 31, 2011 financial statements. Most of these disclosures are not applicable to Pepco because it participates in PHI’s single employer pension plan and accounts for it as participation in a multiemployer plan. The disclosure requirements for Pepco were limited and are already provided in Pepco’s Note (9), “Pension and Other Postretirement Benefits.”

(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Fair Value Measurements and Disclosures (ASC 820)

In May 2011, the FASB issued new guidance on fair value measurement and disclosures that will be effective beginning with Pepco’s March 31, 2012 financial statements. The new guidance will change how fair value is measured in specific instances and expand disclosures about fair value measurements. Pepco expects that it will have to provide additional disclosures, but does not expect this guidance to have a significant impact on its fair value measurements.

(5) SEGMENT INFORMATION

The company 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 Pepco’s regulatory asset and liability balances at December 31, 2011 and 2010 are as follows:

	2011		2010
	(millions of dollars)
Regulatory Assets
Recoverable meter-related costs (a)	$	86	$	15
Deferred income taxes		57		45
Recoverable workers’ compensation and long-term disability costs		34		28
Deferred debt extinguishment costs (a)		30		33
Demand-side management		20		10
Blueprint for the Future		10		5
Deferred energy supply costs		4		8
Other		58		47
Total Regulatory Assets	$	299	$	191
Regulatory Liabilities
Asset removal costs	$	144	$	122
Other		25		25
Total Regulatory Liabilities	$	169	$	147

(a) A return is generally earned on these deferrals.

A description for each category of regulatory assets and regulatory liabilities follows:

Recoverable Meter-Related Costs: Represents costs associated with the installation of smart meters and the early retirement of existing meters throughout Pepco’s service territory as a result of the Advanced Metering Infrastructure project.

Deferred Income Taxes: Represents a receivable from our customers for tax benefits Pepco previously flowed through before the company was ordered to account for 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.

Deferred Debt Extinguishment Costs: Represents the costs of debt extinguishment for which recovery through regulated utility rates is considered probable and, if approved, will be amortized to interest expense during the authorized rate recovery period.

Demand-Side Management: Represents recoverable costs associated with customer energy efficiency programs.

Blueprint for the Future: Includes costs associated with Blueprint for the Future initiatives which include programs to help customers better manage their energy use and to allow each utility to better manage their electrical and natural gas distribution systems.

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 that are probable of recovery in rates.

Other: Represents miscellaneous regulatory assets that generally are being amortized over 1 to 20 years. Also includes the under-recovery of administrative costs associated with Default Electricity Supply in the District of Columbia and Maryland.

Asset Removal Costs: Pepco’s depreciation rates include a component for removal costs, as approved by the relevant federal and state regulatory commissions. As such, Pepco has recorded a regulatory liability for its estimate of the difference between incurred removal costs and the amount of removal costs recovered through depreciation rates.

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Other: Represents miscellaneous regulatory liabilities.

Regulatory Proceedings

District of Columbia Divestiture Case

In June 2000, the DCPSC approved a divestiture settlement under which Pepco is required to share with its District of Columbia customers the net proceeds realized by Pepco from the sale of its generation-related assets in 2000. This approval left unresolved issues of (i) whether Pepco should be required to share with customers the excess deferred income taxes (EDIT) and accumulated deferred investment tax credits (ADITC) associated with the sold assets and, if so, whether such sharing would violate the normalization provisions of the Internal Revenue Code and its implementing regulations and (ii) whether Pepco was entitled to deduct certain costs in determining the amount of proceeds to be shared.

In May 2010, the DCPSC issued an order addressing all of the remaining issues related to the sharing of the proceeds of Pepco’s divestiture of its generating assets. In the order, the DCPSC ruled that Pepco is not required to share EDIT and ADITC with customers. However, the order also disallowed certain items that Pepco had included in the costs deducted from the proceeds of the sale of the generation assets. The disallowance of these costs, together with interest on the disallowed amount, increased the aggregate amount Pepco was required to distribute to customers, pursuant to the sharing formula, by approximately $11 million, which Pepco recognized as an expense in 2010 and refunded the amounts to its customers. In June 2010, Pepco filed an application for reconsideration of the DCPSC’s order. In July 2010, the DCPSC denied Pepco’s application for reconsideration. In September 2010, Pepco filed an appeal of the DCPSC’s decision with the District of Columbia Court of Appeals. On April 12, 2011, the Court of Appeals affirmed the DCPSC order. Pepco determined not to appeal this decision.

Maryland Public Service Commission Reliability Investigation

In August 2010, following major storm events that occurred in July and August 2010, the MPSC initiated a proceeding for the purpose of investigating the reliability of Pepco’s distribution system and the quality of distribution service Pepco provided to its customers. On December 21, 2011, the MPSC issued an order in the proceeding imposing a fine on Pepco of $1 million, which Pepco has paid. In accordance with the order, Pepco filed a detailed work plan for the next five years, which provides a comprehensive description of Pepco’s reliability enhancement plan, its emergency response improvement project, and other communication and service restoration improvements. Pepco is also required to file quarterly updates and a year-end status report with the MPSC providing, among other things, detailed information about its reliability and emergency response improvement objectives; its progress in meeting such objectives, together with an analysis of trends concerning the measured duration and frequency of customer interruptions compared to 2010 baseline data; the amount of spending associated with such objectives; an explanation for any inability to meet such objectives; any proposed changes in funding these improvement projects; any changes to any of these projects; and interim and final results of Pepco’s system inspection program. In addition, Pepco must provide additional detail in these reports about its Estimated Time to Restoration Manager and the Customer Advocate, which personnel have been added by Pepco as part of its emergency response improvement project, and to explore the benefits of damage prediction models. Finally, Pepco was required to consider the comments and suggestions of other interested parties in the reliability proceeding regarding improvements that Pepco might make to its reliability enhancement programs. In these reports, Pepco will be required to demonstrate that its reliability enhancement plan costs were prudently spent and produced a significant improvement in reliability, and if it is unable to do so, the MPSC may deny Pepco reimbursement for future reliability enhancement expenditures or impose additional fines.

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The MPSC also stated in the order that it intends to review in Pepco’s pending electric distribution base rate case the recovery of reliability costs and to disallow incremental costs it determines to be the result of imprudent management. Pepco believes its reliability costs have been prudently incurred and it intends to seek to recover its expenditures in its pending rate case. Furthermore, Pepco believes that its reliability enhancement plan will enable Pepco to meet the MPSC’s requirements.

Rate Proceedings

Over the last several years, Pepco has proposed in its service territories the adoption of a mechanism to decouple retail distribution revenue from the amount of power delivered to retail customers. A BSA has been approved and implemented for electric service in Maryland and in the District of Columbia. The MPSC has issued an order requiring modification of the BSA in Maryland so that revenues lost as a result of major storm outages are not collected if electric service is not restored to the pre-major storm levels within 24 hours of the start of a major storm (as discussed below). Under the BSA, 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.

District of Columbia

On July 8, 2011, Pepco filed an application with the DCPSC to increase its electric distribution base rates by approximately $42 million annually, based on a return on equity (ROE) of 10.75%. In the effort to reduce the shortfall in revenues due to the delay in time or lag between when costs are incurred and when they are reflected in rates (regulatory lag), the filing includes a request for the DCPSC to approve a reliability investment recovery mechanism (RIM), to recover reliability-related capital expenditures incurred between base rate cases. Through the RIM, Pepco would collect in a surcharge the amount of its reliability-related capital expenditures based on its budget for the current year. The budgeted amount would be reconciled with actual capital expenditures on an annual basis and any over-recovery or under-recovery would be reflected in the next year’s surcharge. The work undertaken pursuant to the RIM would be subject to a prudency review by the DCPSC in the next base rate case or at more frequent intervals as determined by the DCPSC. Pepco’s operating and maintenance costs and other capital expenditures would remain subject to recovery through the traditional ratemaking process. A decision by the DCPSC is expected in the second quarter of 2012.

Maryland

Electric Distribution Base Rates

On December 16, 2011, Pepco submitted an application with the MPSC to increase its electric distribution base rates. The filing seeks approval of an annual rate increase of approximately $68.4 million, based on a requested ROE of 10.75%. In the effort to reduce regulatory lag, the filing includes a request for the MPSC to approve a RIM to recover reliability-related capital expenditures incurred between base rate cases. Through the RIM, Pepco would collect in a surcharge the amount of its reliability-related capital expenditures based on its budget for the current year. The budgeted amount would be reconciled with actual capital expenditures on an annual basis and any over-recovery or under-recovery would be reflected in the next year’s surcharge. The work undertaken pursuant to the RIM would be subject to a prudency review by the MPSC in the next base rate case or at more frequent intervals as determined by the MPSC. Pepco’s operating and maintenance costs and other capital expenditures would remain subject to recovery through the traditional ratemaking process. Pepco also has requested MPSC approval of the use of fully forecasted test years in future Pepco rate cases. A decision by the MPSC is expected in July 2012.

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Major Storm Damage Recovery Proceedings

In February 2011, the MPSC initiated proceedings involving Pepco, as well as DPL and unaffiliated utilities in Maryland, for the purpose of reviewing how the BSA operates to recover revenues lost as a result of major storm outages. On January 25, 2012, the MPSC issued an order modifying the BSA to prevent Pepco from collecting lost utility revenue through the BSA if electric service is not restored to the pre-major storm levels within 24 hours of the start of a major storm (defined by the MPSC as a weather-related event during which more than the lesser of 10% or 100,000 of an electric utility’s customers have a sustained outage for more than 24 hours). The period for which the lost utility revenue may not be collected through the BSA commences 24 hours after the start of the major storm and continues until all major storm-related outages are restored. The MPSC stated that waivers permitting collection of BSA revenues would be granted in rare and extraordinary circumstances where a utility can show that an outage was not due to inadequate emphasis on reliability and restoration efforts were reasonable under the circumstances. A similar provision excluding revenues lost as a result of major storm outages from the calculation of future BSA adjustments is already included in the BSA for Pepco in the District of Columbia as approved by the DCPSC. The financial impact of service interruptions due to a major storm as a result of this MPSC order would generally depend on the scope and duration of the outages.

(7) LEASING ACTIVITIES

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. 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, 2011 and 2010 are comprised of the following:

	Original Cost		Accumulated Amortization		Net Book Value
	(millions of dollars)
At December 31, 2011
Transmission	$	76	$	33	$	43
Distribution		76		33		43
Other		3		3		—
Total	$	155	$	69	$	86
At December 31, 2010
Transmission	$	76	$	29	$	47
Distribution		76		29		47
Other		3		3		—
Total	$	155	$	61	$	94

The approximate annual commitments under capital leases are $15 million for each year 2012 through 2016, and $46 million thereafter.

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Rental expense for operating leases was $4 million, $4 million and $3 million for the years ended December 31, 2011, 2010 and 2009, respectively.

Total future minimum operating lease payments for Pepco as of December 31, 2011 are $5 million in 2012, $5 million in 2013, $5 million in 2014, $4 million in 2015, $4 million in 2016, and $16 million thereafter.

(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, 2011
Distribution	$	4,661	$	1,960	$	2,701
Transmission		986		398		588
Construction work in progress		438		—		438
Non-operating and other property		493		346		147
Total	$	6,578	$	2,704	$	3,874
At December 31, 2010
Distribution	$	4,541	$	1,885	$	2,656
Transmission		884		379		505
Construction work in progress		300		—		300
Non-operating and other property		460		345		115
Total	$	6,185	$	2,609	$	3,576

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.

(9) PENSION AND OTHER POSTRETIREMENT BENEFITS

Pepco accounts for its participation in its parent’s single-employer plans, the Pepco Holdings, Inc. Retirement Plan (the PHI Retirement Plan) and the Pepco Holdings, Inc. Welfare Plan for Retirees (the PHI OPEB Plan), as participation in multiemployer plans. For 2011, 2010 and 2009, Pepco was responsible for $43 million, $40 million and $38 million, respectively, of the pension and other postretirement net periodic benefit cost incurred by PHI. On January 31, 2012, Pepco made a discretionary tax-deductible contribution in the amount of $85 million to the PHI Retirement Plan. Pepco made discretionary, tax-deductible contributions of $40 million and $170 million to the PHI Retirement Plan for the years ended December 31, 2011 and 2009, respectively. No contribution was made for the year ended December 31, 2010. In addition, Pepco made contributions of $7 million, $10 million and $8 million, respectively, to the PHI OPEB Plan for the years ended December 31, 2011, 2010 and 2009. At December 31, 2011 and 2010, Pepco’s Prepaid pension expense of $289 million and $274 million, and Other postretirement benefit obligations of $66 million and $67 million, effectively represent assets and benefit obligations resulting from Pepco’s participation in the Pepco Holdings benefit plans.

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(10) DEBT

Long-Term Debt

Long-term debt outstanding as of December 31, 2011 and 2010 is presented below.

Type of Debt	Interest Rate	Maturity		2011		2010
				(millions of dollars)
First Mortgage Bonds	4.95%(a)(b)		2013	$	200	$	200
	4.65%(a)(b)		2014		175		175
	6.20%(a)(b)(c)		2022		110		110
	5.375%(a)		2024		38		38
	5.75%(a)(b)		2034		100		100
	5.40%(a)(b)		2035		175		175
	6.50%(a)(b)(c)		2037		500		500
	7.90%		2038		250		250
Total long-term debt					1,548		1,548
Other long-term debt					1		1
Net unamortized discount					(9)		(9)
Current portion of long-term debt					—		—
Total net long-term debt				$	1,540	$	1,540

(a) Represents a series of first mortgage bonds issued by Pepco (Collateral First Mortgage Bonds) as collateral for an outstanding series of senior notes issued by the company or tax-exempt bonds issued for the benefit of the company. The maturity date, optional and mandatory prepayment provisions, if any, interest rate, and interest payment dates on each series of senior notes or the company’s obligations in respect of the tax-exempt bonds are identical to the terms of the corresponding series of Collateral First Mortgage Bonds. Payments of principal and interest on a series of senior notes or the company’s obligations in respect of the tax-exempt bonds satisfy the corresponding payment obligations on the related series of Collateral First Mortgage Bonds. Because each series of senior notes or the company’s obligations in respect of the tax-exempt bonds and the corresponding series of Collateral First Mortgage Bonds securing that series of senior notes or tax-exempt bonds obligations effectively represents a single financial obligation, the senior notes and the tax-exempt bonds are not separately shown on the table.

(b) Represents a series of Collateral First Mortgage Bonds issued by Pepco that in accordance with its terms will, at such time as there are no First mortgage bonds of Pepco outstanding (other than Collateral First Mortgage Bonds securing payment of senior notes), cease to secure the corresponding series of senior notes and will be cancelled.

(c) Represents a series of Collateral First Mortgage Bonds as to which Pepco has agreed in connection with the issuance of the corresponding series of senior notes that, notwithstanding the terms of the Collateral First Mortgage Bonds described in footnote (b) above, it will not permit the release of the Collateral First Mortgage Bonds as security for the series of senior notes for so long as the senior notes remains outstanding, unless Pepco delivers to the senior note trustee comparable secured obligations to secure the senior notes.

The outstanding First Mortgage Bonds are subject to a lien on substantially all of Pepco’s property, plant and equipment.

The aggregate principal amount of long-term debt outstanding at December 31, 2011, that will mature in each of 2012 through 2016 and thereafter is as follows: zero in 2012, $200 million in 2013, $175 million in 2014, zero in 2015 and 2016 and $1,173 million thereafter.

Pepco’s long-term debt is subject to certain covenants. As of December 31, 2011, Pepco is in compliance with all such covenants.

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.

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A detail of the components of Pepco’s short-term debt at December 31, 2011 and 2010 is as follows:

	2011		2010
	(millions of dollars)
Commercial paper	$	74	$	—
Total	$	74	$	—

Commercial Paper

Pepco has an ongoing commercial paper program of up to $500 million that is backed by its borrowing capacity under PHI’s $1.5 billion credit facility, which is described below under the heading Credit Facility.

Pepco had $74 million of commercial paper outstanding at December 31, 2011 and zero outstanding at December 31, 2010. The weighted average interest rate for commercial paper issued during 2011 was 0.35%, and the weighted average maturity was two days. Pepco did not issue commercial paper during 2010.

Credit Facility

PHI, Pepco, Delmarva Power & Light Company (DPL) and Atlantic City Electric Company (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, 2011, PHI, Pepco, DPL and ACE entered into an amended and restated credit agreement with respect to the facility, which among other changes extended the expiration date of the facility to August 1, 2016.

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 initial credit sublimit for PHI is $750 million 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 one month 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 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

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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 financial covenants under this facility as of December 31, 2011.

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.

At December 31, 2011 and 2010, the amount of cash plus borrowing capacity under the PHI credit facility available to meet the liquidity needs of PHI’s utility subsidiaries was $711 million and $462 million, respectively.

(11) 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,
	2011			2010			2009
	(millions of dollars)
Current Tax Benefit
Federal	$	(19	)	$	(28	)	$	(33	)
State and local		(16	)		(7	)		(11	)
Total Current Tax Benefit		(35	)		(35	)		(44	)
Deferred Tax Expense (Benefit)
Federal		54			52			95
State and local		19			22			27
Investment tax credit amortization		(2	)		(2	)		(2	)
Total Deferred Tax Expense		71			72			120
Total Income Tax Expense	$	36		$	37		$	76

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Reconciliation of Income Tax Expense

	For the Year Ended December 31,
	2011					2010					2009
	(millions of dollars)
Income tax at Federal statutory rate	$	47		35.0	%	$	51		35.0	%	$	64		35.0	%
Increases (decreases) resulting from
Depreciation		(1	)	(0.7	)%		3		2.1	%		5		2.9	%
Asset removal costs		(7	)	(5.0	)%		(3	)	(2.1	)%		(3	)	(1.6	)%
State income taxes, net of federal effect		8		5.5	%		8		5.5	%		10		5.5	%
Software amortization		—		(0.3	)%		(4	)	(2.8	)%		2		1.1	%
Investment tax credits		(2	)	(1.1	)%		(2	)	(1.4	)%		(2	)	(1.1	)%
Change in estimates and interest related to uncertain and effectively settled tax positions		(9	)	(6.6	)%		(11	)	(7.6	)%		4		2.2	%
Other, net		—		(0.1	)%		(5	)	(3.2	)%		(4	)	(2.2	)%
Income Tax Expense	$	36		26.7	%	$	37		25.5	%	$	76		41.8	%

Year ended December 31, 2011

During 2011, PHI reached a settlement with the Internal Revenue Service (IRS) with respect to interest due on its federal tax liabilities related to the November 2010 audit settlement for years 1996 through 2002. In connection with this agreement, PHI reallocated certain amounts that have been on deposit with the IRS since 2006 among liabilities in the settlement years and subsequent years. Primarily related to the settlement and reallocations, Pepco has recorded an additional tax benefit in the amount of $5 million (after-tax). This additional interest income was recorded in the second quarter of 2011.

During the third quarter of 2011, Pepco recalculated interest on its uncertain tax positions for open tax years based on different assumptions related to the application of its deposit made with the IRS in 2006. This resulted in an additional tax expense of $1 million (after-tax). Further during the third quarter of 2010, Pepco reversed $2 million of previously recorded tax benefits related to changes in estimates and interest related to uncertain and effectively settled tax positions.

During 2011, Pepco decided to adopt the safe harbor tax accounting method for certain repairs pursuant to IRS guidance. As a result, Pepco reversed $23 million of previously recorded liabilities on uncertain tax positions and reversed the associated $1 million of accrued interest.

In May 2011, Pepco received refunds of approximately $5 million and recorded tax benefits of approximately $4 million (after-tax) related to the filing of amended state tax returns. These amended returns reduced state taxable income due to an increase in tax basis on certain prior years’ asset dispositions.

Year ended December 31, 2010

In November 2010, PHI reached final settlement with the IRS with respect to its Federal tax returns for the years 1996 to 2002. In connection with the settlement, Pepco reallocated certain amounts on deposit with the IRS since 2006 among liabilities in the settlement years and subsequent years. In light of the settlement and reallocation, Pepco recalculated the estimated interest due for the tax years 1996 to 2002. The revised estimate resulted in the reversal of $24 million (after-tax) of previously accrued estimated interest due to the IRS. This reversal has been recorded as an income tax benefit in the fourth quarter of 2010.

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This benefit was partially offset by the reversal of $8 million of previously recorded tax benefits and $5 million of other adjustments.

Also in the fourth quarter of 2010, Pepco corrected the tax accounting for software amortization. Accordingly, a regulatory asset was established and income tax expense was reduced by $4 million.

Year ended December 31, 2009

In March 2009, the IRS issued a Revenue Agent’s Report for the audit of PHI’s consolidated Federal income tax returns for the calendar years 2003 to 2005. The IRS has proposed adjustments to PHI’s tax returns, including adjustments to Pepco’s capitalization of overhead costs for tax purposes and the deductibility of certain Pepco casualty losses. In conjunction with PHI, Pepco has appealed certain of the proposed adjustments and believes it has adequately reserved for the adjustments included in the Revenue Agent’s Report.

In November 2009, Pepco received a refund of prior years’ Federal income taxes of $51 million. The refund results from the carryback of PHI’s 2008 net operating loss for tax reporting purposes that reflected, among other things, significant tax deductions related to accelerated depreciation, the pension plan contributions paid in 2009 (which were deducted in 2008) and the cumulative effect of adopting a new method of tax reporting for certain repairs.

During 2009, a reconciliation of current and deferred income tax accounts was completed and, as a result, a $1 million net credit was booked to income tax expense. The 2009 adjustment is primarily included in “Other” in the reconciliation above.

Components of Deferred Income Tax Liabilities (Assets)

	At December 31,
	2011			2010
	(millions of dollars)
Deferred Tax Liabilities (Assets)
Depreciation and other basis differences related to plant and equipment	$	902		$	803
Pension and other postretirement benefits		117			100
Deferred taxes on amounts to be collected through future rates		20			15
Federal and state net operating losses		(80	)		—
Other		69			27
Total Deferred Tax Liabilities, net		1,028			945
Deferred tax assets included in Other Current Assets		11			13
Total Deferred Tax Liabilities, net non-current	$	1,039		$	958

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, 2011 and 2010.

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 continues to be amortized to income over the useful lives of the related property.

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Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits

	2011			2010			2009
	(millions of dollars)
Beginning balance as of January 1,	$	190		$	71		$	62
Tax positions related to current year:
Additions		—			110			—
Reductions		—			—			(2	)
Tax positions related to prior years:
Additions		12			24			45
Reductions		(26	)		(15	)		(34	)
Settlements		(3	)		—			—
Ending balance as of December 31,	$	173		$	190		$	71

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, 2011, 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, 2011, 2010 and 2009, Pepco recognized $8 million of pre-tax interest income ($5 million after-tax), $27 million of pre-tax interest income ($16 million after-tax), and $7 million of pre-tax interest expense ($4 million after-tax), respectively, as a component of income tax expense. As of December 31, 2011, 2010 and 2009, Pepco had accrued interest payable of $6 million, accrued interest receivable of $8 million and accrued interest payable of $8 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. The final settlement of the 2003 to 2005 federal audit, the methodology change for deduction of capitalized construction costs, or state audits could impact the balances and related interest accruals significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.

Tax Years Open to Examination

Pepco, as a direct subsidiary of PHI, is included on PHI’s consolidated Federal income tax return. Pepco’s Federal income tax liabilities for all years through 2002 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 amended state returns requesting $20 million in refunds which are subject to review by the various states. To date, Pepco has received $4 million in refunds.

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Other Taxes

Taxes other than income taxes for each year are shown below. These amounts are recoverable through rates.

	2011		2010		2009
	(millions of dollars)
Gross Receipts/Delivery	$	109	$	108	$	104
Property		44		42		41
County Fuel and Energy		170		154		94
Environmental, Use and Other		59		60		63
Total	$	382	$	364	$	302

(12) FAIR VALUE DISCLOSURES

Financial Instruments Measured at Fair Value on a Recurring Basis

Pepco applies FASB guidance on fair value measurement and disclosures (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). 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 internally developed 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 consist of life insurance policies that are categorized as level 2 assets because they are priced 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, 2011. 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.

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Level 3 – Pricing inputs include significant inputs that are 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 and liabilities that are classified as level 3 include certain life insurance policies that are valued using the cash surrender value of the policies, net of loans against those policies, which does not represent a quoted price in an active market.

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, 2011 and 2010. 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, 2011
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
Executive deferred compensation plan assets
Money Market Funds	$	12	$	12	$	—	$	—
Life Insurance Contracts		57		—		40		17
	$	69	$	12	$	40	$	17
LIABILITIES
Executive deferred compensation plan liabilities
Life Insurance Contracts	$	10	$	—	$	10	$	—
	$	10	$	—	$	10	$	—

(a) There were no significant transfers of instruments between level 1 and level 2 valuation categories.

	Fair Value Measurements at December 31, 2010
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
Executive deferred compensation plan assets
Money Market Funds	$	6	$	6	$	—	$	—
Life Insurance Contracts		59		—		41		18
	$	65	$	6	$	41	$	18
LIABILITIES
Executive deferred compensation plan liabilities
Life Insurance Contracts	$	11	$	—	$	11	$	—
	$	11	$	—	$	11	$	—

(a) There were no significant transfers of instruments between level 1 and level 2 valuation categories.

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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, 2011 and 2010 are shown below.

	Life Insurance Contracts
	Year Ended December 31,
	2011			2010
	(millions of dollars)
Beginning balance as of January 1,	$	18		$	18
Total gains (losses) (realized and unrealized):
Included in income		6			3
Included in accumulated other comprehensive loss		—			—
Purchases		—			—
Issuances		(3	)		(3	)
Settlements		(4	)		—
Transfers in (out) of Level 3		—			—
Ending balance as of December 31,	$	17		$	18

The breakdown of realized and unrealized gains or (losses) on level 3 instruments included in income as a component of Other operation and maintenance expense for the periods below were as follows:

	Year Ended December 31,
	2011		2010
	(millions of dollars)
Total gains included in income for the period	$	6	$	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 issued debt and equity instruments at December 31, 2011 and 2010 are shown below:

	December 31, 2011				December 31, 2010
	(millions of dollars)
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	1,540	$	1,943	$	1,540	$	1,722

The fair value of long-term debt was based on actual trade prices (where available), bid prices obtained from brokers and validated by PHI, or a discounted cash flow model. Prices obtained from brokers include observable market data on the target security or historical correlation and direct observation methodologies of similar debt securities.

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The carrying amounts of all other financial instruments in the accompanying financial statements approximate fair value.

(13) COMMITMENTS AND CONTINGENCIES

General Litigation

In 1993, Pepco was served with Amended Complaints filed in the state Circuit Courts of Prince George’s County, Baltimore City and Baltimore County, Maryland in separate ongoing, consolidated proceedings known as “In re: Personal Injury Asbestos Case.” Pepco and other corporate entities were brought into these cases on a theory of premises liability. Under this theory, the plaintiffs argued that Pepco was negligent in not providing a safe work environment for employees or its contractors, who allegedly were exposed to asbestos while working on Pepco’s property. Initially, a total of approximately 448 individual plaintiffs added Pepco to their complaints. While the pleadings are not entirely clear, it appears that each plaintiff sought $2 million in compensatory damages and $4 million in punitive damages from each defendant.

As of December 31, 2011, there are approximately 180 cases still pending against Pepco in the Maryland State Courts, of which approximately 90 cases were filed after December 19, 2000, and were tendered to Mirant Corporation (Mirant) for defense and indemnification in connection with the sale by Pepco of its generation assets to Mirant in 2000. While the aggregate amount of monetary damages sought in the remaining suits (excluding those tendered to Mirant) is approximately $360 million, PHI and Pepco believe the amounts claimed by the remaining plaintiffs are greatly exaggerated. The amount of total liability, if any, and any related insurance recovery cannot be determined at this time. If an unfavorable decision were rendered against Pepco, it could have a material adverse effect on Pepco’s and PHI’s financial condition, results of operations and cash flows.

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 Pepco’s customers, 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, 2011 are summarized as follows:

	Transmission and Distribution		Legacy Regulated Generation		Other		Total
	(millions of dollars)
Beginning balance as of January 1	$	12	$	3	$	—	$	15
Accruals		2		1		—		3
Payments		—		—		—		—
Ending balance as of December 31		14		4		—		18
Less amounts in Other Current Liabilities		2		—		—		2
Amounts in Other Deferred Credits	$	12	$	4	$	—	$	16

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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 Peck’s 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 a Federal Register notice published on November 4, 2009, EPA placed the Peck Iron and Metal site on the National Priorities List (NPL). The NPL, among other things, serves as a guide to EPA in determining which sites warrant further investigation to assess the nature and extent of the human health and environmental risks associated with a site. In September 2011, EPA initiated a remedial investigation/feasibility study (RI/FS) using federal funds. Pepco cannot at this time estimate an amount or range of reasonably possible loss associated with the RI/FS, any remediation activities to be performed at the site or any other costs that EPA might seek to impose on Pepco.

Ward Transformer Site

In April 2009, a group of PRPs with respect to the Ward Transformer site in Raleigh, North Carolina, filed a complaint in the U.S. District Court for the Eastern District of North Carolina, alleging cost recovery and/or contribution claims against a number of entities, including Pepco, with respect to past and future response costs incurred by the PRP group in performing a removal action at the site. In a March 2010 order, the court denied the defendants’ motion to dismiss. The next step in the litigation will be the filing of summary judgment motions regarding liability for certain “test case” defendants other than Pepco. The case has been stayed as to the remaining defendants pending rulings upon the test cases. Although Pepco cannot at this time estimate an amount or range of reasonably possible losses to which it may be exposed, Pepco does not believe that it had extensive business transactions, if any, with the Ward Transformer site and therefore, costs incurred to resolve this matter are not expected to be material.

Benning Road Site

In September 2010, PHI received a letter from EPA stating that EPA and the District of Columbia Department of the Environment (DDOE) have identified the Benning Road location, consisting of a transmission and distribution facility operated by Pepco and a generation facility operated by Pepco Energy Services, as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. The letter stated that the principal contaminants of concern are polychlorinated biphenyls and polycyclic aromatic hydrocarbons, that EPA is monitoring the efforts of DDOE and that EPA intends to use federal authority to address the Benning Road site if an agreement for a comprehensive study to evaluate (and, if necessary, to clean up) the facility is not reached. In January 2011, Pepco and Pepco Energy Services entered into a proposed consent decree with DDOE that requires Pepco and Pepco Energy Services to conduct a RI/FS for the Benning Road site and an approximately 10-15 acre portion of the adjacent Anacostia River. The RI/FS will form the basis for DDOE’s selection of a remedial action for the Benning Road site and for the Anacostia River sediment associated with the site. In February 2011, the District of Columbia filed a complaint against Pepco and Pepco Energy Services in the United States District Court for the District of Columbia for the purpose of obtaining judicial approval of the consent decree. The complaint asserted claims under CERCLA, the Resource Conservation and Recovery Act, and District of Columbia law seeking to compel Pepco and Pepco Energy Services to take

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actions to investigate and clean up contamination allegedly originating from the Benning Road site, and to reimburse the District of Columbia for its response costs. On December 1, 2011, the District Court issued an order granting the motion to enter a revised consent decree. The District Court’s order entering the consent decree requires DDOE to solicit and consider public comment on the key RI/FS documents prior to final approval, requires DDOE to make final versions of all approved RI/FS documents available to the public, and requires the parties to submit a written status report to the District Court on May 24, 2013 regarding the implementation of the requirements of the consent decree and any related plans for remediation. In addition, if the RI/FS has not been completed by May 24, 2013, the status report must provide an explanation and a showing of good cause for why the work has not been completed.

Pepco and Pepco Energy Services commenced work on the RI/FS upon entry of the consent decree. On December 21, 2011, they submitted a draft RI/FS Scope of Work and a draft Community Involvement Plan to DDOE for review. DDOE has solicited public comment on these documents, which were due by February 13, 2012, with respect to the draft Scope of Work, and are due by March 7, 2012 with respect to the Draft Community Involvement Plan. Depending on the nature and extent of public comments received, Pepco and Pepco Energy Services anticipate that these documents will be approved and a draft RI/FS work plan will be submitted by the end of the first quarter of 2012. The field work will commence after final work plan approval by DDOE.

The amount of remediation costs accrued for this matter is included in the table above under the column entitled Transmission and Distribution.

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.

The release falls within the regulatory jurisdiction of multiple federal and state agencies. Beginning in March 2011, DDOE issued a series of compliance directives that require Pepco to prepare an incident report, provide certain records, and prepare and implement plans for sampling surface water and river sediments and assessing ecological risks and natural resources damages. Pepco has submitted an incident report and is providing the requested records. In December 2011, Pepco completed field sampling and anticipates submitting a report to DDOE during the second quarter of 2012.

On March 16, 2011, the Virginia Department of Environmental Quality (VADEQ) requested documentation regarding the release and the preparation of an emergency response report, which Pepco submitted to the agency on April 20, 2011. On March 25, 2011, Pepco received a notice of violation from VADEQ and in December 2011, VADEQ executed a consent agreement that had been executed by Pepco in August, pursuant to which Pepco paid a civil penalty of approximately $40,000.

During March 2011, EPA conducted an inspection of the Potomac River substation to review compliance with federal regulations regarding Spill Prevention, Control, and Countermeasure (SPCC) plans for facilities using oil-containing equipment in proximity to surface waters. As a result, EPA identified several potential violations of the SPCC regulations relating to SPCC plan content, recordkeeping, and secondary containment, which EPA advised may lead to an EPA demand for noncompliance penalties. As a result of the oil release, Pepco submitted a revised SPCC plan to EPA in August 2011 and implemented certain interim operational changes to the secondary containment systems at the facility which involve pumping accumulated storm water to an aboveground holding tank for off-site disposal. In December 2011, Pepco completed the installation of a treatment system designed to allow automatic discharge of accumulated storm water from the secondary containment system. Pepco is currently seeking DDOE’s

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approval to commence operation of the new system and, after receiving such approval, will submit a further revised SPCC plan to EPA. In the meantime, Pepco will continue to use the above ground holding tank to manage storm water from the secondary containment system.

The U.S. Coast Guard assessed a $5,000 penalty against Pepco for the release of oil into the waters of the United States, which Pepco has paid.

In addition to the cost to remediate impacts to the river and shoreline, Pepco also may be liable for non-compliance penalties and/or natural resource damages in addition to those it has already paid. It is not possible to accurately estimate an amount or range of reasonably possible loss to which it may be exposed associated with this liability at this time; however, based on current information, PHI and Pepco do not believe this matter will have a material adverse effect on their respective financial conditions, results of operations or cash flows.

The amounts accrued for these matters are included in the table above under the column entitled Transmission and Distribution.

District of Columbia Tax Legislation

On June 14, 2011, the Council of the District of Columbia approved the Fiscal Year 2012 Budget Support Act of 2011 (the Budget Support Act). The Budget Support Act includes a provision requiring that corporate taxpayers in the District of Columbia calculate taxable income allocable or apportioned to the District of Columbia by reference to the income and apportionment factors applicable to commonly controlled entities organized within the United States that are engaged in a unitary business. This new tax reporting method resulted in an additional state income tax provision of less than $1 million in 2011, which is reflected in Pepco’s results of operations. The District of Columbia Office of Tax and Revenue issued proposed regulations on January 20, 2012, to implement this reporting method. Pepco will continue to analyze these regulations and will record the impact, if any, of such regulations on PHI’s results of operations in the period in which the proposed regulations are adopted as final regulations.

Contractual Obligations

As of December 31, 2011, Pepco had no contractual obligations under non-derivative fuel and power purchase contracts.

(14) 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 causal 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, 2011, 2010 and 2009 were approximately $185 million, $186 million and $175 million, respectively.

Certain subsidiaries of Pepco Energy Services Inc. (collectively with its subsidiaries, Pepco Energy Services) perform utility maintenance services, including services that are treated as capital costs, for Pepco. Amounts charged to Pepco by these companies for the years ended December 31, 2011, 2010 and 2009 were approximately $20 million, $10 million and $9 million, respectively.

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In addition to the transactions described above, Pepco’s financial statements include the following related party transactions in its statements of income:

	For the Year Ended December 31,
	2011		2010		2009
Income (Expense)	(millions of dollars)
Purchased power under Default Electricity Supply contracts with Conectiv Energy Supply, Inc. (a)(b)	$	—	$	—	$	1

(a) Included in purchased energy expense.

(b) During 2010, PHI disposed of its Conectiv Energy segment and a third party assumed Conectiv Energy Supply, Inc.’s responsibilities under these contracts.

As of December 31, 2011 and 2010, Pepco had the following balances on its balance sheets due to related parties:

	2011			2010
(Liability) Asset	(millions of dollars)
Payable to Related Party (current) (a)
PHI Parent Company	$	15		$	—
PHI Service Company		(32	)		(27	)
Pepco Energy Services (b)		(40	)		(48	)
Total	$	(57	)	$	(75	)
Money Pool Balance with Pepco Holdings (included in cash and cash equivalents)	$	—		$	82

(a) Included in accounts payable due to associated companies.

(b) Pepco bills customers on behalf of Pepco Energy Services where customers have selected Pepco Energy Services as their alternative energy supplier or where Pepco Energy Services has performed work for certain government agencies under a General Services Administration area-wide agreement.

(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.

	2011
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(millions of dollars)
Total Operating Revenue	$	534		$	506		$	603		$	435		$	2,078
Total Operating Expenses		491			454			521			400			1,866
Operating Income		43			52			82			35			212
Other Expenses		(18	)		(18	)		(21	)		(20	)		(77	)
Income Before Income Tax Expense		25			34			61			15			135
Income Tax Expense (a)		7			2			23			4			36
Net Income	$	18		$	32		$	38		$	11		$	99

(a) Includes tax benefits of $5 million (after-tax) associated with an interest benefit related to federal tax liabilities and an additional tax benefit of $4 million (after-tax) related to the filing of amended state tax returns, each recorded in the second quarter.

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	2010
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(millions of dollars)
Total Operating Revenue	$	552		$	539		$	706		$	491		$	2,288
Total Operating Expenses (a) (b)		516			462			617			463			2,058
Operating Income		36			77			89			28			230
Other Expenses		(22	)		(22	)		(19	)		(22	)		(85	)
Income Before Income Tax Expense		14			55			70			6			145
Income Tax Expense (Benefit)		6			23			33			(25	)		37
Net Income	$	8		$	32		$	37		$	31		$	108

(a) Includes restructuring charges of $6 million and $9 million in the third and fourth quarters, respectively.

(b) Includes expenses of $2 million and $9 million in the second and third quarters, respectively, related to the effects of divestiture-related claims.

(16) RESTRUCTURING CHARGE

With the ongoing wind-down of the retail energy supply business of Pepco Energy Services and the disposition of Conectiv Energy, PHI repositioned itself as a regulated transmission and distribution company during 2010. In connection with this repositioning, PHI completed a comprehensive organizational review in 2010 that identified opportunities to streamline the organization and to achieve certain reductions in corporate overhead costs that are allocated to its operating segments, which resulted in the adoption of a restructuring plan. PHI began implementation of the plan during 2010, identifying 164 employee positions that were eliminated. The plan also included additional cost reduction opportunities that were implemented through process improvements and operational efficiencies.

In connection with the restructuring plan, Pepco recorded a pre-tax restructuring charge related to its allocation of severance, pension, and health and welfare benefits for the termination of corporate services employees at PHI of $15 million in 2010. The severance, pension, and health and welfare benefits were estimated based on the years of service and compensation levels of the employees associated with the 164 eliminated positions at PHI. The restructuring charge was reflected as a separate line item in the statement of income for the year ended December 31, 2010.

A reconciliation of Pepco’s accrued restructuring charges for the year ended December 31, 2011 is as follows:

	Year Ended December 31, 2011
	(millions of dollars)
Beginning balance as of January 1, 2011	$	15
Restructuring charge		—
Cash payments		(12	)
Ending balance as of December 31, 2011	$	3

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Management’s Report on Internal Control over Financial Reporting

The management of 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, 2011 based on the framework in Internal Control – Integrated Framework 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, 2011.

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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, 2011 and December 31, 2010, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2011 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 23, 2012

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DELMARVA POWER & LIGHT COMPANY

STATEMENTS OF INCOME

For the Year Ended December 31,	2011			2010			2009
	(millions of dollars)
Operating Revenue
Electric	$	1,074		$	1,163		$	1,135
Natural gas		230			237			268
Total Operating Revenue		1,304			1,400			1,403
Operating Expenses
Purchased energy		635			740			751
Gas purchased		155			164			193
Other operation and maintenance		239			255			238
Restructuring charge		—			8			—
Depreciation and amortization		89			83			76
Other taxes		37			37			35
Total Operating Expenses		1,155			1,287			1,293
Operating Income		149			113			110
Other Income (Expenses)
Interest and dividend income		—			—			1
Interest expense		(44	)		(44	)		(44	)
Other income		8			7			1
Total Other Expenses		(36	)		(37	)		(42	)
Income Before Income Tax Expense		113			76			68
Income Tax Expense		42			31			16
Net Income	$	71		$	45		$	52

The accompanying Notes are an integral part of these Financial Statements.

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DELMARVA POWER & LIGHT COMPANY

BALANCE SHEETS

ASSETS	December 31, 2011			December 31, 2010
	(millions of dollars)
CURRENT ASSETS
Cash and cash equivalents	$	5		$	69
Accounts receivable, less allowance for uncollectible accounts of $12 million and $13 million, respectively		186			212
Inventories		44			41
Prepayments of income taxes		14			62
Prepaid expenses and other		28			22
Total Current Assets		277			406
INVESTMENTS AND OTHER ASSETS
Goodwill		8			8
Regulatory assets		227			242
Prepaid pension expense		162			139
Other		23			21
Total Investments and Other Assets		420			410
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		3,188			3,000
Accumulated depreciation		(926	)		(901	)
Net Property, Plant and Equipment		2,262			2,099
TOTAL ASSETS	$	2,959		$	2,915

The accompanying Notes are an integral part of these Financial Statements.

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DELMARVA POWER & LIGHT COMPANY

BALANCE SHEETS

LIABILITIES AND EQUITY	December 31, 2011		December 31, 2010
	(millions of dollars, except shares)
CURRENT LIABILITIES
Short-term debt	$	152	$	105
Current portion of long-term debt		66		35
Accounts payable and accrued liabilities		92		98
Accounts payable due to associated companies		21		34
Taxes accrued		11		6
Interest accrued		6		7
Derivative liabilities		12		15
Other		59		73
Total Current Liabilities		419		373
DEFERRED CREDITS
Regulatory liabilities		297		310
Deferred income taxes, net		615		561
Investment tax credits		6		7
Other postretirement benefit obligations		22		22
Liabilities and accrued interest related to uncertain tax positions		9		24
Derivative liabilities		3		8
Other		37		39
Total Deferred Credits		989		971
LONG-TERM LIABILITIES
Long-term debt		699		730
COMMITMENTS AND CONTINGENCIES (NOTE 15)
EQUITY
Common stock, $2.25 par value, 1,000 shares authorized, 1,000 shares outstanding		—		—
Premium on stock and other capital contributions		347		347
Retained earnings		505		494
Total Equity		852		841
TOTAL LIABILITIES AND EQUITY	$	2,959	$	2,915

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,	2011			2010			2009
	(millions of dollars)
OPERATING ACTIVITIES
Net income	$	71		$	45		$	52
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		89			83			76
Deferred income taxes		57			74			60
Investment tax credit amortization		(1	)		(1	)		(1	)
Changes in:
Accounts receivable		26			(21	)		10
Inventories		(3	)		(1	)		12
Regulatory assets and liabilities, net		(32	)		(12	)		29
Accounts payable and accrued liabilities		(23	)		31			(26	)
Pension contributions		(40	)		—			(10	)
Prepaid pension expense, excluding contributions		17			18			37
Taxes accrued		14			11			(37	)
Other assets and liabilities		3			(1	)		11
Net Cash From Operating Activities		178			226			213
INVESTING ACTIVITIES
Investment in property, plant and equipment		(229	)		(250	)		(193	)
Proceeds from sale of assets		—			—			1
Net other investing activities		(4	)		2			1
Net Cash Used By Investing Activities		(233	)		(248	)		(191	)
FINANCING ACTIVITIES
Dividends paid to Parent		(60	)		(23	)		(28	)
Capital contribution from Parent		—			11			32
Issuances of long-term debt		35			109			—
Reacquisitions of long-term debt		(35	)		(31	)		—
Issuances (repayments) of short-term debt, net		47			—			(141	)
Net other financing activities		4			(1	)		3
Net Cash (Used By) From Financing Activities		(9	)		65			(134	)
Net (Decrease) Increase In Cash and Cash Equivalents		(64	)		43			(112	)
Cash and Cash Equivalents at Beginning of Year		69			26			138
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	5		$	69		$	26
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for interest (net of capitalized interest of $1 million, $2 million and $1 million, respectively)	$	43		$	40		$	41
Cash received for income taxes		(24	)		(49	)		(17	)

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, DECEMBER 31, 2008		1,000	$	—	$	304	$	448		$	752
Net Income		—		—		—		52			52
Dividends on common stock		—		—		—		(28	)		(28	)
Capital contribution from Parent		—		—		32		—			32
BALANCE, DECEMBER 31, 2009		1,000		—		336		472			808
Net Income		—		—		—		45			45
Dividends on common stock		—		—		—		(23	)		(23	)
Capital contribution from Parent		—		—		11		—			11
BALANCE, DECEMBER 31, 2010		1,000		—		347		494			841
Net Income		—		—		—		71			71
Dividends on common stock		—		—		—		(60	)		(60	)
BALANCE, DECEMBER 31, 2011		1,000	$	—	$	347	$	505		$	852

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 Delaware and portions of 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).

(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 evaluations, fair value calculations for derivative instruments, pension and other postretirement benefits assumptions, unbilled revenue calculations, the assessment of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of restructuring charges, recognition of changes in network service transmission rates for prior service year costs, accrual of self-insurance reserves for general and auto 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.

Storm Costs

During 2011, DPL incurred significant costs associated with Hurricane Irene that affected its service territory. Total incremental storm costs associated with Hurricane Irene were $11 million, with $8 million incurred for repair work and $3 million incurred as capital expenditures. Costs incurred for repair work of $5 million were deferred as a regulatory asset to reflect the probable recovery of these storm costs in DPL’s jurisdictions, and the remaining $3 million was charged to Other operation and maintenance expense. Approximately $1 million of these total incremental storm costs have been estimated for the cost of restoration services provided by outside contractors. Since the invoices for such services had not been received at December 31, 2011, actual invoices may vary from these estimates. DPL is seeking recovery of the incremental Hurricane Irene costs in each of its jurisdictions in planned distribution rate case filings as discussed in Note (7), “Regulatory Matters – Regulatory Proceedings.”

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Restructuring Charge

PHI commenced a comprehensive organizational review in the second quarter of 2010 to identify opportunities to streamline the organization and to achieve certain reductions in corporate overhead costs allocated to its operating segments. The restructuring plan resulted in the elimination of 164 employee positions. DPL’s accrual of $8 million in costs associated with termination benefits was based on estimated severance costs and actuarial calculations of the present value of certain changes in pension and other postretirement benefits for terminated employees. There were no material changes to this accrual in 2011.

Network Service Transmission Rates

In May of each year, DPL provides its updated network service transmission rate to the Federal Energy Regulatory Commission (FERC) effective for the service year beginning June 1 of the current year and ending May 31 of the following year. The network service transmission rate includes a true-up for costs incurred in the prior service year that had not yet been reflected in rates charged to customers.

Revenue Recognition

DPL recognizes revenues upon distribution of electricity and gas to its customers, including unbilled revenue for services rendered, but not yet billed. DPL’s unbilled revenue was $56 million and $72 million as of December 31, 2011 and 2010, 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 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 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. Revenues from non-regulated electricity and gas sales are included in Electric revenues and Natural Gas revenues, respectively.

Taxes related to the consumption of electricity and gas by its 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. Excise tax related generally to the consumption of gasoline by DPL in the normal course of business is charged to operations, maintenance or construction, and is not material.

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Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in DPL’s gross revenues were $18 million, $17 million and $17 million for the years ended December 31, 2011, 2010 and 2009, 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 Delaware Public Service Commission (DPSC). Derivatives are recorded in the consolidated balance sheets as derivative assets or derivative liabilities and measured at fair value unless designated as normal purchases or normal sales. 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. DPLs 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. The gain or loss on a derivative that is designated as a cash flow hedge is initially recorded in Accumulated Other Comprehensive Loss (a separate component of equity) to the extent that the hedge is effective.

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. At December 31, 2011, after the effects of cash collateral and netting, there was a net derivative liability of $15 million, offset by a $17 million regulatory asset. At December 31, 2010, after the effects of cash collateral and netting, there was a net derivative liability of $23 million, offset by a $31 million regulatory asset.

Long-Lived Asset 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 an asset is being used or its physical condition. A long-lived asset to be held and used is written down to fair value if its 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 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 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 balance sheets. See Note (7), “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.

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 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. DPL has entered into three land-based wind power purchase agreements (PPAs) in the aggregate amount of 128 megawatts and one solar PPA with a 10 megawatt facility as of December 31, 2011. All of the facilities associated with these PPAs are operational, and DPL is obligated to purchase energy and RECs in amounts generated and delivered by the wind facilities and solar renewable energy credits (SRECs) from the solar facility at rates that are primarily fixed under these agreements. DPL has concluded that consolidation is not required for any of these agreements under the FASB guidance on the consolidation of variable interest entities.

DPL is obligated to purchase energy and RECs from one of the wind facilities through 2024 in amounts not to exceed 50 megawatts, the second of the wind facilities through 2031 in amounts not to exceed 40 megawatts, and the third facility through 2031 in amounts not to exceed 38 megawatts. DPL’s purchases under the three wind PPAs totaled $18 million and $12 million for the years ended December 31, 2011 and 2010, respectively. The term of the agreement with the solar facility is 20 years and DPL is obligated to purchase SRECs in an amount up to 70 percent of the energy output at a fixed price. DPL’s purchases under the agreement were $1 million for the year ended December 31, 2011.

In addition to the three land-based wind PPAs, DPL has also entered into an offshore wind PPA for a 200 megawatt facility that has not yet been constructed. In December 2011, the developer of the offshore wind facility notified DPL that it was terminating the wind PPA for this facility. DPL received a $2 million termination payment from the developer that will be refunded to DPL’s Delaware customers.

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 megawatts to be constructed by a Qualified Fuel Cell Provider. The tariff and the RPS establish that DPL would be an agent to collect payments in advance from its distribution customers and remit them to the Qualified Fuel Cell Provider for each megawatt hour of energy produced by the fuel cell facilities over 20 years. DPL would have no liability to the Qualified Fuel Cell Provider other than to remit payments collected from its distribution customers pursuant to the tariff. The RPS provide for a reduction in DPL’s REC requirements based upon the actual energy output of the facilities. PHI has concluded that DPL would account for this arrangement as an agency transaction.

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, 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 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. Although management 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 inventory 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. All of DPL’s goodwill was generated by DPL’s acquisition of Conowingo Power Company in 1995. DPL tests its goodwill for impairment annually and whenever an event occurs or circumstances change in the interim that would more likely than not reduce the fair value of DPL below its carrying amount. DPL performs its annual impairment test on November 1. 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; an adverse regulatory action; or an impairment of DPL’s long-lived assets. As described in Note (6), “Goodwill,” DPL’s goodwill was not impaired as of November 1, 2011.

Regulatory Assets and Regulatory Liabilities

Certain aspects of DPL’s business are subject to regulation by the DPSC and the Maryland Public Service Commission (MPSC), and, until the sale of its Virginia assets on January 2, 2008, were regulated by the Virginia State Corporation Commission. 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

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through the establishment of regulatory assets. 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 mechanism (BSA) for retail customers. See Note (7), “Regulatory Matters – Regulatory Proceedings.” 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 are 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 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 gas property, plant and equipment is computed on a straight-line basis using composite rates by classes of depreciable property. Accumulated depreciation is charged with the cost of depreciable property retired, less salvage and other recoveries. Property, plant and equipment other than electric and gas facilities is generally depreciated on a straight-line basis over the useful lives of the assets. The system-wide composite depreciation rate for 2011, 2010 and 2009 for DPL’s transmission and distribution system property was approximately 2.8%.

Capitalized Interest and Allowance for Funds Used During Construction

In accordance with FASB guidance on regulated operations (ASC 980), utilities can 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, $2 million, and $1 million for the years ended December 31, 2011, 2010, and 2009, respectively.

DPL recorded amounts for the equity component of AFUDC of $3 million, $4 million and zero for the years ended December 31, 2011, 2010 and 2009, respectively.

Leasing Activities

DPL’s lease transactions include plant, office space, equipment, software and vehicles. 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 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.

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 issues. 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, asset removal costs are recorded as regulatory liabilities. At December 31, 2011 and 2010, $244 million and $239 million, respectively, of asset removal costs are included in Regulatory liabilities in the accompanying balance sheets.

Pension and Postretirement Benefit Plans

Pepco Holdings sponsors the PHI Retirement Plan, a non-contributory, defined benefit pension plan that covers substantially all employees of DPL and certain employees of other Pepco Holdings subsidiaries. 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 existing and future preferred stock, 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 $505 million and $494 million of retained earnings available for payment of common stock dividends at December 31, 2011 and 2010, respectively. These amounts represent the total retained earnings balances at those dates.

Reclassifications and Adjustments

Certain prior period amounts have been reclassified in order to conform to current period presentation. The following adjustments have been recorded and are not considered material individually or in the aggregate:

Default Electricity Supply Revenue and Costs Adjustments

During 2011, DPL recorded adjustments associated with the accounting for Default Electricity Supply revenue and costs. These adjustments were primarily due to the under-recognition of allowed returns on working capital and administrative costs, and resulted in a pre-tax decrease in Other operation and maintenance expense of $11 million for the year ended December 31, 2011.

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Operating Revenue

During 2009, DPL recorded an adjustment to correct certain errors in the BSA calculation. The adjustment resulted in a decrease in revenue of $1 million.

(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Fair Value Measurements and Disclosures (ASC 820)

The FASB issued new disclosure requirements that require significant items within the reconciliation of the Level 3 valuation category to be presented in separate categories for purchases, sales, issuances and settlements. The guidance was effective beginning with DPL’s March 31, 2011 financial statements. DPL has included the new disclosure requirements in Note (14), “Fair Value Disclosures,” to its financial statements.

Goodwill (ASC 350)

The FASB issued new guidance on performing goodwill impairment tests that was effective beginning January 1, 2011 for DPL. Under the new guidance, the carrying value of the reporting unit must include the liabilities that are part of the capital structure of the reporting unit. DPL already allocates liabilities to the reporting unit when performing its goodwill impairment test, so the new guidance did not change DPL’s goodwill impairment test methodology.

Compensation Retirement Benefits—Multiemployer Plans (ASC 715-80)

In September 2011, the FASB issued new disclosure requirements for participants in multiemployer pension and postretirement benefit plans that would be effective beginning with DPL’s December 31, 2011 financial statements. Most of these disclosures are not applicable to DPL because it participates in PHI’s single employer pension plan and accounts for it as participation in a multiemployer plan. The disclosure requirements for DPL were limited and are already provided in DPL’s Note (10), “Pension and Other Postretirement Benefits.”

(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Fair Value Measurements and Disclosures (ASC 820)

In May 2011, the FASB issued new guidance on fair value measurement and disclosures that will be effective beginning with DPL’s March 31, 2012 financial statements. The new guidance will change how fair value is measured in specific instances and expand disclosures about fair value measurements. DPL expects that it will have to provide additional disclosures, but does not expect this guidance to have a significant impact on its fair value measurements.

Goodwill (ASC 350)

In September 2011, the FASB issued new guidance that changes the annual and interim assessments of goodwill for impairment. The new guidance modifies the required annual impairment test by giving entities the option to perform a qualitative assessment of whether it is more likely than not that goodwill is impaired before performing a quantitative assessment. The new guidance also amends the events and circumstances that entities should assess to determine whether an interim quantitative impairment test is necessary. The new guidance is effective beginning January 1, 2012 for DPL as it did not elect the option to apply the guidance earlier. DPL did not employ the new qualitative assessment as part of its November 1, 2011 annual impairment test. DPL does not expect the new impairment guidance to have a material impact on its financial statements.

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Balance Sheet (ASC 210)

In December 2011, the FASB issued new disclosure requirements for assets and liabilities, such as derivatives, that are subject to contractual netting arrangements. The new disclosures will include information about the gross exposures and net exposure under contractual netting arrangements as well as how the exposures are presented in the financial statements. The new disclosures are effective beginning with DPL’s March 31, 2013 financial statements. DPL is evaluating the impact of this new guidance on its financial statements.

(5) SEGMENT INFORMATION

The company operates its business as one regulated utility segment, which includes all of its services as described above.

(6) GOODWILL

DPL’s goodwill balance of $8 million was unchanged during the year ended December 31, 2011. All of DPL’s goodwill was generated by its acquisition of Conowingo Power Company in 1995.

DPL’s annual impairment test as of November 1, 2011 indicated that goodwill was not impaired.

In order to estimate the fair value of DPL’s business, DPL uses two valuation techniques: an income approach and a market approach. The income approach estimates fair value based on a discounted cash flow analysis using estimated future cash flows and a terminal value that is consistent with DPL’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. DPL determines the estimated WACC by considering market-based information for the cost of equity and cost of debt as of the measurement date appropriate for DPL’s business. The market approach estimates fair value based on a multiple of earnings before interest, taxes, depreciation, and amortization (EBITDA) that management believes is consistent with EBITDA multiples for comparable utilities. DPL has consistently used this valuation framework to estimate the fair value of DPL’s business.

The estimation of fair value is dependent on a number of factors that are derived from the DPL business forecast, 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 affect the results of impairment testing. Assumptions used in the models were consistent with historical experience, including assumptions concerning the recovery of operating costs and capital expenditures. Sensitive, interrelated and uncertain variables that could decrease the estimated fair value of the DPL business include utility sector market performance, sustained adverse business conditions, changes in forecasted revenues, higher operating and maintenance capital expenditure requirements, a significant increase in the cost of capital and other factors.

DPL’s gross amount of goodwill, accumulated impairment losses and carrying amount of goodwill for the years ended December 31, 2011 and 2010 were as follows:

	2011						2010
	Gross Amount		Accumulated Impairment Losses		Carrying Amount		Gross Amount		Accumulated Impairment Losses		Carrying Amount
	(millions of dollars)
Beginning balance as of January 1	$	8	$	—	$	8	$	8	$	—	$	8
Impairment losses		—		—		—		—		—		—
Ending balance as of December 31	$	8	$	—	$	8	$	8	$	—	$	8

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(7) REGULATORY MATTERS

Regulatory Assets and Regulatory Liabilities

The components of DPL’s regulatory asset and liability balances at December 31, 2011 and 2010 are as follows:

	2011		2010
	(millions of dollars)
Regulatory Assets
Deferred income taxes	$	61	$	65
COPCO acquisition adjustment (a)		30		33
Recoverable meter-related costs (a)		26		29
Deferred losses on gas derivatives		17		31
Blueprint for the Future		20		11
Deferred debt extinguishment costs (a)		16		16
Deferred energy supply costs (b)		15		22
Other		42		35
Total Regulatory Assets	$	227	$	242
Regulatory Liabilities
Asset removal costs	$	244	$	239
Deferred income taxes due to customers		38		38
Deferred energy supply costs		12		23
Other		3		10
Total Regulatory Liabilities	$	297	$	310

(a) A return is earned on these deferrals.

(b) A return is generally earned in Delaware on this deferral.

A description for each category of regulatory assets and regulatory liabilities follows:

Deferred Income Taxes: Represents a receivable from our customers for tax benefits DPL previously flowed through before the company was ordered to account for 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 will be amortized from August 2007 through August 2018. The return earned is 12.95%.

Recoverable Meter-Related Costs: Represents costs associated with the installation of smart meters and the early retirement of existing meters throughout DPL’s service territory as a result of the Advanced Metering Infrastructure project.

Deferred Losses on Gas Derivatives: Represents losses associated with hedges of natural gas purchases that are recoverable through the GCR approved by the DPSC.

Blueprint for the Future: Includes costs associated with Blueprint for the Future initiatives which include programs to help customers better manage their energy use and to allow DPL to better manage its electrical and natural gas distribution systems.

Deferred Debt Extinguishment Costs: Represents the costs of debt extinguishment for which recovery through regulated utility rates is considered probable and, if approved, will be amortized to interest expense during the authorized rate recovery period.

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Deferred Energy Supply Costs: The regulatory asset represents primarily deferred energy costs associated with a net under-recovery of Default Electricity Supply costs incurred in Maryland and deferred fuel costs for DPL’s gas business that are probable of recovery in rates. The gas deferred fuel costs are recovered over a twelve month period. The regulatory liability represents primarily deferred energy and transmission costs associated with a net over-recovery of Default Electricity Supply costs incurred in Delaware and Maryland that will be refunded to customers.

Other: Represents miscellaneous regulatory assets that generally are being amortized over 1 to 20 years.

Asset Removal Costs: DPL’s depreciation rates include a component for removal costs, as approved by the relevant federal and state regulatory commissions. As such, DPL has recorded a regulatory liability for its estimate of the difference between incurred removal costs and the amount of removal costs recovered through depreciation rates.

Deferred Income Taxes Due to Customers: Represents the portions of deferred income tax liabilities applicable to DPL’s utility operations 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: Includes miscellaneous regulatory liabilities.

Regulatory Proceedings

Rate Proceedings

Over the last several years, DPL proposed in each of its service territories the adoption of a mechanism to decouple retail distribution revenue from the amount of power delivered to retail customers. To date:

• A BSA has been approved and implemented for electric service in Maryland. The MPSC has issued an order requiring modification of the BSA in Maryland so that revenues lost as a result of major storm outages are not collected if electric service is not restored to the pre-major storm levels within 24 hours of the start of a major storm (as discussed below).

• A modified fixed variable rate design (MFVRD) has been approved in concept for electric service in Delaware, but the implementation has been deferred by the DPSC pending the development of an implementation plan and a customer education plan. DPL anticipates that the MFVRD will be in place for electric service by early 2013.

• A MFVRD has been approved in concept for natural gas service in Delaware, but implementation likewise has been deferred until development of an implementation plan and a customer education plan. DPL anticipates that the MFVRD will be in place for natural gas service by early 2013.

Under the BSA, 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. The MFVRD approved in concept in Delaware provides for a fixed customer charge (i.e., not tied to the customer’s volumetric consumption) to recover the utility’s fixed costs, plus a reasonable rate of return. Although different from the BSA, DPL views the MFVRD as an appropriate distribution revenue decoupling mechanism.

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Delaware

Gas Cost Rates

DPL makes an annual Gas Cost Rate (GCR) filing with the DPSC for the purpose of allowing DPL to recover natural gas procurement costs through customer rates. In August 2010, DPL made its 2010 GCR filing, which proposes rates that would allow DPL to recover an amount equal to a two-year amortization of currently under-recovered natural gas costs. In October 2010, the DPSC issued an order allowing DPL to place the new rates into effect on November 1, 2010, subject to refund and pending final DPSC approval. The effect of the proposed two-year amortization upon rates is an increase of 0.1% in the level of GCR. The parties in the proceeding submitted a proposed settlement to the hearing examiner on June 3, 2011, which includes the first year of DPL’s two-year amortization but provides that DPL will forego the interest ($171,000 for the 2011 to 2012 period covered by the GCR and $171,000 for the 2012 to 2013 period covered by the GCR) associated with that amortization. The proposed settlement was approved by the DPSC on October 18, 2011.

In August 2011, DPL made its 2011 GCR filing. The filing includes the second year of the effect of the proposed two-year amortization as proposed in DPL’s 2010 filing. On September 20, 2011, the DPSC issued an order allowing DPL to place the new rates into effect on November 1, 2011, subject to refund and pending final DPSC approval.

Natural Gas Distribution Base Rates

In July 2010, DPL submitted an application with the DPSC to increase its natural gas distribution base rates. As subsequently amended, the filing sought approval of an annual rate increase of approximately $10.2 million, based on a requested return on equity (ROE) of 11.0%, and requests approval of implementation of the MFVRD. As permitted by Delaware law, DPL placed an annual increase of approximately $2.5 million into effect, on a temporary basis, on August 31, 2010, and the remainder of approximately $7.7 million of the requested increase was placed into effect on February 2, 2011, in each case subject to refund and pending final DPSC approval. On June 21, 2011, the DPSC approved a settlement providing for an annual rate increase of approximately $5.8 million, based on an ROE of 10.0%. The decision deferred the implementation of the MFVRD until an implementation plan and a customer education plan are developed. As of December 31, 2011, the amount collected in excess of the approved rate has been refunded to customers through a bill credit.

Electric Distribution Base Rates

On December 2, 2011, DPL submitted an application with the DPSC to increase its electric distribution base rates. The filing seeks approval of an annual rate increase of approximately $31.8 million, based on a requested ROE of 10.75%, and requests approval of implementation of the MFVRD. DPL has requested that the rates become effective on January 31, 2012. In the effort to reduce the shortfall in revenues due to the delay in time or lag between when costs are incurred and when they are reflected in rates (regulatory lag), the filing includes a request for the DPSC to approve a reliability investment recovery mechanism (RIM) to recover reliability-related capital expenditures incurred between base rate cases. Through the RIM, DPL would collect in a surcharge the amount of its reliability-related capital expenditures based on its budget for the current year. The budgeted amount would be reconciled with actual capital expenditures on an annual basis and any over-recovery or under-recovery would be reflected in the next year’s surcharge. The work undertaken pursuant to the RIM would be subject to a prudency review by the DPSC in the next base rate case or at more frequent intervals as determined by the DPSC. DPL’s operating and maintenance costs and other capital expenditures would remain subject to recovery through the traditional ratemaking process. DPL has also requested DPSC approval of the use of fully forecasted test years in future DPL rate cases. On January 10, 2012, the DPSC entered an order suspending the full increase and

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allowing a temporary rate increase of $2.5 million to go into effect on January 31, 2012, subject to refund and pending final DPSC approval. As permitted by Delaware law, DPL intends to place the remainder of approximately $29.3 million of the requested increase into effect on July 2, 2012, subject to refund and pending final DPSC approval.

Maryland

Electric Distribution Base Rates

On December 9, 2011, DPL submitted an application with the MPSC to increase its electric distribution base rates. The filing seeks approval of an annual rate increase of approximately $25.2 million, based on a requested ROE of 10.75%. In the effort to reduce regulatory lag, the filing includes a request for the MPSC to approve a RIM to recover reliability-related capital expenditures incurred between base rate cases. Through the RIM, DPL would collect in a surcharge the amount of its reliability-related capital expenditures based on its budget for the current year. The budgeted amount would be reconciled with actual capital expenditures on an annual basis and any over-recovery or under-recovery would be reflected in the next year’s surcharge. The work undertaken pursuant to the RIM would be subject to a prudency review by the MPSC in the next base rate case or at more frequent intervals as determined by the MPSC. DPL’s operating and maintenance costs and other capital expenditures would remain subject to recovery through the traditional ratemaking process. DPL has also requested MPSC approval of the use of fully forecasted test years in future DPL rate cases. A decision by the MPSC is expected in July 2012.

Major Storm Damage Recovery Proceedings

In February 2011, the MPSC initiated proceedings involving DPL, as well as Pepco and unaffiliated utilities in Maryland, for the purpose of reviewing how the BSA operates to recover revenues lost as a result of major storm outages. On January 25, 2012, the MPSC issued an order modifying the BSA to prevent DPL from collecting lost utility revenue through the BSA if electric service is not restored to the pre-major storm levels within 24 hours of the start of a major storm (defined by the MPSC as a weather-related event during which more than the lesser of 10% or 100,000 of an electric utility’s customers have a sustained outage for more than 24 hours). The period for which the lost utility revenue may not be collected through the BSA commences 24 hours after the start of the major storm and continues until all major storm-related outages are restored. The MPSC stated that waivers permitting collection of BSA revenues would be granted in rare and extraordinary circumstances where a utility can show that an outage was not due to inadequate emphasis on reliability and restoration efforts were reasonable under the circumstances. The financial impact of service interruptions due to a major storm as a result of this MPSC order would generally depend on the scope and duration of the outages.

(8) LEASING ACTIVITIES

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 $93 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, 2011, are $12 million in 2012, $11 million in each of the years 2013 through 2015, $9 million in 2016, and $108 million thereafter.

Rental expense for operating leases, including the Merrill Creek Reservoir lease, was $11 million, $10 million and $9 million for the years ended December 31, 2011, 2010 and 2009, respectively.

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(9) 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, 2011
Distribution	$	1,580	$	435	$	1,145
Transmission		788		230		558
Gas		429		133		296
Construction work in progress		151		—		151
Non-operating and other property		240		128		112
Total	$	3,188	$	926	$	2,262
At December 31, 2010
Distribution	$	1,515	$	431	$	1,084
Transmission		740		219		521
Gas		413		125		288
Construction work in progress		124		—		124
Non-operating and other property		208		126		82
Total	$	3,000	$	901	$	2,099

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.

(10) PENSION AND OTHER POSTRETIREMENT BENEFITS

DPL accounts for its participation in its parent’s single-employer plans, the Pepco Holdings Inc. Retirement Plan (the PHI Retirement Plan) and the Pepco Holdings, Inc. Welfare Plan for Retirees (the PHI OPEB Plan), as participation in multiemployer plans. For 2011, 2010 and 2009, DPL was responsible for $23 million, $28 million and $25 million, respectively, of the pension and other postretirement net periodic benefit cost incurred by PHI. On January 31, 2012, DPL made a discretionary tax-deductible contribution in the amount of $85 million to the PHI Retirement Plan. DPL made discretionary, tax-deductible contributions of $40 million and $10 million to the PHI Retirement Plan for the years ended December 31, 2011 and 2009, respectively. No contribution was made for the year ended December 31, 2010. In addition, DPL made contributions of $6 million, $9 million and $10 million, respectively, to the PHI OPEB Plan for the years ended December 31, 2011, 2010 and 2009. At December 31, 2011 and 2010, DPL’s Prepaid pension expense of $162 million and $139 million, and Other postretirement benefit obligations of $22 million and $22 million, effectively represent assets and benefit obligations resulting from DPL’s participation in the PHI benefit plans.

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(11) DEBT

Long-Term Debt

Long-term debt outstanding as of December 31, 2011 and 2010 is presented below:

Type of Debt	Interest Rate	Maturity	2011			2010
			(millions of dollars)
First Mortgage Bonds
	6.40%	2013	$	250		$	250
	5.22%(a)	2016		100			100
	5.20%(a)	2019		31			31
	0.75%-4.90%(a)(b)	2026		35			35
				416			416
Unsecured Tax-Exempt Bonds
	1.80%(c)	2025		15			15
	2.30%(d)	2028		16			16
	5.40%	2031		78			78
				109			109
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%	2014		100			100
	5.00%	2015		100			100
				200			200
Total long-term debt				765			765
Other long-term debt				—			1
Net unamortized discount				—			(1	)
Current portion of long-term debt				(66	)		(35	)
Total net long-term debt			$	699		$	730

(a) Represents a series of First Mortgage Bonds issued by DPL (Collateral First Mortgage Bonds) as collateral for an outstanding series of senior notes issued by the company or tax-exempt bonds issued for the benefit of the company. The maturity date, optional and mandatory prepayment provisions, if any, interest rate, and interest payment dates on each series of senior notes or the obligations in respect of the tax-exempt bonds are identical to the terms of the corresponding series of Collateral First Mortgage Bonds. Payments of principal and interest on a series of senior notes or the company’s obligations in respect of the tax-exempt bonds satisfy the corresponding payment obligations on the related series of Collateral First Mortgage Bonds. Because each series of senior notes and tax-exempt bonds and the corresponding series of Collateral First Mortgage Bonds securing that series of senior notes or tax-exempt bonds effectively represents a single financial obligation, the senior notes and the tax-exempt bonds are not separately shown on the table.

(b) These bonds bearing an interest note of 4.90% were repurchased. On June 1, 2011, DPL resold these bonds that were subject to mandatory repurchase on May 1, 2011 at an interest rate of 0.75%. The bonds are currently subject to mandatory tender on June 1, 2012.

(c) On July 1, 2010, DPL purchased this series of tax-exempt bonds issued for the benefit of DPL by the Delaware Economic Development Authority (DEDA) pursuant to a mandatory repurchase provision in the indenture for the bonds that was triggered by the expiration of the original interest period for the bonds. While DPL held the bonds, they remained outstanding as a contractual matter, but were considered extinguished for accounting purposes. On December 1, 2010, DPL resold the bonds to the public, at which time the interest rate on the bonds was changed from 5.50% to a fixed rate of 1.80%. The bonds are subject to mandatory purchase by DPL on June 1, 2012.

(d) On July 1, 2010, DPL purchased this series of tax-exempt bonds issued for the benefit of DPL by DEDA pursuant to a mandatory repurchase provision in the indenture for the bonds that was triggered by the expiration of the original interest period for the bonds. While DPL held the bonds, they remained outstanding as a contractual matter, but were considered extinguished for accounting purposes. On December 1, 2010, DPL resold the bonds to the public, at which time the interest rate on the bonds was changed from 5.65% to a fixed rate of 2.30%. The bonds are subject to mandatory purchase by DPL on June 1, 2012.

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The outstanding First Mortgage Bonds issued by DPL are subject to a lien on substantially all of DPL’s property, plant and equipment.

Maturities of long-term debt during the next five years are as follows: $66 million in 2012, $250 million in 2013, $100 million in 2014, $100 million in 2015, $100 million in 2016, and $149 million thereafter.

DPL’s long-term debt is subject to certain covenants. As of December 31, 2011, DPL is in compliance with all such covenants.

Tax-Exempt Bonds

On June 1, 2011, DPL resold $35 million of Pollution Control Refunding Revenue Bonds (Delmarva Power & Light Company Project) Series 2001C due 2026 (the “Series 2001C Bonds”). The Series 2001C Bonds were issued for the benefit of DPL in 2001 and were repurchased by DPL on May 2, 2011, pursuant to a mandatory repurchase provision in the indenture for the Series 2001C Bonds triggered by the expiration of the original interest rate period specified by the Series 2001C Bonds.

In connection with the issuance of the Series 2001C Bonds, DPL entered into a continuing disclosure agreement under which it is obligated to furnish certain information to the bondholders. At the time of the resale, the continuing disclosure agreement was amended and restated to designate the Municipal Securities Rulemaking Board as the sole repository for these continuing disclosure documents. The amendment and restatement of the continuing disclosure agreement did not change the operating or financial data that is required to be provided by DPL under such agreement.

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. A detail of the components of DPL’s short-term debt at December 31, 2011 and 2010 is as follows:

	2011		2010
	(millions of dollars)
Variable rate demand bonds	$	105	$	105
Commercial paper		47		—
	$	152	$	105

Commercial Paper

DPL has an ongoing commercial paper program of up to $500 million that is backed by its borrowing capacity under PHI’s $1.5 billion credit facility, which is described below under the heading Credit Facility.

DPL had $47 million of commercial paper outstanding at December 31, 2011 and zero outstanding at December 31, 2010. The weighted average interest rates for commercial paper issued during 2011 and 2010 were 0.34%. The weighted average maturity of all commercial paper issued by DPL during 2011 and 2010 was two days.

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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 GAAP. 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 credit worthiness of the company and because the remarketing agent resets the interest rate to the then-current market rate. The bonds maybe 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 2011 mature as follows: 2017 ($26 million), 2024 ($33 million), 2028 ($16 million), and 2029 ($30 million). The weighted average interest rate for VRDBs was 0.53% during 2011 and 0.52% during 2010. Of the $105 million in VRDBs, $72 million of DPL’s obligations are secured by Collateral First Mortgage Bonds, which provide collateral to the investors in the event of a default by DPL.

Credit Facility

PHI, Potomac Electric Power Company (Pepco), DPL and Atlantic City Electric Company (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 commercial paper programs. On August 1, 2011, PHI, Pepco, DPL and ACE entered into an amended and restated credit agreement with respect to the facility, which among other changes, extended the expiration date of the facility to August 1, 2016.

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 initial credit sublimit for PHI is $750 million 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 one month 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 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 financial covenants under this facility as of December 31, 2011.

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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.

At December 31, 2011 and 2010, the amount of cash, plus borrowing capacity under the PHI credit facility available to meet the liquidity needs of PHI’s utility subsidiaries was $711 million and $462 million, respectively.

(12) 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,
	2011			2010			2009
	(millions of dollars)
Current Tax (Benefit) Expense
Federal	$	(22	)	$	(37	)	$	(26	)
State and local		8			(5	)		(17	)
Total Current Tax Benefit		(14	)		(42	)		(43	)
Deferred Tax Expense (Benefit)
Federal		53			61			58
State and local		4			13			2
Investment tax credit amortization		(1	)		(1	)		(1	)
Total Deferred Tax Expense		56			73			59
Total Income Tax Expense	$	42		$	31		$	16

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Reconciliation of Income Tax Expense

	For the Year Ended December 31,
	2011					2010					2009
	(millions of dollars)
Income tax at Federal statutory rate	$	40		35.0	%	$	27		35.0	%	$	24		35.0	%
Increases (decreases) resulting from Depreciation		1		0.9	%		1		1.3	%		2		2.9	%
State income taxes, net of Federal effect		6		5.3	%		4		5.3	%		4		5.9	%
State tax benefit related to prior years’ asset dispositions		—		—			—		—			(13	)	(19.1	)%
Investment tax credits		(1	)	(0.9	)%		(1	)	(1.3	)%		(1	)	(1.5	)%
Change in estimates and interest related to uncertain and effectively settled tax positions		(3	)	(2.7	)%		1		1.3	%		(1	)	(1.5	)%
Adjustments to prior years’ taxes		—		—			—		—			2		2.9	%
Deferred tax basis adjustments		(1	)	(0.9	)%		—		—			—		—
Other, net		—		0.5	%		(1	)	(0.8	)%		(1	)	(1.1	)%
Income Tax Expense	$	42		37.2	%	$	31		40.8	%	$	16		23.5	%

Year ended December 31, 2011

During 2011, PHI reached a settlement with the Internal Revenue Service (IRS) with respect to interest due on its federal tax liabilities related to the November 2010 audit settlement for years 1996 through 2002. In connection with this agreement, PHI reallocated certain amounts that have been on deposit with the IRS since 2006 among liabilities in the settlement years and subsequent years. Primarily related to the settlement and reallocations, DPL recorded an additional $4 million (after-tax) interest benefit. This is partially offset by adjustments recorded in the third quarter of 2011 related to DPL’s settlement with the state taxing authorities resulting in $1 million (after-tax) of additional tax expense and the recalculation of interest on its uncertain tax positions for open tax years based on different assumptions related to the application of its deposit made with the IRS in 2006. This resulted in an additional tax expense of $1 million (after-tax).

Year ended December 31, 2010

In November 2010, PHI reached final settlement with the IRS with respect to its Federal tax returns for the years 1996 to 2002. In connection with the settlement, PHI reallocated certain amounts on deposit with the IRS since 2006 among liabilities in the settlement years and subsequent years. In light of the settlement and reallocations, DPL recalculated the estimated interest due for the tax years 1996 to 2002. The revised estimate resulted in an additional $3 million (after-tax) of estimated interest due to the IRS. This additional estimated interest expense was recorded in the fourth quarter of 2010. This expense is partially offset by the reversal of $2 million of previously recorded tax liabilities.

Year ended December 31, 2009

During 2009, DPL recorded a decrease to tax expense of $13 million resulting from the receipt of a refund of $6 million (after-tax) of state income taxes and the establishment of a state income tax benefit carry forward of $7 million (after-tax), related to a change in tax reporting for certain asset dispositions occurring in prior years.

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In March 2009, the IRS issued a Revenue Agent’s Report for the audit of PHI’s consolidated Federal income tax returns for the calendar years 2003 to 2005. The IRS has proposed adjustments to PHI’s tax returns, including adjustments to DPL’s capitalization of overhead costs for tax purposes and the deductibility of certain DPL casualty losses. In conjunction with PHI, DPL has appealed certain of the proposed adjustments and believes it has adequately reserved for the adjustments included in the Revenue Agent’s Report.

In November 2009, DPL received a refund of prior years’ Federal income taxes of $10 million. The refund results from the carryback of a 2008 net operating loss for tax reporting purposes that reflected, among other things, significant tax deductions related to accelerated depreciation, the pension plan contributions paid in 2009 (which were deducted in 2008) and the cumulative effect of adopting a new method of tax reporting for certain repairs.

Components of Deferred Income Tax Liabilities (Assets)

	As of December 31,
	2011			2010
	(millions of dollars)
Deferred Tax Liabilities (Assets)
Depreciation and other basis differences related to plant and equipment	$	526		$	475
Deferred taxes on amounts to be collected through future rates		14			14
State net operating losses		(57	)		(9	)
Pension and other postretirement benefits		86			53
Other		34			16
Total Deferred Tax Liabilities, net		603			549
Deferred tax assets included in Other Current Assets		11			13
Deferred tax liabilities included in Other Current Liabilities		1			(1	)
Total Deferred Tax Liabilities, net non-current	$	615		$	561

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, 2011 and 2010.

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 continues to be amortized to income over the useful lives of the related property.

Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits

	2011			2010			2009
	(millions of dollars)
Beginning balance as of January 1,	$	40		$	39		$	54
Tax positions related to current year:
Additions		—			3			—
Tax positions related to prior years:
Additions		7			5			10
Reductions		(12	)		(7	)		(25	)
Settlements		—			—			—
Ending balance as of December 31,	$	35		$	40		$	39

277

DPL

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, 2011, DPL had no 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 the years ended December 31, 2011, 2010 and 2009, DPL recognized $6 million of pre-tax interest income ($4 million after-tax), $6 million of pre-tax interest expense ($4 million after-tax), and $3 million of pre-tax interest income ($2 million after-tax), respectively, as a component of income tax expense. As of December 31, 2011, 2010 and 2009, DPL had accrued interest receivable of $1 million and accrued interest payable of $5 million and $1 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. The final settlement of the 2003 to 2005 Federal audit, the methodology change for deduction of capitalized construction costs, or state audits could impact the balances and related interest accruals significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.

Tax Years Open to Examination

DPL, as an indirect subsidiary of PHI, is included on PHI’s consolidated Federal tax return. DPL’s Federal income tax liabilities for all years through 2002 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.

Other Taxes

Taxes other than income taxes for each year are shown below. These amounts are recoverable through rates.

	2011		2010		2009
	(millions of dollars)
Gross Receipts/Delivery	$	15	$	16	$	17
Property		19		19		18
Environmental, Use and Other		3		2		—
Total	$	37	$	37	$	35

278

DPL

(13) DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

DPL uses derivative instruments in the form of swaps and over-the-counter options primarily to reduce natural gas commodity price volatility and 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. DPL’s capacity contracts are not classified as derivatives. 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, 2011 and 2010:

	As of December 31, 2011
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)	$	—	$	—		$	—		$	—	$	—
Derivative assets (non-current assets)		—		—			—			—		—
Total Derivative assets		—		—			—			—		—
Derivative liabilities (current liabilities)		—		(14	)		(14	)		2		(12	)
Derivative liabilities (non-current liabilities)		—		(3	)		(3	)		—		(3	)
Total Derivative liabilities		—		(17	)		(17	)		2		(15	)
Net Derivative (liability) asset	$	—	$	(17	)	$	(17	)	$	2	$	(15	)

	As of December 31, 2010
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)	$	—		$	—		$	—		$	—	$	—
Derivative assets (non-current assets)		—			—			—			—		—
Total Derivative assets		—			—			—			—		—
Derivative liabilities (current liabilities)		(6	)		(15	)		(21	)		6		(15	)
Derivative liabilities (non-current liabilities)		—			(8	)		(8	)		—		(8	)
Total Derivative liabilities		(6	)		(23	)		(29	)		6		(23	)
Net Derivative (liability) asset	$	(6	)	$	(23	)	$	(29	)	$	6	$	(23	)

279

DPL

Under FASB guidance on the offsetting of balance sheet accounts (ASC 210), DPL offsets the fair value amounts recognized for derivative instruments and fair value amounts recognized for related collateral positions executed with the same counterparty under master netting agreements. The amount of cash collateral that was offset against these derivative positions is as follows:

	December 31, 2011		December 31, 2010
	(millions of dollars)
Cash collateral pledged to counterparties with the right to reclaim	$	2	$	6

As of December 31, 2011 and 2010, all DPL 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

All premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all of DPL’s gains and losses related to hedging activities, are deferred under FASB guidance on regulated operations until recovered from customers based on the fuel adjustment clause approved by the DPSC. The following table indicates the net unrealized derivative losses arising during the period included in Regulatory assets and the realized losses recognized in the statements of income for the years ended December 31, 2011, 2010 and 2009 associated with cash flow hedges:

	For the Year Ended December 31,
	2011			2010			2009
	(millions of dollars)
Net unrealized losses arising during the period included in Regulatory assets	$	—		$	(9	)	$	(20	)
Net realized losses recognized in Purchased energy or Gas purchased		(5	)		(13	)		(41	)

As of December 31, 2011 and 2010, DPL had the following outstanding commodity forward contracts that were entered into to hedge forecasted transactions:

	Quantities
Commodity	December 31, 2011		December 31, 2010
Forecasted purchases hedges:
Natural gas (One Million British Thermal Units (MMBtu))		—		1,840,000

Effective October 1, 2011, DPL elected to no longer apply cash flow hedge accounting to its natural gas derivatives. These derivatives will continue to be employed as part of DPL’s natural gas hedging activities under the hedging program approved by the DPSC, and their dedesignation as cash flow hedges has not resulted in a change to the historical financial statement presentation because all of DPL’s gains and losses on these derivatives are recoverable from customers through the fuel adjustment clause approved by the DPSC.

280

DPL

Other Derivative Activity

DPL holds certain derivatives that are not in hedge accounting relationships nor are they designated as normal purchases or normal sales. These derivatives are recorded at fair value on the balance sheets with changes in the fair value recorded in income. In accordance with FASB guidance on regulated operations, offsetting regulatory liabilities or regulatory assets 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. For the years ended December 31, 2011, 2010 and 2009, the net unrealized derivative losses arising during the period included in Regulatory assets and the net realized losses recognized in the statements of income are provided in the table below:

	For the Year Ended December 31,
	2011			2010			2009
	(millions of dollars)
Net unrealized losses arising during the period included in Regulatory assets	$	(13	)	$	(20	)	$	(18	)
Net realized losses recognized in Purchased energy or Gas purchased		(22	)		(26	)		(11	)

As of December 31, 2011 and 2010, DPL had the following net outstanding natural gas commodity forward contracts that did not qualify for hedge accounting:

	December 31, 2011				December 31, 2010
Commodity	Quantity		Net Position		Quantity		Net Position
Natural Gas (MMBtu)		6,161,200		Long		8,236,500		Long

Contingent Credit Risk Features

The primary contracts used by DPL for derivative transactions are entered into under the International Swaps and Derivatives Association Master Agreement (ISDA) or similar agreements that closely mirror the principal credit provisions of the ISDA. The ISDAs include a Credit Support Annex (CSA) that governs the mutual posting and administration of collateral security. The failure of a party to comply with an obligation under the CSA, including an obligation to transfer collateral security when due or the failure to maintain any required credit support, constitutes an event of default under the ISDA for which the other party may declare an early termination and liquidation of all transactions entered into under the ISDA, including foreclosure against any collateral security. In addition, some of the ISDAs have cross default provisions under which a default by a party under another commodity or derivative contract, or the breach by a party of another borrowing obligation in excess of a specified threshold, is a breach under the ISDA.

The collateral requirements under the ISDA or similar agreements generally work as follows. The parties establish a dollar threshold of unsecured credit for each party in excess of which the party would be required to post collateral to secure its obligations to the other party. The amount of the unsecured credit threshold varies according to the senior, unsecured debt rating of the respective parties or that of a guarantor of the party’s obligations. The fair values of all transactions between the parties are netted under the master netting provisions. Transactions may include derivatives accounted for on-balance sheet as well as normal purchases and normal sales that are accounted for off-balance sheet. If the aggregate fair value of the transactions in a net loss position exceeds the unsecured credit threshold, then collateral is required to be posted in an amount equal to the amount by which the unsecured credit threshold is exceeded. The obligations of DPL are stand-alone obligations without the guaranty of PHI. If DPL’s credit rating were to fall below “investment grade,” the unsecured credit threshold would typically be set at zero and collateral would be required for the entire net loss position. Exchange-traded contracts are required to be fully collateralized without regard to the credit rating of the holder.

281

DPL

The gross fair value of DPL’s derivative liabilities, excluding the impact of offsetting transactions or collateral under master netting agreements, with credit-risk-related contingent features on December 31, 2011 and 2010, was $15 million and $23 million, respectively. As of those dates, DPL had posted no cash collateral in the normal course of business against the gross derivative liability resulting in a net liability of $15 million and $23 million, respectively, before giving effect to offsetting transactions that are encompassed within master netting agreements that would reduce this amount. DPL’s net settlement amount in the event of a downgrade of DPL below investment grade as of December 31, 2011 and 2010, would have been approximately $15 million and $37 million, respectively, after taking into account the master netting agreements.

DPL’s primary sources for posting cash collateral or letters of credit are PHI’s credit facilities. At December 31, 2011 and 2010, the aggregate amount of cash plus borrowing capacity under the credit facilities available to meet the liquidity needs of PHI’s utility subsidiaries was $711 million and $462 million, respectively.

(14) FAIR VALUE DISCLOSURES

Financial Instruments Measured at Fair Value on a Recurring Basis

DPL applies FASB guidance on fair value measurement and disclosures (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). 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 New York Mercantile Exchange (NYMEX).

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 internally developed 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 include significant inputs that are generally less observable than those from objective sources. Level 3 includes those financial instruments that are valued using models or other valuation methodologies.

282

DPL

Derivative instruments categorized as level 3 include natural gas options purchased by DPL as part of a natural gas hedging program approved by the DPSC. The valuation of the options is based, in part, on internal volatility assumptions extracted from historical NYMEX prices over a certain period of time.

Executive deferred compensation plan assets and liabilities that are classified as level 3 include certain life insurance policies that are valued using the cash surrender value of the policies, net of loans against those policies, which does not represent a quoted price in an active market.

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, 2011 and 2010. 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, 2011
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
Executive deferred compensation plan assets
Money Market Funds	$	2	$	2	$	—	$	—
Life Insurance Contracts		1		—		—		1
	$	3	$	2	$	—	$	1
LIABILITIES
Derivative instruments (b)
Natural Gas (c)	$	17	$	2	$	—	$	15
	$	17	$	2	$	—	$	15

(a) There were no significant transfers of instruments between level 1 and level 2 valuation categories.

(b) The fair value of derivative liabilities reflect netting by counterparty before the impact of collateral.

(c) Represents natural gas options purchased by DPL as part of a natural gas hedging program approved by the DPSC.

283

DPL

	Fair Value Measurements at December 31, 2010
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
Executive deferred compensation plan assets
Money Market Funds	$	2	$	2	$	—	$	—
Life Insurance Contracts		1		—		—		1
	$	3	$	2	$	—	$	1
LIABILITIES
Derivative instruments (b)
Natural Gas (c)	$	29	$	6	$	—	$	23
	$	29	$	6	$	—	$	23

(a) There were no significant transfers of instruments between level 1 and level 2 valuation categories.

(b) The fair value of derivative liabilities reflect netting by counterparty before the impact of collateral.

(c) Represents natural gas options purchased by DPL as part of a natural gas hedging program approved by the DPSC.

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, 2011 and 2010 are shown below:

	Year Ended December 31, 2011
	Natural Gas			Life Insurance Contracts
	(millions of dollars)
Beginning balance as of January 1, 2011	$	(23	)	$	1
Total gains (losses) (realized and unrealized):
Included in income		—			—
Included in accumulated other comprehensive loss		—			—
Included in regulatory liabilities		(10	)		—
Purchases		—			—
Issuances		—			—
Settlements		18			—
Transfers in (out) of Level 3		—			—
Ending balance as of December 31, 2011	$	(15	)	$	1

284

DPL

	Year Ended December 31, 2010
	Natural Gas			Life Insurance Contracts
	(millions of dollars)
Beginning balance as of January 1, 2010	$	(29	)	$	1
Total gains (losses) (realized and unrealized):
Included in income		—			—
Included in accumulated other comprehensive loss		—			—
Included in regulatory liabilities		(20	)		—
Purchases		—			—
Issuances		—			—
Settlements		26			—
Transfers in (out) of Level 3		—			—
Ending balance as of December 31, 2010	$	(23	)	$	1

Other Financial Instruments

The estimated fair values of DPL’s issued debt and equity instruments as of December 31, 2011 and 2010 are shown below:

	December 31, 2011				December 31, 2010
	(millions of dollars)
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	765	$	834	$	765	$	822

The fair value of long-term debt was based on actual trade prices (where available), bid prices obtained from brokers and validated by PHI, or a discounted cash flow model. Prices obtained from brokers include observable market data on the target security or historical correlation and direct observation methodologies of similar debt securities.

The carrying amounts of all other financial instruments in the accompanying financial statements approximate fair value.

(15) COMMITMENTS AND CONTINGENCIES

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, 2011 are summarized as follows:

285

DPL

	Transmission and Distribution		Legacy Regulated Generation			Other		Total
	(millions of dollars)
Beginning balance as of January 1	$	1	$	5		$	2	$	8
Accruals		—		—			—		—
Payments		—		(1	)		—		(1	)
Ending balance as of December 31		1		4			2		7
Less amounts in Other Current Liabilities		1		1			2		4
Amounts in Other Deferred Credits	$	—	$	3		$	—	$	3

Ward Transformer Site

In April 2009, a group of potentially responsible parties (PRPs) with respect to the Ward Transformer site in Raleigh, North Carolina, filed a complaint in the U.S. District Court for the Eastern District of North Carolina, alleging cost recovery and/or contribution claims against a number of entities, including DPL, with respect to past and future response costs incurred by the PRP group in performing a removal action at the site. In a March 2010 order, the court denied the defendants’ motion to dismiss. The next step in the litigation will be the filing of summary judgment motions regarding liability for certain “test case” defendants other than DPL. The case has been stayed as to the remaining defendants pending rulings upon the test cases. Although DPL cannot at this time estimate an amount or range of reasonably possible losses to which it may be exposed, DPL does not believe that it had extensive business transactions, if any, with the Ward Transformer site and therefore, costs incurred to resolve this matter are not expected to be material.

Indian River Oil Release

In 2001, DPL entered into a consent agreement 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 resulting from an oil release at the Indian River generating facility, which was sold in June 2001. The amount of remediation costs accrued for this matter is included in the table above under the column entitled Legacy Regulated Generation.

Contractual Obligations

As of December 31, 2011, DPL’s contractual obligations under non-derivative fuel and power purchase contracts were $65 million in 2012, $129 million in 2013 to 2014, $133 million in 2015 to 2016, and $268 million in 2017 and thereafter.

(16) 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 causal 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, 2011, 2010 and 2009 were $133 million, $139 million and $130 million, respectively.

286

DPL

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,
	2011		2010			2009
	(millions of dollars)
Income (Expense)
Purchased power under Default Electricity Supply contracts with Conectiv Energy Supply, Inc. (a)(b)	$	1	$	(103	)	$	(88	)
Intercompany lease transactions (c)		5		7			7
Transcompany pipeline gas purchases with Conectiv Energy Supply, Inc. (b)(d)		—		(1	)		(1	)

(a) Included in purchased energy expense.

(b) During 2010, PHI disposed of its Conectiv Energy segment and a third party assumed Conectiv Energy Supply, Inc.’s responsibilities under these contracts.

(c) Included in electric revenue.

(d) Included in gas purchased expense.

As of December 31, 2011 and 2010, DPL had the following balances on its balance sheets due (to) from related parties:

	2011			2010
	(millions of dollars)
(Liability) Asset
(Payable to) Receivable from Related Party (current) (a)
PHI Service Company	$	(20	)	$	(19	)
Conectiv Energy Supply, Inc.		(1	)		(13	)
Pepco Energy Services, Inc. and its subsidiaries (Pepco Energy Services) (b)		—			(2	)
Total	$	(21	)	$	(34	)
Money Pool Balance with Pepco Holdings (included in cash and cash equivalents)	$	—		$	63

(a) Included in accounts payable due to associated companies.

(b) DPL bills customers on behalf of Pepco Energy Services where customers have selected Pepco Energy Services as their alternative energy supplier.

287

DPL

(17) 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.

	2011
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(millions of dollars)
Total Operating Revenue	$	400		$	284		$	326		$	294		$	1,304
Total Operating Expenses		351			248			297			259			1,155
Operating Income		49			36			29			35			149
Other Expenses		(9	)		(9	)		(8	)		(10	)		(36	)
Income Before Income Tax Expense		40			27			21			25			113
Income Tax Expense (a)		17			5			10			10			42
Net Income	$	23		$	22		$	11		$	15		$	71

(a) Includes tax benefits of $4 million (after-tax) associated with an interest benefit related to federal tax liabilities in the second quarter and an additional tax expense of $1 million (after-tax) resulting from a recalculation of interest on uncertain tax positions for open tax years in the third quarter.

	2010
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(millions of dollars)
Total Operating Revenue	$	394		$	296		$	377		$	333		$	1,400
Total Operating Expenses (a)		358			277			352			300			1,287
Operating Income		36			19			25			33			113
Other Expenses		(9	)		(10	)		(9	)		(9	)		(37	)
Income Before Income Tax Expense		27			9			16			24			76
Income Tax Expense		13			3			7			8			31
Net Income	$	14		$	6		$	9		$	16		$	45

(a) Includes restructuring charges of $4 million and $4 million in the third and fourth quarters, respectively.

(18) RESTRUCTURING CHARGE

With the ongoing wind-down of the retail energy supply business of Pepco Energy Services and the disposition of Conectiv Energy, PHI repositioned itself as a regulated transmission and distribution company during 2010. In connection with this repositioning, PHI completed a comprehensive organizational review in 2010 that identified opportunities to streamline the organization and to achieve certain reductions in corporate overhead costs that are allocated to its operating segments, which resulted in the adoption of a restructuring plan. PHI began implementation of the plan during 2010, identifying 164 employee positions that were eliminated. The plan also included additional cost reduction opportunities that were implemented through process improvements and operational efficiencies.

In connection with the restructuring plan, DPL recorded a pre-tax restructuring charge related to its allocation of severance, pension, and health and welfare benefits for the termination of corporate services employees at PHI of $8 million in 2010. The severance, pension, and health and welfare benefits were estimated based on the years of service and compensation levels of the employees associated with the 164 eliminated positions at PHI. The restructuring charge was reflected as a separate line item in the statement of income for the year ended December 31, 2010.

288

DPL

A reconciliation of DPL’s accrued restructuring charges for the year ended December 31, 2011 is as follows:

	Year Ended December 31, 2011
	(millions of dollars)
Beginning balance as of January 1, 2011	$	7
Restructuring charge		—
Cash payments		(6	)
Ending balance as of December 31, 2011	$	1

289

ACE

Management’s Report on Internal Control over Financial Reporting

The management of 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, 2011 based on the framework in Internal Control – Integrated Framework 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, 2011.

290

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, 2011 and December 31, 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011 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 23, 2012

291

ACE

ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME

For the Year Ended December 31,	2011			2010			2009
	(millions of dollars)
Operating Revenue	$	1,268		$	1,430		$	1,351
Operating Expenses
Purchased energy		807			1,030			1,076
Other operation and maintenance		226			204			190
Restructuring charge		—			6			—
Depreciation and amortization		134			112			102
Other taxes		25			26			21
Deferred electric service costs		(63	)		(108	)		(161	)
Total Operating Expenses		1,129			1,270			1,228
Operating Income		139			160			123
Other Income (Expenses)
Interest expense		(69	)		(65	)		(67	)
Other income		2			1			2
Total Other Expenses		(67	)		(64	)		(65	)
Income Before Income Tax Expense		72			96			58
Income Tax Expense		33			43			17
Net Income	$	39		$	53		$	41

The accompanying Notes are an integral part of these Consolidated Financial Statements.

292

ACE

ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

ASSETS	December 31, 2011			December 31, 2010
	(millions of dollars)
CURRENT ASSETS
Cash and cash equivalents	$	91		$	4
Restricted cash equivalents		11			11
Accounts receivable, less allowance for uncollectible accounts of $12 million and $11 million, respectively		185			212
Inventories		25			17
Prepayments of income taxes		26			55
Income taxes receivable		5			25
Prepaid expenses and other		16			9
Total Current Assets		359			333
INVESTMENTS AND OTHER ASSETS
Regulatory assets		662			667
Prepaid pension expense		71			51
Income taxes receivable		61			59
Restricted cash equivalents		15			5
Assets and accrued interest related to uncertain tax positions		42			38
Other		14			11
Total Investments and Other Assets		865			831
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		2,548			2,443
Accumulated depreciation		(766	)		(729	)
Net Property, Plant and Equipment		1,782			1,714
TOTAL ASSETS	$	3,006		$	2,878

The accompanying Notes are an integral part of these Consolidated Financial Statements.

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ACE

ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

LIABILITIES AND EQUITY	December 31, 2011		December 31, 2010
	(millions of dollars, except shares)
CURRENT LIABILITIES
Short-term debt	$	23	$	181
Current portion of long-term debt		37		35
Accounts payable and accrued liabilities		117		120
Accounts payable due to associated companies		14		29
Taxes accrued		10		7
Interest accrued		15		13
Other		45		41
Total Current Liabilities		261		426
DEFERRED CREDITS
Regulatory liabilities		60		71
Deferred income taxes, net		698		659
Investment tax credits		7		8
Other postretirement benefit obligations		31		27
Other		20		13
Total Deferred Credits		816		778
LONG-TERM LIABILITIES
Long-term debt		832		633
Transition Bonds issued by ACE Funding		295		332
Total Long-Term Liabilities		1,127		965
COMMITMENTS AND CONTINGENCIES (NOTE 14)
REDEEMABLE SERIAL PREFERRED STOCK		—		6
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		576		516
Retained earnings		200		161
Total Equity		802		703
TOTAL LIABILITIES AND EQUITY	$	3,006	$	2,878

The accompanying Notes are an integral part of these Consolidated Financial Statements.

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ACE

ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Year Ended December 31,	2011			2010			2009
	(millions of dollars)
OPERATING ACTIVITIES
Net income	$	39		$	53		$	41
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		134			112			102
Deferred income taxes		42			49			53
Investment tax credit amortization		(1	)		(1	)		(1	)
Changes in:
Accounts receivable		26			(35	)		19
Inventories		(8	)		(2	)		—
Regulatory assets and liabilities, net		(74	)		(107	)		(183	)
Accounts payable and accrued liabilities		(18	)		(24	)		43
Pension contributions		(30	)		—			(60	)
Taxes accrued		45			(10	)		(6	)
Other assets and liabilities		16			24			(16	)
Net Cash From (Used By) Operating Activities		171			59			(8	)
INVESTING ACTIVITIES
Investment in property, plant and equipment		(138	)		(156	)		(141	)
Department Of Energy capital reimbursement awards received		4			2			—
Net other investing activities		(9	)		(3	)		—
Net Cash Used By Investing Activities		(143	)		(157	)		(141	)
FINANCING ACTIVITIES
Dividends paid to Parent		—			(35	)		(64	)
Capital contribution from Parent		60			43			129
Redemption of preferred stock		(6	)		—			—
Issuances of long-term debt		200			23			—
Reacquisitions of long-term debt		(35	)		(35	)		(32	)
(Repayments) issuances of short-term debt, net		(158	)		98			60
Net other financing activities		(2	)		1			(2	)
Net Cash From Financing Activities		59			95			91
Net Increase (Decrease) In Cash and Cash Equivalents		87			(3	)		(58	)
Cash and Cash Equivalents at Beginning of Year		4			7			65
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	91		$	4		$	7
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for interest (net of capitalized interest of $2 million, for each year presented)	$	64		$	61		$	65
Cash (received) paid for income taxes		(51	)		10			(42	)

The accompanying Notes are an integral part of these Consolidated Financial Statements.

295

ACE

ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF EQUITY

(millions of dollars, except shares)	Common Stock				Premium on Stock		Retained Earnings			Total
	Shares		Par Value
BALANCE, DECEMBER 31, 2008		8,546,017	$	26	$	344	$	166		$	536
Net Income		—		—		—		41			41
Dividends on common stock		—		—		—		(64	)		(64	)
Capital contribution from Parent		—		—		129		—			129
BALANCE, DECEMBER 31, 2009		8,546,017		26		473		143			642
Net Income		—		—		—		53			53
Dividends on common stock		—		—		—		(35	)		(35	)
Capital contribution from Parent		—		—		43		—			43
BALANCE, DECEMBER 31, 2010		8,546,017		26		516		161			703
Net Income		—		—		—		39			39
Capital contribution from Parent		—		—		60		—			60
BALANCE, DECEMBER 31, 2011		8,546,017	$	26	$	576	$	200		$	802

The accompanying Notes are an integral part of these Consolidated Financial Statements.

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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).

(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 evaluations, pension and other postretirement benefits assumptions, unbilled revenue calculations, the assessment of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of restructuring charges, recognition of changes in network service transmission rates for prior service year costs, accrual of self-insurance reserves for general and auto 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.

Storm Costs

During 2011, ACE incurred significant costs associated with Hurricane Irene that affected its service territory. Total incremental storm costs associated with Hurricane Irene were $13 million, with $8 million incurred for repair work and $5 million incurred as capital expenditures. All costs incurred for repair work were deferred as a regulatory asset to reflect the probable recovery of these storm costs. Approximately $5 million of these total incremental storm costs have been estimated for the cost of restoration services provided by outside contractors. Since the invoices for such services had not been received at December 31, 2011, actual invoices may vary from these estimates. ACE is seeking recovery of the incremental Hurricane Irene costs as discussed in Note (6), “Regulatory Matters – Regulatory Proceedings.”

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ACE

Restructuring Charge

PHI commenced a comprehensive organizational review in the second quarter of 2010 to identify opportunities to streamline the organization and to achieve certain reductions in corporate overhead costs allocated to its operating segments. The restructuring plan resulted in the elimination of 164 employee positions. ACE’s accrual of $6 million in costs associated with termination benefits was based on estimated severance costs and actuarial calculations of the present value of certain changes in pension and other postretirement benefits for terminated employees. There were no material changes to this accrual in 2011.

Network Service Transmission Rates

In May of each year, ACE provides its updated network service transmission rate to the Federal Energy Regulatory Commission (FERC) effective for the service year beginning June 1 of the current year and ending May 31 of the following year. The network service transmission rate includes a true-up for costs incurred in the prior service year that had not yet been reflected in rates charged to customers.

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 $41 million and $51 million as of December 31, 2011 and 2010, 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 its 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. Excise tax related generally to the consumption of gasoline by ACE in the normal course of business is charged to operations, maintenance or construction, and is not material.

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ACE

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in ACE’s gross revenues were $22 million, $23 million and $22 million for the years ended December 31, 2011, 2010 and 2009, 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 an asset is being used or its physical condition. A long-lived asset to be held and used is written down to 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 fair value including costs to sell.

Income Taxes

ACE, as an indirect subsidiary of PHI, is included in the consolidated federal income tax return of Pepco Holdings. 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 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.

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ACE

ACE Power Purchase Agreements

ACE is a party to three power purchase agreements (PPAs) with unaffiliated, non-utility generators (NUGs) totaling 459 megawatts. One of the agreements ends in 2016 and the other two end in 2024. ACE was 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, it applied the scope exemption from the consolidation guidance for enterprises that have not been able to obtain such information.

Net purchase activities with the NUGs for the years ended December 31, 2011, 2010 and 2009 were approximately $218 million, $292 million and $282 million, respectively, of which approximately $206 million, $270 million and $262 million, respectively, consisted of power purchases under the PPAs. The power purchase costs are recoverable from ACE’s customers through regulated rates.

Atlantic City Electric Transition Funding LLC

ACE Funding was established in 2001 by ACE 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 have been transferred to ACE in exchange for the transfer by ACE to ACE Funding of the right to collect non-bypassable transition bond charges (the Transition Bond Charges) from ACE customers pursuant to bondable stranded costs rate orders issued by the New Jersey Board of Public Utilities (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). ACE collects the Transition Bond Charges from its customers on behalf of ACE Funding and the holders of the Transition Bonds. 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 the Transition Bonds have recourse only to the assets of ACE Funding. ACE owns 100 percent of the equity of ACE Funding and consolidates ACE Funding in its financial statements as ACE is the primary beneficiary of ACE Funding under the variable interest entity consolidation guidance.

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. The SOCAs were established under a New Jersey law enacted to promote the construction of qualified electric generation facilities in New Jersey. The SOCAs are 15-year, financially settled transactions approved by the NJBPU that allow generators to receive payments from, or make payments to, ACE based on the difference between the fixed price in the SOCAs and the price for capacity that clears PJM Interconnection, LLC (PJM). Each of the other electricity distribution companies (EDCs) in New Jersey has entered into SOCAs having the same terms with the same generation companies. The annual share of payments or receipts for ACE and the other EDCs is based upon each company’s annual proportion of the total New Jersey load attributable to all EDCs. The NJBPU has approved full recovery from distribution customers of payments made by ACE and the other EDCs, and distribution customers would be entitled to any payments received by ACE and the other EDCs.

ACE and the other EDCs entered the SOCAs under protest based on concerns about the potential cost to distribution customers. In May 2011, the NJBPU denied a joint motion for reconsideration of its order requiring each of the EDCs to enter into the SOCAs. In June 2011, ACE and the other EDCs filed appeals related to the NJBPU orders with the Appellate Division of the New Jersey Superior Court. In February 2011, ACE joined other plaintiffs in an action filed in the United States District Court for the District of New Jersey challenging the constitutionality of the New Jersey law. ACE and the other plaintiffs filed a motion for summary judgment in December 2011.

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ACE

Two of the generation companies sent a notice of dispute under the SOCA to ACE. The notice of dispute alleges that certain actions taken by PJM have an adverse effect on the generation company’s ability to clear the PJM auction as required by the SOCA. In November 2011, one of the generation companies filed a petition with the NJBPU to change its SOCA. ACE does not believe that a dispute exists under the SOCAs.

Currently, PHI believes that FASB guidance on derivative accounting and the accounting for regulated operations would apply to a SOCA once capacity has cleared a PJM auction. Once cleared, the gain (loss) associated with the fair value of a derivative would be offset by the recognition of a regulatory liability (asset). The next PJM capacity auction is scheduled for May 2012.

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 Investments and 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, 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 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. Although management 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 inventory are recorded in inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed.

301

ACE

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. 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 are 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.

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. Accumulated depreciation is charged with the cost of depreciable property retired, less salvage and other recoveries. Property, plant and equipment other than electric facilities is generally depreciated on a straight-line basis over the useful lives of the assets. The system-wide composite depreciation rates for 2011, 2010 and 2009 for ACE’s transmission and distribution system property were approximately 3.0%, 2.8% and 2.8%, respectively.

In 2010, ACE received an award from the U.S. Department of Energy under the American Recovery and Reinvestment Act of 2009. ACE was awarded $19 million 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. ACE has elected to recognize the awards as a reduction in the carrying value of the assets acquired rather than grant income over the service period.

Capitalized Interest and Allowance for Funds Used During Construction

In accordance with FASB guidance on regulated operations (ASC 980), utilities can 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 $2 million in each of the years ended December 31, 2011, 2010 and 2009, respectively.

ACE recorded amounts for the equity component of AFUDC of less than $1 million for the years ended December 31, 2011 and 2010, respectively, and $1 million for the year ended December 31, 2009.

Leasing Activities

ACE’s lease transactions include plant, office space, equipment, software and vehicles. In accordance with FASB guidance on leases (ASC 840), these leases are classified as operating leases.

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ACE

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.

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 issues. 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 the PHI Retirement Plan, a non-contributory, defined benefit pension plan that covers substantially all employees of ACE and certain employees of other Pepco Holdings subsidiaries. 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 existing and future preferred stock, 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 the charter of ACE which 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 $200 million and $161 million of retained earnings available for payment of common stock dividends at December 31, 2011 and 2010, respectively. These amounts represent the total retained earnings balances at those dates.

Reclassifications and Adjustments

Certain prior period amounts have been reclassified in order to conform to current period presentation. The following adjustments have been recorded and are not considered material individually or in the aggregate:

Income Tax Expense

During 2011, ACE completed a reconciliation of its deferred taxes associated with certain regulatory assets and recorded adjustments which resulted in an increase to income tax expense of $1 million for the year ended December 31, 2011.

During 2010, ACE recorded an adjustment to correct certain income tax errors related to prior periods. The adjustment resulted in an increase in income tax expense of $6 million.

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During 2009, ACE recorded adjustments to correct certain income tax errors related to prior periods. These adjustments resulted in a decrease in income tax expense of $1 million.

(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Fair Value Measurements and Disclosures (ASC 820)

The FASB issued new disclosure requirements that require significant items within the reconciliation of the Level 3 valuation category to be presented in separate categories for purchases, sales, issuances and settlements. The guidance was effective beginning with ACE’s March 31, 2011 consolidated financial statements. ACE has included the new disclosure requirements in Note (13), “Fair Value Disclosures,” to its consolidated financial statements.

Compensation Retirement Benefits—Multiemployer Plans (ASC 715-80)

In September 2011, the FASB issued new disclosure requirements for participants in multiemployer pension and postretirement benefit plans that would be effective beginning with ACE’s December 31, 2011 financial statements. Most of these disclosures are not applicable to ACE because it participates in PHI’s single employer pension plan and accounts for it as participation in a multiemployer plan. The disclosure requirements for ACE were limited and are already provided in ACE’s Note (9), “Pension and Other Postretirement Benefits.”

(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Fair Value Measurements and Disclosures (ASC 820)

In May 2011, the FASB issued new guidance on fair value measurement and disclosures that will be effective beginning with ACE’s March 31, 2012 consolidated financial statements. The new guidance will change how fair value is measured in specific instances and expand disclosures about fair value measurements. ACE expects that it will have to provide additional disclosures, but does not expect this guidance to have a significant impact on its fair value measurements.

(5) SEGMENT INFORMATION

The company 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, 2011 and 2010 are as follows:

	2011		2010
	(millions of dollars)
Regulatory Assets
Securitized stranded costs (a)	$	481	$	559
Deferred energy supply costs (a)		105		31
Deferred income taxes		27		29
Other		49		48
Total Regulatory Assets	$	662	$	667
Regulatory Liabilities
Excess depreciation reserve	$	26	$	42
Federal and New Jersey tax benefits, related to securitized stranded costs		19		22
Deferred energy supply costs		11		—
Other		4		7
Total Regulatory Liabilities	$	60	$	71

(a) A return is generally earned on these deferrals.

A description for each category of regulatory assets and regulatory liabilities follows:

Securitized Stranded Costs: Includes contract termination payments under a contract between ACE and an unaffiliated NUG and costs associated with the regulated operations of ACE’s electricity generation business which are no longer recoverable through customer rates. The recovery of these stranded costs has been securitized through the issuance of Transition Bonds by ACE Funding. A customer surcharge is collected by ACE to fund principal and interest payments on the Transition Bonds. The stranded costs are amortized over the life of the Transition Bonds, which mature between 2013 and 2023.

Deferred Energy Supply Costs: The regulatory asset represents primarily deferred costs associated with a net under-recovery of Default Electricity Supply costs incurred by ACE that are probable of recovery in rates. The regulatory liability represents primarily deferred costs associated with a net over-recovery of Default Electricity Supply costs incurred by ACE that will be refunded to customers.

Deferred Income Taxes: Represents a receivable from our customers for tax benefits ACE previously flowed through before the company was ordered to account for 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.

Other: Represents miscellaneous regulatory assets that generally are being amortized over 1 to 20 years.

Excess Depreciation Reserve: The excess depreciation reserve was recorded as part of an ACE New Jersey rate case settlement. This excess reserve is the result of a change in estimated depreciable lives and a change in depreciation technique from remaining life to whole life that caused an over-recovery for depreciation expense from customers when the remaining life method has been used. The excess is being amortized over an 8.25 year period, which began in June 2005.

Federal and New Jersey 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.

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Other: Includes miscellaneous regulatory liabilities.

Regulatory Proceedings

Rate Proceedings

Over the last several years, ACE has proposed the adoption of a mechanism to decouple retail distribution revenue from the amount of power delivered to retail customers. A bill stabilization adjustment mechanism (BSA) proposed by ACE as part of a Phase 2 to the base rate proceeding filed in August 2009 was not included in the final settlement approved by the NJBPU on May 16, 2011. Accordingly, there is no BSA proposal currently pending in New Jersey. Under the BSA, 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.

Electric Distribution Base Rates

On August 5, 2011, ACE filed a petition with the NJBPU to increase its electric distribution rates by the net amount of approximately $58.9 million, based on a return on equity of 10.75% (the ACE 2011 Base Rate Case). The net increase consists of a rate increase proposal of approximately $70.5 million, less a deduction from base rates of approximately $17 million attributable to excess depreciation expenses, plus approximately a $4.9 million increase in sales-and-use taxes and an upward adjustment of approximately $0.5 million in the Regulatory Asset Recovery Charge. A decision in the electric distribution rate case is expected by the end of 2012.

Infrastructure Investment Program

In July 2009, the NJBPU approved certain rate recovery mechanisms in connection with ACE’s Infrastructure Investment Program (the IIP). In exchange for the increase in infrastructure investment, the NJBPU, through the IIP, allowed recovery of ACE’s infrastructure investment capital expenditures through a special rate outside the normal rate recovery mechanism of a base rate filing. The IIP was designed to stimulate the New Jersey economy and provide incremental employment in ACE’s service territory by increasing the infrastructure expenditures to a level above otherwise normal budgeted levels. In an October 18, 2011 petition (subsequently amended December 16, 2011) with the NJBPU, ACE requested an extension and expansion to the IIP under which ACE proposes to spend approximately $63 million, $94 million and $81 million in calendar years 2012, 2013 and 2014, respectively, on non-revenue reliability-related capital expenditures. As proposed, capital expenditures related to the proposed special rate would be subject to annual reconciliation and approval by the NJBPU. A decision by the NJBPU on ACE’s IIP filing is expected by the end of the third quarter 2012.

Storm Damage Restoration Costs Recovery

In August 2011, ACE filed a petition with the NJBPU seeking authorization for deferred accounting treatment of uninsured incremental storm damage restoration costs not otherwise recovered through base rates. In that petition, ACE sought deferred accounting treatment for recovery of storm costs of approximately $8 million incurred during Hurricane Irene, which impacted ACE’s service territory in the third quarter of 2011. On December 15, 2011, the request for deferral of these costs was consolidated with ACE’s pending base rate proceeding.

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(7) LEASING ACTIVITIES

ACE leases certain types of property and equipment for use in its operations. Rental expense for operating leases was $10 million, $9 million and $9 million for the years ended December 31, 2011, 2010 and 2009, respectively.

Total future minimum operating lease payments for ACE as of December 31, 2011 are $5 million in 2012, $4 million in each of the years 2013 through 2015, $3 million in 2016 and $25 million thereafter.

(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, 2011
Generation	$	10	$	9	$	1
Distribution		1,591		453		1,138
Transmission		688		206		482
Construction work in progress		87		—		87
Non-operating and other property		172		98		74
Total	$	2,548	$	766	$	1,782
At December 31, 2010
Generation	$	10	$	9	$	1
Distribution		1,511		433		1,078
Transmission		683		195		488
Construction work in progress		72		—		72
Non-operating and other property		167		92		75
Total	$	2,443	$	729	$	1,714

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 December 31, 2011 and 2010, ACE’s subsidiaries had a net book value ownership interest of $8 million and $9 million, respectively, 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.

(9) PENSION AND OTHER POSTRETIREMENT BENEFITS

ACE accounts for its participation in its parent’s single-employer plans, the Pepco Holdings, Inc. Retirement Plan (the PHI Retirement Plan) and the Pepco Holdings, Inc. Welfare Plan for Retirees (the PHI OPEB Plan), as participation in multiemployer plans. For 2011, 2010 and 2009, ACE was responsible for $21 million, $23 million and $20 million, respectively, of the pension and other postretirement net periodic benefit cost incurred by PHI. On January 31, 2012, ACE made a discretionary tax-deductible contribution in the amount of $30 million to the PHI Retirement Plan. ACE made discretionary tax-deductible contributions of $30 million and $60 million to the PHI Retirement Plan for the years ended December 31, 2011 and 2009, respectively. No contribution was made for the year ended December 31, 2010. In addition, ACE made contributions of $7 million, $8 million and $6 million, respectively, to the PHI OPEB Plan for the years ended December 31, 2011, 2010 and 2009. At December 31, 2011 and 2010, ACE’s Prepaid pension expense of $71 million and $51 million, and Other postretirement benefit obligations of $31 million and $27 million, respectively, effectively represent assets and benefit obligations resulting from ACE’s participation in the PHI benefit plans.

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(10) DEBT

Long-Term Debt

Long-term debt outstanding as of December 31, 2011 and 2010 is presented below.

Type of Debt	Interest Rate			Maturity		2011			2010
						(millions of dollars)
First Mortgage Bonds
		7.63	%		2014	$	7		$	7
		6.63	%		2013		69			69
		7.68	%		2015-2016		17			17
		7.75	%		2018		250			250
		6.80	% (a)		2021		39			39
		4.35	%		2021		200			—
		5.60	% (a)		2025		4			4
		4.875	% (a)(b)(c)		2029		23			23
		5.80	% (a)(b)		2034		120			120
		5.80	% (a)(b)		2036		105			105
Total long-term debt							834			634
Net unamortized discount							(2	)		(1	)
Current portion of long-term debt							—			—
Total net long-term debt						$	832		$	633
Transition Bonds Issued by ACE Funding
		4.21	%		2013	$	—		$	9
		4.46	%		2016		29			39
		4.91	%		2017		102			118
		5.05	%		2020		54			54
		5.55	%		2023		147			147
							332			367
Net unamortized discount							—			—
Current portion of long-term debt							(37	)		(35	)
Total net long-term Transition Bonds Issued by ACE Funding						$	295		$	332

(a) Represents a series of First Mortgage Bonds issued by ACE (Collateral First Mortgage Bonds) as collateral for an outstanding series of senior notes issued by the company or tax-exempt bonds issued by or for the benefit of ACE. The maturity date, optional and mandatory prepayment provisions, if any, interest rate, and interest payment dates on each series of senior notes or the obligations in respect of the tax-exempt bonds are identical to the terms of the corresponding series of Collateral First Mortgage Bonds. Payments of principal and interest on a series of senior notes or the company’s obligation in respect of the tax-exempt bonds satisfy the corresponding payment obligations on the related series of Collateral First Mortgage Bonds. Because each series of senior notes and tax-exempt bonds and the corresponding series of Collateral First Mortgage Bonds securing that series of senior notes or tax-exempt bonds effectively represents a single financial obligation, the senior notes and the tax-exempt bonds are not separately shown on the table.

(b) Represents a series of Collateral First Mortgage Bonds issued by ACE that will, at such time as there are no First Mortgage Bonds of ACE outstanding (other than Collateral First Mortgage Bonds securing payment of senior notes), cease to secure the corresponding series of senior notes and will be cancelled.

(c) Represents a series of Collateral First Mortgage Bonds as to which the indicated company has agreed in connection with the issuance of the corresponding series of senior notes that, notwithstanding the terms of the Collateral First Mortgage Bonds described in footnote (b) above, it will not permit the release of the Collateral First Mortgage Bonds as security for the series of senior notes for so long as the senior notes remain outstanding, unless the company delivers to the senior note trustee comparable secured obligations to secure the senior notes.

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The outstanding First Mortgage Bonds issued by ACE are subject to a lien on substantially all of ACE’s property, plant and equipment.

For a description of the Transition Bonds issued by ACE Funding, see the discussion under the heading “Consolidation of Variable Interest Entities – ACE Transition Funding, LLC” in Note (2), “Significant Accounting Policies.” The aggregate principal amount of long-term debt including Transition Bonds outstanding at December 31, 2011, that will mature in each of 2012 through 2016 and thereafter is as follows: $37 million in 2012, $108 million in 2013, $48 million in 2014, $59 million in 2015, $48 million in 2016 and $866 million thereafter.

First Mortgage Bonds

On April 5, 2011, ACE issued $200 million of 4.35% first mortgage bonds due April 1, 2021. The net proceeds were used to repay short-term debt and for general corporate purposes.

ACE’s long-term debt is subject to certain covenants. As of December 31, 2011, ACE is in compliance with all such covenants.

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. A detail of the components of ACE’s short-term debt at December 31, 2011 and 2010 is as follows:

	2011		2010
	(millions of dollars)
Commercial paper	$	—	$	158
Variable rate demand bonds		23		23
Total	$	23	$	181

Commercial Paper

ACE has an ongoing commercial paper program of up to $250 million that is backed by its borrowing capacity under PHI’s $1.5 billion credit facility, which is described below under the heading Credit Facility.

ACE had no commercial paper outstanding at December 31, 2011 and $158 million of commercial paper outstanding at December 31, 2010. The weighted average interest rates for commercial paper issued during 2011 and 2010 were 0.33% and 0.36%, respectively. The weighted average maturity of all commercial paper issued by ACE during 2011 and 2010 was six days and seven 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 GAAP. However, bonds submitted for purchase are remarketed by a remarketing agent on a best efforts basis. ACE expects that any bonds submitted for purchase will be remarketed successfully due to the credit worthiness of the company 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, ACE views VRDBs as a source of long-term financing. The VRDBs outstanding in 2011 mature as follows: 2014 ($19 million) and 2017 ($4 million). The weighted average interest rate for VRDBs was 0.18% and 0.27% during 2011 and 2010, respectively.

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Credit Facility

PHI, Potomac Electric Power Company (Pepco), Delmarva Power & Light Company (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, 2011, PHI, Pepco, DPL and ACE entered into an amended and restated credit agreement with respect to the facility, which among other changes, extended the expiration date of the facility to August 1, 2016.

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 initial credit sublimit for PHI is $750 million 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 one month 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 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 financial covenants under this facility as of December 31, 2011.

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.

At December 31, 2011 and 2010, the amount of cash, plus borrowing capacity under the PHI credit facility available to meet the liquidity needs of PHI’s utility subsidiaries was $711 million and $462 million, respectively.

(11) 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.

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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,
	2011			2010			2009
	(millions of dollars)
Current Tax (Benefit) Expense
Federal	$	(9	)	$	(5	)	$	(32	)
State and local		1			—			(3	)
Total Current Tax Benefit		(8	)		(5	)		(35	)
Deferred Tax Expense (Benefit)
Federal		35			33			42
State and local		7			16			11
Investment tax credit amortization		(1	)		(1	)		(1	)
Total Deferred Tax Expense		41			48			52
Total Consolidated Income Tax Expense	$	33		$	43		$	17

Reconciliation of Consolidated Income Tax Expense

	For the Year Ended December 31,
	2011					2010					2009
	(millions of dollars)
Income tax at Federal statutory rate	$	25		35.0	%	$	33		35.0	%	$	20		35.0	%
Increases (decreases) resulting from State income taxes, net of Federal effect		4		6.0	%		7		7.3	%		5		8.6	%
Investment tax credits		(1	)	(1.3	)%		(1	)	(1.0	)%		(1	)	(1.7	)%
Change in estimates and interest related to uncertain and effectively settled tax positions		5		6.9	%		5		5.2	%		(5	)	(8.6	)%
Adjustments to prior years’ taxes		(1	)	(1.7	)%		—		—			(1	)	(1.7	)%
Other, net		1		0.9	%		(1	)	(1.7	)%		(1	)	(2.3	)%
Consolidated Income Tax Expense	$	33		45.8	%	$	43		44.8	%	$	17		29.3	%

Year ended December 31, 2011

During 2011, PHI reached a settlement with the IRS with respect to interest due on its federal tax liabilities related to the November 2010 audit settlement for years 1996 through 2002. In connection with this agreement, PHI reallocated certain amounts that have been on deposit with the IRS since 2006 among liabilities in the settlement years and subsequent years. Primarily related to the settlement and reallocations, ACE has recorded an additional $1 million (after-tax) of interest due to the IRS. This additional interest expense was recorded in the second quarter of 2011. This is further impacted by the adjustment recorded in the third quarter of 2011 related to the recalculation of interest on its uncertain tax positions for open tax years using different assumptions related to the application of its deposit made with the IRS in 2006. This resulted in an additional tax expense of $3 million (after-tax).

Year ended December 31, 2010

In November 2010, PHI reached final settlement with the IRS with respect to its federal tax returns for the years 1996 to 2002. In connection with the settlement, PHI reallocated certain amounts on deposit with the IRS since 2006 among liabilities in the settlement years and subsequent years. In light of the

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settlement and reallocations, ACE recalculated the estimated interest due for the tax years 1996 to 2002. The revised estimate resulted in an additional $1 million (after-tax) of estimated interest due to the IRS for the tax years 1996 to 2002. This additional interest expense was recorded in the fourth quarter of 2010. In addition to this adjustment, in 2010 ACE reversed $6 million of accrued interest income on uncertain and effectively settled state income tax positions, as discussed in Note (2), “Significant Accounting Policies.” This is partially offset by $1 million of other adjustments.

Year ended December 31, 2009

In March 2009, the IRS issued a Revenue Agent’s Report for the audit of PHI’s consolidated Federal income tax returns for the calendar years 2003 to 2005. The IRS has proposed adjustments to PHI’s tax returns, including adjustments to ACE’s capitalization of overhead costs for tax purposes and the deductibility of certain ACE casualty losses. In conjunction with PHI, ACE has appealed certain of the proposed adjustments, and believes it has adequately reserved for the adjustments proposed in the Revenue Agent’s Report.

In November 2009, ACE received a refund of prior years’ Federal income taxes of $9 million. The refund results from the carryback of PHI’s 2008 net operating loss for tax reporting purposes that reflected, among other things, significant tax deductions related to accelerated depreciation, the pension plan contributions paid in 2009 (which were deducted in 2008) and the cumulative effect of adopting a new method of tax reporting for certain repairs.

Components of Consolidated Deferred Income Tax Liabilities (Assets)

	As of December 31,
	2011		2010
	(millions of dollars)
Deferred Tax Liabilities (Assets)
Depreciation and other basis differences related to plant and equipment	$	424	$	389
Deferred taxes on amounts to be collected through future rates		11		14
Payment for termination of purchased power contracts with NUGs		53		59
Electric restructuring liabilities		137		160
Fuel and purchased energy		4		7
Other		60		20
Total Deferred Tax Liabilities, net		689		649
Deferred tax assets included in Other Current Assets		9		10
Total Consolidated Deferred Tax Liabilities, net non-current	$	698	$	659

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, 2011 and 2010.

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 continues to be amortized to income over the useful lives of the related property.

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Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits

	2011			2010			2009
	(millions of dollars)
Beginning balance as of January 1,	$	83		$	39		$	49
Tax positions related to current year:
Additions		2			50			1
Reductions		—			(1	)		—
Tax positions related to prior years:
Additions		4			—			10
Reductions		(10	)		(5	)		(21	)
Settlements		—			—			—
Ending balance as of December 31,	$	79		$	83		$	39

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, 2011, ACE had $5 million of 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, 2011, 2010 and 2009, ACE recognized $5 million of pre-tax interest expense ($3 million after-tax), $8 million of pre-tax interest expense ($5 million after-tax), and $9 million of pre-tax interest income ($6 million after-tax), respectively, as a component of income tax expense. As of December 31, 2011, 2010 and 2009, ACE had $6 million, $14 million and $19 million, respectively, of accrued interest receivable 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. The final settlement of the 2003 to 2005 federal audit, the methodology change for deduction of capitalized construction costs, or state audits could impact the balances and related interest accruals significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.

Tax Years Open to Examination

ACE, as an indirect subsidiary of PHI, is included on PHI’s consolidated Federal tax return. ACE’s Federal income tax liabilities for all years through 2002 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. As a result of the final determination of these years, ACE has filed amended state returns requesting $1 million in refunds which are subject to review by the various states.

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Other Taxes

Taxes other than income taxes for each year are shown below. These amounts are recoverable through rates.

	2011		2010		2009
	(millions of dollars)
Gross Receipts/Delivery	$	20	$	20	$	20
Property		3		3		2
Environmental, Use and Other		2		3		(1	)
Total	$	25	$	26	$	21

(12) PREFERRED STOCK

The preferred stock amounts outstanding as of December 31, 2011 and 2010 are as follows:

	Redemption Price		Shares Outstanding				December 31,
			2011		2010		2011		2010
							(millions of dollars)
4.0% Series of 1944, $100 per share par value	$	105.50		—		24,268	$	—	$	2
4.35% Series of 1949, $100 per share par value	$	101.00		—		2,942		—		—
4.35% Series of 1953, $100 per share par value	$	101.00		—		1,680		—		—
4.10% Series of 1954, $100 per share par value	$	101.00		—		20,504		—		2
4.75% Series of 1958, $100 per share par value	$	101.00		—		8,631		—		1
5.0% Series of 1960, $100 per share par value	$	100.00		—		4,120		—		1
Total Preferred Stock				—		62,145	$	—	$	6

Under the terms of the Company’s Articles of Incorporation, ACE has authority to issue up to 799,979 shares of its $100 par value Cumulative Preferred Stock. The shares of each of the series are redeemable solely at the option of the issuer. In addition, ACE has authority to issue up to two million shares of No Par Preferred Stock and three million shares of Preference Stock without par value. During 2011, ACE redeemed all of its outstanding cumulative preferred stock at the redemption prices listed in the table above.

(13) FAIR VALUE DISCLOSURES

Financial Instruments Measured at Fair Value on a Recurring Basis

ACE applies FASB guidance on fair value measurement and disclosures (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). 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:

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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 internally developed 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.

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.

Level 3 – Pricing inputs include significant inputs that are generally less observable than those from objective sources. Level 3 includes those financial investments that are valued using models or other valuation methodologies.

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, 2011 and 2010. 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, 2011
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
Treasury Fund	$	114	$	114	$	—	$	—
	$	114	$	114	$	—	$	—
LIABILITIES
Executive deferred compensation plan liabilities
Life Insurance Contracts	$	1	$	—	$	1	$	—
	$	1	$	—	$	1	$	—

(a) There were no significant transfers of instruments between level 1 and level 2 valuation categories.

315

ACE

	Fair Value Measurements at December 31, 2010
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
Treasury Fund	$	17	$	17	$	—	$	—
	$	17	$	17	$	—	$	—
LIABILITIES
Executive deferred compensation plan liabilities
Life Insurance Contracts	$	1	$	—	$	1	$	—
	$	1	$	—	$	1	$	—

(a) There were no significant transfers of instruments between Level 1 and Level 2 valuation categories.

Other Financial Instruments

The estimated fair values of ACE’s issued debt and equity instruments at December 31, 2011 and 2010 are shown below:

	December 31, 2011				December 31, 2010
	(millions of dollars)
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	832	$	1,003	$	633	$	710
Transition Bonds issued by ACE Funding		332		380		367		406
Redeemable Serial Preferred Stock		—		—		6		5

The fair value of long-term debt issued was based on actual trade prices (where available), bid prices obtained from brokers and validated by PHI, or a discounted cash flow model. Prices obtained from brokers include observable market data on the target security or historical correlation and direct observation methodologies of similar debt securities.

The fair value of Transition Bonds issued by ACE Funding, including amounts due within one year, were derived based on actual trade prices as of December 31, 2011. Bid prices obtained from brokers and validated by PHI were used at December 31, 2010, because actual trade prices were not available.

The fair value of the Redeemable Serial Preferred Stock was derived based on quoted market prices.

The carrying amounts of all other financial instruments in the accompanying financial statements approximate fair value.

(14) COMMITMENTS AND CONTINGENCIES

General Litigation

In September 2011, an asbestos complaint was filed in the New Jersey Superior Court, Law Division, against ACE (among other defendants) asserting claims under New Jersey’s Wrongful Death and Survival statutes. The complaint, filed by the estate of a decedent who was the wife of a former employee of ACE, alleges that the decedent’s mesothelioma was caused by exposure to asbestos brought home by her husband on his work clothes. Unlike the other jurisdictions to which PHI subsidiaries are subject, New Jersey courts have recognized a cause of action against a premise owner in a so-called “take home” case if it can be shown that the harm was foreseeable. In this case, the complaint seeks recovery of an unspecified amount of damages for the decedant’s past medical expenses, loss of earnings, and pain and

316

ACE

suffering between the time of injury and death, and asserts a punitive damage claim. At this time, ACE cannot estimate an amount or range of reasonably possible loss to which it may be exposed that may be associated with the claims raised in this complaint. Such an estimate of reasonably possible loss must await further internal investigation and discovery procedures.

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 ACE’s customers, 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, 2011 are summarized as follows:

	Transmission and Distribution			Legacy Regulated Generation		Other		Total
	(millions of dollars)
Beginning balance as of January 1	$	1		$	1	$	—	$	2
Accruals		—			—		—		—
Payments		(1	)		—		—		(1	)
Ending balance as of December 31		—			1		—		1
Less amounts in Other Current Liabilities		—			—		—		—
Amounts in Other Deferred Credits	$	—		$	1	$	—	$	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 (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 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 estimates the additional cost for future response measures will be approximately $6 million. ACE believes that EPA sent similar general notice letters to three other companies and various individuals.

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.

317

ACE

Ward Transformer Site

In April 2009, a group of PRPs with respect to the Ward Transformer site in Raleigh, North Carolina, filed a complaint in the U.S. District Court for the Eastern District of North Carolina, alleging cost recovery and/or contribution claims against a number of entities, including ACE, with respect to past and future response costs incurred by the PRP group in performing a removal action at the site. In a March 2010 order, the court denied the defendants’ motion to dismiss. The next step in the litigation will be the filing of summary judgment motions regarding liability for certain “test case” defendants other than. The case has been stayed as to the remaining defendants pending rulings upon the test cases. Although ACE cannot at this time estimate an amount or range of reasonably possible losses to which it may be exposed, ACE does not believe that it had extensive business transactions, if any, with the Ward Transformer site and therefore, costs incurred to resolve this matter are not expected to be material.

Price’s Pit Site

ACE owns a transmission and distribution right-of-way that traverses the Price’s Pit superfund site in Egg Harbor Township, New Jersey. EPA placed Price’s Pit on the NPL in 1983 and the New Jersey Department of Environmental Protection (NJDEP) undertook an environmental investigation to identify and implement remedial action at the site. NJDEP’s investigation revealed that landfill waste had been disposed on ACE’s right-of-way and NJDEP determined that ACE was a responsible party as the owner of a facility on which a hazardous substance has been deposited. ACE, EPA and NJDEP entered into a settlement agreement effective on August 11, 2011 to resolve ACE’s alleged liability. Under the settlement agreement, ACE made a payment of approximately $1 million (the amount accrued by ACE in 2010) to the EPA Hazardous Substance Superfund and donated a four-acre parcel of land adjacent to the site to NJDEP.

Contractual Obligations

As of December 31, 2011, ACE’s contractual obligations under non-derivative fuel and power purchase contracts were $197 million in 2012, $500 million in 2013 to 2014, $576 million in 2015 to 2016, and $1,857 million in 2017 and thereafter.

(15) 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 causal 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, 2011, 2010 and 2009 were $102 million, $100 million and $100 million, respectively.

318

ACE

In addition to the PHI Service Company charges described above, ACE’s financial statements include the following related party transactions in its Consolidated Statements of Income:

	For the Year Ended December 31,
	2011			2010			2009
	(millions of dollars)
(Expense) Income
Purchased power under Default Electricity Supply contracts with Conectiv Energy Supply, Inc. (a)(b)	$	—		$	(174	)	$	(185	)
Meter reading services provided by Millennium Account Services LLC (c)		(4	)		(4	)		(4	)
Intercompany use revenue (d)		2			2			3

(a) Included in purchased energy expense.

(b) During 2010, PHI disposed of its Conectiv Energy segment and a third party assumed Conectiv Energy Supply, Inc.’s responsibilities under those contracts.

(c) Included in other operation and maintenance expense.

(d) Included in operating revenue.

As of December 31, 2011 and 2010, ACE had the following balances on its Consolidated Balance Sheets due to related parties:

	2011			2010
	(millions of dollars)
Liability
Payable to Related Party (current) (a)
PHI Service Company	$	(12	)	$	(13	)
Conectiv Energy Supply, Inc.		—			(14	)
Other		(2	)		(2	)
Total	$	(14	)	$	(29	)

(a) Included in accounts payable due to associated companies.

During 2011, PHI, through Conectiv, LLC, made a $60 million capital contribution to ACE.

(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.

	2011
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(millions of dollars)
Total Operating Revenue	$	315		$	304		$	399		$	250		$	1,268
Total Operating Expenses		289			256			347			237			1,129
Operating Income		26			48			52			13			139
Other Expenses		(15	)		(16	)		(18	)		(18	)		(67	)
Income (Loss) Before Income Tax Expense		11			32			34			(5	)		72
Income Tax Expense (Benefit) (a)		5			14			17			(3	)		33
Net Income (Loss)	$	6		$	18		$	17		$	(2	)	$	39

(a) Includes tax expense of $1 million (after-tax) associated with interest related to federal tax liabilities in the second quarter and an additional tax expense of $3 million (after-tax) resulting from a recalculation of interest on uncertain tax positions for open tax years in the third quarter.

319

ACE

	2010
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(millions of dollars)
Total Operating Revenue	$	317		$	315		$	518		$	280		$	1,430
Total Operating Expenses (a)		296			258			451			265			1,270
Operating Income		21			57			67			15			160
Other Expenses		(16	)		(15	)		(17	)		(16	)		(64	)
Income (Loss) Before Income Tax Expense		5			42			50			(1	)		96
Income Tax Expense		7	(b)		16			20			—			43
Net (Loss) Income	$	(2	)	$	26		$	30		$	(1	)	$	53

(a) Includes restructuring charges of $3 million and $3 million in the third and fourth quarters, respectively.

(b) Includes $6 million charge for the reversal of erroneously accrued interest income on uncertain and effectively settled state income tax positions.

(17) RESTRUCTURING CHARGE

With the ongoing wind-down of the retail energy supply business of Pepco Energy Services and the disposition of Conectiv Energy, PHI repositioned itself as a regulated transmission and distribution company during 2010. In connection with this repositioning, PHI completed a comprehensive organizational review in 2010 that identified opportunities to streamline the organization and to achieve certain reductions in corporate overhead costs that are allocated to its operating segments, which resulted in the adoption of a restructuring plan. PHI began implementation of the plan during 2010, identifying 164 employee positions that were eliminated. The plan also included additional cost reduction opportunities that were implemented through process improvements and operational efficiencies.

In connection with the restructuring plan, ACE recorded a pre-tax restructuring charge related to its allocation of severance, pension, and health and welfare benefits for the termination of corporate services employees at PHI of $6 million in 2010. The severance, pension, and health and welfare benefits were estimated based on the years of service and compensation levels of the employees associated with the 164 eliminated positions at PHI. The restructuring charge was reflected as a separate line item in the consolidated statement of income for the year ended December 31, 2010.

A reconciliation of ACE’s accrued restructuring charges for the year ended December 31, 2011 is as follows:

	Year Ended December 31, 2011
	(millions of dollars)
Beginning balance as of January 1, 2011	$	6
Restructuring charge		—
Cash payments		(5	)
Ending balance as of December 31, 2011	$	1

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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.

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, 2011, 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

321

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, 2011, 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.

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.

Information required by this Item 10 is incorporated herein by reference to (1) PHI’s definitive proxy statement for the 2012 Annual Meeting, which is expected to be filed with the SEC no later than 120 days after December 31, 2011, and (2) the section entitled “Executive Officers of PHI” contained in Part I, Item 1. “Business” of this Form 10-K.

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.

Information required by this Item 11 is incorporated herein by reference to PHI’s definitive proxy statement for the 2012 Annual Meeting, which is expected to be filed with the SEC no later than 120 days after December 31, 2011.

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 is incorporated herein by reference to PHI’s definitive proxy statement for the 2012 Annual Meeting, which is expected to be filed with the SEC no later than 120 days after December 31, 2011.

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 is incorporated herein by reference to PHI’s definitive proxy statement for the 2012 Annual Meeting, which is expected to be filed with the SEC no later than 120 days after December 31, 2011.

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.

323

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 2011 and 2010 fiscal years, reviews of the financial statements included in the 2011 and 2010 Forms 10-Q of Pepco Holdings and its subsidiary reporting companies, reviews of public filings, comfort letters and other attest services were $5,889,420 and $5,618,652, respectively. The amount for 2010 includes $148,323 for the 2010 audit that was billed after the 2010 amount was disclosed in Pepco Holdings’ proxy statement for the 2011 Annual Meeting.

Audit-Related Fees

The aggregate fees billed by PricewaterhouseCoopers LLP for audit-related services rendered for the 2011 and 2010 fiscal years were zero and $738,843, respectively. These services for 2010 consisted of the audit of Conectiv Energy’s financial statements and other consultation services fees related to the disposition of Conectiv Energy.

Tax Fees

The aggregate fees billed by PricewaterhouseCoopers LLP for tax services rendered for the 2011 and 2010 fiscal years were $587,427 and $720,731, respectively. These services consisted of tax compliance, tax advice and tax planning.

All Other Fees

The aggregate fees billed by PricewaterhouseCoopers LLP for all other services other than those covered under “Audit Fees,” “Audit-Related Fees” and “Tax Fees” for the 2011 and 2010 fiscal years were $7,200 and $12,500, respectively. The fees for 2011 and 2010 included the costs of training and technical materials provided by PricewaterhouseCoopers LLP.

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 will be attached as Annex A to Pepco Holdings’ definitive proxy statement for the 2012 Annual Meeting of Shareholders, which is expected to be filed with the SEC no later than 120 days after December 31, 2011, and is incorporated herein by reference.

Part IV

Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) Documents List

1. Financial Statements

Pepco Holdings, Inc.

Consolidated Statements of Income for each of the years ended December 31, 2011, 2010 and 2009

Consolidated Statements of Comprehensive Income for each of the years ended December 31, 2011, 2010 and 2009

Consolidated Balance Sheets as of December 31, 2011 and 2010

324

Consolidated Statements of Cash Flows for each of the years ended December 31, 2011, 2010 and 2009

Consolidated Statements of Equity for each of the years ended December 31, 2011, 2010 and 2009

Notes to Consolidated Financial Statements

Potomac Electric Power Company

Statements of Income for each of the years ended December 31, 2011, 2010 and 2009

Balance Sheets as of December 31, 2011 and 2010

Statements of Cash Flows for each of the years ended December 31, 2011, 2010 and 2009

Statements of Equity for each of the years ended December 31, 2011, 2010 and 2009

Notes to Financial Statements

Delmarva Power & Light Company

Statements of Income for each of the years ended December 31, 2011, 2010 and 2009

Balance Sheets as of December 31, 2011 and 2010

Statements of Cash Flows for each of the years ended December 31, 2011, 2010 and 2009

Statements of Equity for each of the years ended December 31, 2011, 2010 and 2009

Notes to Financial Statements

Atlantic City Electric Company

Consolidated Statements of Income for each of the years ended December 31, 2011, 2010 and 2009

Consolidated Balance Sheets as of December 31, 2011 and 2010

Consolidated Statements of Cash Flows for each of the years ended December 31, 2011, 2010 and 2009

Consolidated Statements of Equity for each of the years ended December 31, 2011, 2010 and 2009

Notes to Consolidated Financial Statements

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		326		N/A		N/A		N/A
Schedule II, Valuation and Qualifying Accounts		331		331		332		332

325

Schedule I, Condensed Financial Information of Parent Company is submitted below.

PEPCO HOLDINGS, INC. (Parent Company)

STATEMENTS OF INCOME

	For the Year Ended December 31,
	2011			2010			2009
	(millions of dollars, except share data)
OPERATING REVENUE	$	—		$	—		$	—
OPERATING EXPENSES
Other operation and maintenance		1			5			5
Total operating expenses		1			5			5
OPERATING LOSS		(1	)		(5	)		(5	)
OTHER INCOME (EXPENSES)
Interest expense		(29	)		(72	)		(87	)
Loss on extinguishment of debt		—			(189	)		—
Income from equity investments		281			287			278
Impairment losses		(5	)		—			—
Total other income		247			26			191
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE		246			21			186
INCOME TAX BENEFIT RELATED TO CONTINUING OPERATIONS		(14	)		(118	)		(37	)
NET INCOME FROM CONTINUING OPERATIONS		260			139			223
(LOSS) INCOME FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES		(3	)		(107	)		12
NET INCOME	$	257		$	32		$	235
EARNINGS PER SHARE
Earnings per share of common stock from Continuing Operations	$	1.15		$	0.62		$	1.01
(Loss) earnings per share of common stock from Discontinued Operations		(0.01	)		(0.48	)		0.05
Basic and diluted earnings per share of common stock	$	1.14		$	0.14		$	1.06

The accompanying Notes are an integral part of these financial statements.

326

PEPCO HOLDINGS, INC. (Parent Company)

BALANCE SHEETS

	As of December 31,
	2011			2010
	(millions of dollars, except share data)
ASSETS
Current Assets
Cash and cash equivalents	$	257		$	131
Prepayments of income taxes		51			99
Accounts receivable and other		7			8
		315			238
Investments and Other Assets
Goodwill		1,398			1,398
Notes receivable from subsidiary companies		154			154
Investment in consolidated companies		3,654			3,033
Other		24			19
Investments held for sale		—			355
		5,230			4,959
Total Assets	$	5,545		$	5,197
LIABILITIES AND EQUITY
Current Liabilities
Short-term debt	$	465		$	230
Interest and taxes accrued		11			15
Accounts payable due to associated companies		25			3
		501			248
Deferred Credits
Liabilities and accrued interest related to uncertain tax positions		3			14
Long-Term Debt		705			705
Commitments and Contingencies (Note 4)
Equity
Common stock, $.01 par value; authorized 400,000,000 shares; 227,500,190 and 225,082,252 shares outstanding, respectively		2			2
Premium on stock and other capital contributions		3,325			3,275
Accumulated other comprehensive loss		(63	)		(106	)
Retained earnings		1,072			1,059
Total equity		4,336			4,230
Total Liabilities and Equity	$	5,545		$	5,197

The accompanying Notes are an integral part of these financial statements.

327

PEPCO HOLDINGS, INC. (Parent Company)

STATEMENTS OF CASH FLOWS

	For the Year Ended December 31,
	2011			2010			2009
	(millions of dollars)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	257		$	32		$	235
Loss (income) from discontinued operations, net of income taxes		3			107			(12	)
Adjustments to reconcile net income to net cash from operating activities:
Distributions from related parties less than earnings		(207	)		(150	)		(186	)
Deferred income taxes		(16	)		(5	)		—
Changes in:
Prepaid and other		23			24			(24	)
Accounts payable		2			1			(4	)
Interest and taxes		42			(130	)		19
Other assets and liabilities		11			31			16
Net Cash From (Used By) Operating Activities		115			(90	)		44
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from sale of Conectiv Energy wholesale power generation business		—			1,035			—
Net Cash From Investing Activities		—			1,035			—
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends paid on common stock		(244	)		(241	)		(238	)
Common stock issued for the Dividend Reinvestment Plan and employee-related compensation		47			47			49
Issuance of long-term debt		—			250			—
Capital distribution to subsidiaries, net		(20	)		(31	)		(255	)
Reacquisitions of long-term debt		—			(1,644	)		—
Decrease in notes receivable from associated companies		—			318			156
Issuances (repayments) of short-term debt, net		235			(94	)		274
Costs of issuances		(7	)		(4	)		(1	)
Net Cash From (Used By) Financing Activities		11			(1,399	)		(15	)
Net increase (decrease) in cash and cash equivalents		126			(454	)		29
Cash and cash equivalents at beginning of year		131			585			556
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	257		$	131		$	585

The accompanying Notes are an integral part of these financial statements.

328

NOTES TO FINANCIAL INFORMATION

(1) BASIS OF PRESENTATION

Pepco Holdings, Inc. (Pepco Holdings) 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) RECLASSIFICATIONS AND ADJUSTMENTS

Certain prior period amounts have been reclassified in order to conform to the current period presentation.

(3) DEBT

For information concerning Pepco Holdings’ long-term debt obligations, see Note (11), “Debt,” to the consolidated financial statements of Pepco Holdings.

(4) COMMITMENTS AND CONTINGENCIES

For information concerning Pepco Holdings’ material contingencies and guarantees, see Note (17), “Commitments and Contingencies” to the consolidated financial statements of Pepco Holdings.

(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:

	2011		2010
	(millions of dollars)
Conectiv, LLC	$	1,300	$	772
Potomac Electric Power Company		1,502		1,428
Potomac Capital Investment Corporation		499		498
Pepco Energy Services, Inc.		350		331
PHI Service Company		3		4
Total investment in consolidated companies	$	3,654	$	3,033

(6) INVESTMENTS HELD FOR SALE

As of December 31, 2010, PHI’s investment in Conectiv Energy Holding Company, LLC (Conectiv Energy), a subsidiary of Conectiv was held for sale. The balance in investments held for sale of $355 million as of December 31, 2010, includes net intercompany receivables of $310 million.

(7) DISCONTINUED OPERATIONS

On April 20, 2010, the Board of Directors of Pepco Holdings approved a plan for the disposition of Conectiv Energy. The plan consists of (i) the sale of Conectiv Energy’s wholesale power generation business and (ii) the liquidation, within the succeeding twelve months, of all of Conectiv Energy’s remaining assets and businesses, including its load service supply contracts, energy hedging portfolio, certain tolling agreements and other non-generation assets. On July 1, 2010, Pepco Holdings completed the sale of its wholesale power generation business to Calpine Corporation.

329

(8) RELATED PARTY TRANSACTIONS

As of December 31, 2011 and 2010, PHI had the following balances on its balance sheets due (to) from related parties:

	2011			2010
	(millions of dollars)
(Liability) Asset
(Payable to) Receivable from Related Party (current) (a)
Potomac Capital Investment Corporation	$	(37	)	$	—
Conectiv, LLC		29			—
Conectiv Communications, Inc.		(4	)		(4	)
Potomac Electric Power Company		(15	)		—
PHI Service Company		2			—
Other		—			1
Total	$	(25	)	$	(3	)
Money Pool Balance with Pepco Holdings (included in cash and cash equivalents)	$	257		$	131

(a) Included in accounts payable due to associated companies.

330

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, 2011 Allowance for uncollectible accounts - customer and other accounts receivable	$	51	$	45	$	8	$	(55	)	$	49
Year Ended December 31, 2010 Allowance for uncollectible accounts - customer and other accounts receivable	$	44	$	53	$	6	$	(52	)	$	51
Year Ended December 31, 2009 Allowance for uncollectible accounts - customer and other accounts receivable	$	35	$	52	$	6	$	(49	)	$	44

(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, 2011 Allowance for uncollectible accounts - customer and other accounts receivable	$	20	$	21	$	2	$	(25	)	$	18
Year Ended December 31, 2010 Allowance for uncollectible accounts - customer and other accounts receivable	$	17	$	26	$	1	$	(24	)	$	20
Year Ended December 31, 2009 Allowance for uncollectible accounts - customer and other accounts receivable	$	15	$	23	$	1	$	(22	)	$	17

(a) Collection of accounts previously written off.

(b) Uncollectible accounts written off.

331

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, 2011 Allowance for uncollectible accounts - customer and other accounts receivable	$	13	$	11	$	3	$	(15	)	$	12
Year Ended December 31, 2010 Allowance for uncollectible accounts - customer and other accounts receivable	$	12	$	13	$	3	$	(15	)	$	13
Year Ended December 31, 2009 Allowance for uncollectible accounts - customer and other accounts receivable	$	10	$	15	$	3	$	(16	)	$	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, 2011 Allowance for uncollectible accounts - customer and other accounts receivable	$	11	$	13	$	3	$	(15	)	$	12
Year Ended December 31, 2010 Allowance for uncollectible accounts - customer and other accounts receivable	$	7	$	13	$	2	$	(11	)	$	11
Year Ended December 31, 2009 Allowance for uncollectible accounts - customer and other accounts receivable	$	6	$	9	$	2	$	(10	)	$	7

(a) Collection of accounts previously written off.

(b) Uncollectible accounts written off.

332

3. EXHIBITS

The documents listed below are being filed, furnished or submitted 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
3.1	PHI	Restated Certificate of Incorporation (filed in Delaware 6/2/2005)	Exh. 3.1 to PHI’s Form 10-K, 3/13/06.
3.2	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.
3.3	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.
3.4	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.
3.5	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.
3.6	PHI	Bylaws	Exh. 3 to PHI’s Form 8-K, 12/21/11.
3.7	Pepco	Bylaws	Exh. 3.2 to Pepco’s Form 10-Q, 5/5/06.
3.8	DPL	Bylaws	Exh. 3.2.1 to DPL’s Form 10-Q 5/9/05.
3.9	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 - 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.

333

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
		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.
		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.

334

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
		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.
		May 7, 1992	Exh. 4 to Pepco’s Form 10-K, 3/26/93.

335

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
		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	Exhibit 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.
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.

336

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.

337

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
		Ninety-First Supplemental Indenture	Exh. 4.L to DPL’s Registration Statement No. 333-24059, 3/27/97.
		Ninety-Second Supplemental Indenture	Filed herewith.
		Ninety-Third Supplemental Indenture	Filed herewith.
		Ninety-Fourth Supplemental Indenture	Filed herewith.
		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	Filed herewith.
		Ninety-Seventh Supplemental Indenture	Filed herewith.
		Ninety-Eighth Supplemental Indenture	Filed herewith.
		Ninety-Ninth Supplemental Indenture	Filed herewith.
		One Hundredth Supplemental Indenture	Filed herewith.
		One Hundred and First Supplemental Indenture	Filed herewith.
		One Hundred and Second Supplemental Indenture	Filed herewith.
		One Hundred and Third Supplemental Indenture	Filed herewith.
		One Hundred and Fourth Supplemental Indenture	Filed herewith.
		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.
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 Atlantic City Electric Company 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.

338

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
		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.
		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.

339

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
		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.

340

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
		July 15, 1987	Exh. 4(d) to ACE’s Form 10-K, 3/28/88.
		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.
4.7	PHI ACE	Indenture dated as of March 1, 1997 between Atlantic City Electric Company and The Bank of New York Mellon, as trustee	Exh. 4(e) to ACE’s Form 8-K, 3/24/97.

341

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
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.
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 between PHI and The Bank of New York Mellon, as trustee dated September 6, 2002	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	Filed herewith.
10.1	PHI	Employment Agreement of Joseph M. Rigby dated August 1, 2008*	Exh. 10.1 to PHI’s Form 8-K, 7/30/08.
10.2	PHI	Pepco Holdings, Inc. Long-Term Incentive Plan (as amended and restated)*	Exh. 10.5 to PHI’s Form 10-K, 3/2/09.
10.2.1	PHI	Amendment to the Pepco Holdings, Inc. Long-Term Incentive Plan*	Filed herewith.
10.3	PHI Pepco	Potomac Electric Power Company Director and Executive Deferred Compensation Plan*	Exh. 10.22 to PHI’s Form 10-K, 3/28/03.
10.4	PHI Pepco	Potomac Electric Power Company Long-Term Incentive Plan*	Exh. 4 to Pepco’s Form S-8, 6/12/98.
10.5	PHI	Conectiv Incentive Compensation Plan*	Exh. 99(e) to Conectiv’s Registration Statement No. 333-18843, 12/26/96.
10.6	PHI	Conectiv Supplemental Executive Retirement Plan*	Exh. 10.10 to PHI’s Form 10-K, 3/2/09.
10.6.1	DPL	Amendment to the Conectiv Supplemental Executive Retirement Plan*	Exh. 10.4 to PHI’s Form 10-Q, 8/3/11.

342

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
10.7	ACE	Bondable Transition Property Sale Agreement between ACE Funding and ACE dated as of December 19, 2002	Exh. 10.1 to ACE Funding’s Form 8-K, 12/23/02.
10.8	ACE	Bondable Transition Property Servicing Agreement between ACE Funding and ACE dated as of December 19, 2002	Exh. 10.2 to ACE Funding’s Form 8-K, 12/23/02.
10.9	PHI	Conectiv Deferred Compensation Plan*	Exh. 10.1 to PHI’s Form 10-Q, 8/6/04.
10.10	PHI	Form of Employee Nonqualified Stock Option Agreement under the PHI Long-Term Incentive Plan*	Exh. 10.2 to PHI’s Form 10-Q, 11/8/04.
10.11	PHI	Form of Director Nonqualified Stock Option Agreement under the PHI Long-Term Incentive Plan*	Exh. 10.3 to PHI’s Form 10-Q, 11/8/04.
10.12	PHI	Non-Management Directors Compensation Plan*	Exh. 10.21 to PHI’s Form 10-K, 3/2/09.
10.13	PHI	Non-Management Director Compensation Arrangements*	Exh. 10.24 to PHI’s Form 10-K, 2/29/08.
10.14	PHI	Form of Election regarding Non-Management Directors Compensation Plan*	Exh. 10.57 to PHI’s Form 10-K, 3/16/05.
10.15	PHI Pepco	Change-in-Control Severance Plan for Certain Executive Employees*	Exh. 10.25 to PHI’s Form 10-K, 3/2/09.
10.16	PHI	Pepco Holdings, Inc. Combined Executive Retirement Plan*	Exh. 10.28 to PHI’s Form 10-K, 3/2/09.
10.16.1	PHI	Amendment to the Pepco Holdings, Inc. Combined Executive Retirement Plan	Exh. 10.3 to PHI’s Form 10-Q, 8/3/11.
10.17	PHI	PHI Named Executive Officer 2010 Compensation Determinations*	Exh. 10.37 to PHI’s Form 10-K, 2/26/10.
10.18	DPL	Transmission Purchase and Sale Agreement by and between DPL and Old Dominion Electric Cooperative dated as of June 13, 2007	Exh. 10.1 to DPL’s Form 10-Q, 8/6/07.
10.19	DPL	Purchase and Sale Agreement by and between DPL and A&N Electric Cooperative dated as of June 13, 2007	Exh. 10.2 to DPL’s Form 10-Q, 8/6/07.
10.20	PHI	PHI Named Executive Officer 2011 Compensation Determinations*	Exh. 10.30 to PHI’s Form 10-K, 2/25/11.
10.21	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.
10.22	PHI	Separation Agreement of Gary J. Morsches dated as of October 25, 2010*	Exh. 10.34 to PHI’s Form 10-K, 2/25/11.

343

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
10.23	PHI	Credit Agreement, dated as of October 27, 2010, by and between Pepco Holdings, Inc. and The Bank of Nova Scotia	Exh. 10.1 to PHI’s Form 8-K, 11/2/10.
10.24	PHI	Credit Agreement, dated as of October 27, 2010, by and between Pepco Holdings, Inc. and JP Morgan Chase Bank, N.A.	Exh. 10.2 to PHI’s Form 8-K, 11/2/10.
10.25	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.
10.26	PHI	The Pepco Holdings, Inc. 2011 Supplemental Executive Retirement Plan*	Exh. 10.2 to PHI’s Form 10-Q, 8/3/11.
10.27	ACE	Purchase Agreement, dated March 29, 2011, by and between ACE and Citigroup Global Markets Inc., Scotia Capital (USA) Inc. and Wells Fargo Securities, LLC for themselves and as representatives of the underwriters named in Schedule A thereto	Exh. 1.1 to ACE’s Form 8-K, 4/1/11.
10.28	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.
10.29	PHI	Pepco Holdings, Inc. 2012 Long-Term Incentive Plan*	Filed herewith.
10.30	PHI	Pepco Holdings, Inc. Annual Executive Incentive Compensation Plan*	Exh. 10.22 to PHI’s Form 10-K, 3/2/09.
10.30.1	PHI	Pepco Holdings, Inc. Amended and Restated Annual Executive Incentive Compensation Plan*	Filed herewith.
10.31	PHI	Pepco Holdings, Inc. Revised and Restated Executive and Director Deferred Compensation Plan*	Exh. 10.6 to PHI’s Form 10-K, 3/2/09.
10.31.1	PHI	Pepco Holdings, Inc. Second Revised and Restated Executive and Director Deferred Compensation Plan*	Filed herewith.

344

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
10.32	PHI	Form of 2012 Non-Management Director Compensation Election Agreement*	Filed herewith.
10.33	PHI	Form of Executive and Director Deferred Compensation Plan Executive Deferral Agreement*	Filed herewith.
10.34	PHI	Form of 2011 Restricted Stock Unit Agreement (Time Based) under the PHI Long-Term Incentive Plan*	Filed herewith.
10.35	PHI	Form of 2011 Restricted Stock Unit Agreement (Performance Based) under the PHI Long-Term Incentive Plan *	Filed herewith.
10.36	PHI	Form of 2012 Restricted Stock Unit Agreement (Time Based) under the PHI Long-Term Incentive Plan *	Filed herewith.
10.37	PHI	Form of 2012 Restricted Stock Unit Agreement (Performance Based) under the PHI Long-Term Incentive Plan*	Filed herewith.
10.38	PHI	Form of 2012 Restricted Stock Unit Agreement (Performance Based/162(m)) under the PHI Long-Term Incentive Plan*	Filed herewith.
10.39	PHI	Form of Election with Respect to Stock Tax Withholding*	Filed herewith.
10.40	PHI	PHI Named Executive Officer 2012 Compensation Determinations*	Filed herewith.
10.41	PHI Pepco DPL ACE	Form of Issuing and Paying Agency Filed Agreement between JPMorgan Chase Bank, National Association and each Reporting Company	Filed herewith.
10.41.1	PHI Pepco DPL ACE	Amendment to Issuing and Paying Agency Agreement	Filed herewith.
10.42	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.
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.

345

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
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.
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.

* Management contract or compensatory plan or arrangement.

** The information required by this Exhibit is set forth in Note (14), “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.

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, those 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.

346

INDEX TO SUBMITTED EXHIBITS

The documents listed below are being submitted herewith:

Exhibit	Registrant(s)	Description of Exhibit
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
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

347

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, furnished or submitted with this Form 10-K are set forth on the exhibit index appearing at the end of this Form 10-K.

348

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 23, 2012	By	/s/ JOSEPH M. RIGBY
		Joseph M. Rigby     Chairman of the Board, President and Chief Executive     Officer
	POTOMAC ELECTRIC POWER COMPANY (Pepco)     (Registrant)
February 23, 2012	By	/s/ DAVID M. VELAZQUEZ
		David M. Velazquez,     President and Chief Executive Officer
	DELMARVA POWER & LIGHT COMPANY (DPL)     (Registrant)
February 23, 2012	By	/s/ DAVID M. VELAZQUEZ
		David M. Velazquez,     President and Chief Executive Officer
	ATLANTIC CITY ELECTRIC COMPANY (ACE)     (Registrant)
February 23, 2012	By	/s/ DAVID M. VELAZQUEZ
		David M. Velazquez,     President and Chief Executive Officer

349

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 23, 2012
/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 23, 2012
/s/ A. J. KAMERICK     Anthony J. Kamerick	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 23, 2012
/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 23, 2012

350

Signature	Title	Date
/s/ J.B. DUNN	Director, Pepco Holdings	February 23, 2012
Jack B. Dunn, IV
/s/ T. C. GOLDEN	Director, Pepco Holdings	February 23, 2012
Terence C. Golden
/s/ FRANK O. HEINTZ	Director, Pepco Holdings	February 23, 2012
Frank O. Heintz
/s/ PATRICK T. HARKER	Director, Pepco Holdings	February 23, 2012
Patrick T. Harker
/s/ BARBARA J. KRUMSIEK	Director, Pepco Holdings	February 23, 2012
Barbara J. Krumsiek
/s/ GEORGE F. MacCORMACK	Director, Pepco Holdings	February 23, 2012
George F. MacCormack
/s/ LAWRENCE C. NUSSDORF	Director, Pepco Holdings	February 23, 2012
Lawrence C. Nussdorf
/s/ PATRICIA A. OELRICH	Director, Pepco Holdings	February 23, 2012
Patricia A. Oelrich
/s/ FRANK ROSS	Director, Pepco Holdings	February 23, 2012
Frank K. Ross
/s/ PAULINE A. SCHNEIDER	Director, Pepco Holdings	February 23, 2012
Pauline A. Schneider
/s/ LESTER P. SILVERMAN	Director, Pepco Holdings	February 23, 2012
Lester P. Silverman
/s/ KIRK J. EMGE	Director, Pepco and DPL	February 23, 2012
Kirk J. Emge
/s/ CHARLES R. DICKERSON	Director, Pepco	February 23, 2012
Charles R. Dickerson
/s/ WILLIAM M. GAUSMAN	Director, Pepco	February 23, 2012
William M. Gausman
/s/ MICHAEL J. SULLIVAN	Director, Pepco	February 23, 2012
Michael J. Sullivan

351

INDEX TO EXHIBITS FILED HEREWITH

Exhibit No.	Registrant(s)	Description of Exhibit
4.4	PHI DPL	Ninety-Second Supplemental Indenture Ninety-Third Supplemental Indenture Ninety-Fourth Supplemental Indenture Ninety-Sixth Supplemental Indenture Ninety-Seventh Supplemental Indenture Ninety-Eighth Supplemental Indenture Ninety-Ninth Supplemental Indenture One Hundredth Supplemental Indenture One Hundred and First Supplemental Indenture One Hundred and Second Supplemental Indenture One Hundred and Third Supplemental Indenture One Hundred and Fourth Supplemental Indenture
4.13	PHI Pepco DPL ACE	Corporate Commercial Paper – Master Note
10.2.1	PHI	Amendment to the Pepco Holdings, Inc. Long-Term Incentive Plan*
10.29	PHI	Pepco Holdings, Inc. 2012 Long-Term Incentive Plan*
10.30.1	PHI	Pepco Holdings, Inc. Amended and Restated Annual Executive Incentive Compensation Plan*
10.31.1	PHI	Pepco Holdings, Inc. Second Revised and Restated Executive and Director Deferred Compensation Plan*
10.32	PHI	Form of 2012 Non-Management Director Compensation Election Agreement*
10.33	PHI	Form of Executive and Director Deferred Compensation Plan Executive Deferral Agreement*
10.34	PHI	Form of 2011 Restricted Stock Unit Agreement (Time Based) under the PHI Long-Term Incentive Plan*
10.35	PHI	Form of 2011 Restricted Stock Unit Agreement (Performance Based) under the PHI Long-Term Incentive Plan*
10.36	PHI	Form of 2012 Restricted Stock Unit Agreement (Time Based) under the PHI Long-Term Incentive Plan*
10.37	PHI	Form of 2012 Restricted Stock Unit Agreement (Performance Based) under the PHI Long-Term Incentive Plan*
10.38	PHI	Form of 2012 Restricted Stock Unit Agreement (Performance Based/162(m)) under the PHI Long-Term Incentive Plan*
10.39	PHI	Form of Election with Respect to Stock Tax Withholding*
10.40	PHI	PHI Named Executive Officer 2012 Compensation Determinations*

10.41	PHI Pepco DPL ACE	Form of Issuing and Paying Agency Agreement between JPMorgan Chase Bank, National Association, and each Reporting Company
10.41.1	PHI Pepco DPL ACE	Amendment to Issuing and Paying Agency Agreement
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
INDEX TO EXHIBITS 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

INDEX TO EXHIBITS SUBMITTED HEREWITH

Exhibit No.	Registrant(s)	Description of Exhibit
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
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