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, 2010

Commission File Number	Name of Registrant, State of Incorporation, Address of Principal Executive Offices, and Telephone Number	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 800 King Street, P.O. Box 231 Wilmington, Delaware 19899 Telephone: (202)872-2000	51-0084283
001-03559	ATLANTIC CITY ELECTRIC COMPANY (ACE), a New Jersey corporation 800 King Street, P.O. Box 231 Wilmington, Delaware 19899 Telephone: (202)872-2000	21-0398280

Continued

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  ¨	No  ¨
DPL	Yes  ¨	No  ¨	ACE	Yes  ¨	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 the definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K (applicable to Pepco Holdings only).

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

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

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

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

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

Registrant	Aggregate Market Value of Voting and Non-Voting Common Equity Held by Non-Affiliates of the Registrant at June 30, 2010	Number of Shares of Common Stock of the Registrant Outstanding at February 1, 2011
Pepco Holdings	$3.5 billion	225,138,897 ($.01 par value)
Pepco	None (a)	100 ($.01 par value)
DPL	None (b)	1,000 ($2.25 par value)
ACE	None (b)	8,546,017 ($3.00 par value)

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

(b) All voting and non-voting common equity is owned by Conectiv, 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 2011 Annual Meeting of Shareholders to be filed with the Securities and Exchange Commission on or about March 31, 2011 are incorporated by reference into Part III of this report.

TABLE OF CONTENTS

			Page
	-	Glossary of Terms		i
PART I
Item 1.	-	Business		1
Item 1A.	-	Risk Factors		17
Item 1B.	-	Unresolved Staff Comments		26
Item 2.	-	Properties		27
Item 3.	-	Legal Proceedings		28
Item 4.	-	Reserved		28
PART II
Item 5.	-	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		29
Item 6.	-	Selected Financial Data		32
Item 7.	-	Management’s Discussion and Analysis of Financial Condition and Results of Operations		33
Item 7A.	-	Quantitative and Qualitative Disclosures About Market Risk		122
Item 8.	-	Financial Statements and Supplementary Data		126
Item 9.	-	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure		320
Item 9A.	-	Controls and Procedures		320
Item 9B.	-	Other Information		323
PART III
Item 10.		Directors, Executive Officers and Corporate Governance		324
Item 11.	-	Executive Compensation		326
Item 12.	-	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		326
Item 13.	-	Certain Relationships and Related Transactions, and Director Independence		327
Item 14.	-	Principal Accounting Fees and Services		328
PART IV
Item 15.	-	Exhibits and Financial Statement Schedules		329
Financial Statements		Included in Part II, Item 8
Schedule I	-	Condensed Financial Information of Parent Company		330
Schedule II	-	Valuation and Qualifying Accounts		334
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
Signatures

GLOSSARY OF TERMS

Term	Definition
ABO	Accumulated benefit obligation
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
BGS	Basic Generation Service (the supply of electricity by ACE to retail customers in New Jersey who have not elected to purchase electricity from a competitive supplier)
BGS-CIEP	BGS-Commercial and Industrial Energy Price
BGS-FP	BGS-Fixed Price
Blueprint for the Future	PHI’s initiatives combining traditional DSM programs with new technologies and systems to help customers manage their energy use and reduce the total cost of energy
BMPs	Best management practices
BSA	Bill Stabilization Adjustment mechanism
CAA	Federal Clean Air Act
CAIR	Clean Air Interstate Rule issued by EPA
Calpine	Calpine Corporation, the purchaser of Conectiv Energy’s wholesale power generation business
CWA	Federal Clean Water Act
CERCLA	Comprehensive Environmental Response, Compensation, and Liability Act of 1980
CH4	Methane gas
C02	Carbon dioxide
Conectiv	A wholly owned subsidiary of PHI and the parent of DPL and ACE
Conectiv Energy	Conectiv Energy Holding Company and its subsidiaries
CRMC	PHI’s Corporate Risk Management Committee
CSA	Credit Support Annex
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 service
Default Supply Revenue	Revenue received for Default Electricity Supply
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
DSM	Demand-side management
EBITDA	Earnings before interest, taxes, depreciation, and amortization
EDIT	Excess Deferred Income Taxes
EIS	Federal Environmental Impact Statement
Energy Services	Business of Pepco Energy Services that provides energy savings performance contracting services and designing, constructing and operating combined heat and power and central energy plats for customers
EPA	U.S. Environmental Protection Agency
Exchange Act	Securities Exchange Act of 1934, as amended
FASB	Financial Accounting Standards Board

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Term	Definition
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
GCR	Gas Cost Rate
GWh	Gigawatt hour
HPS	Hourly Priced Service
ICR	Information Collection Request from the EPA
IRS	Internal Revenue Service
ISDA	International Swaps and Derivatives Association
ISO	Independent system operator
ITC	Investment tax credit
Line Loss	Estimates of electricity and gas expected to be lost in the process of its transmission and distribution to customers
LTIP	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
MDC	MDC Industries, Inc.
Medicare Act	Medicare Prescription Drug Improvement and Modernization Act of 2003
Medicare Part D	A prescription drug benefit under Medicare
MFVRD	Modified fixed variable rate design
Mirant	Mirant Corporation
MMBtu	One Million British Thermal Units
MSCG	Morgan Stanley Capital Group, Inc.
MPSC	Maryland Public Service Commission
MWh	Megawatt hour
NAV	Net Asset Value
New Jersey Societal Benefit Charge	Revenue ACE receives to recover certain costs incurred under various NJBPU - mandated social programs
NYMEX	New York Mercantile Exchange
NJBPU	New Jersey Board of Public Utilities
NJDEP	New Jersey Department of Environmental Protection
Normalization provisions	Sections of the Internal Revenue Code and related regulations that dictate how excess deferred income taxes resulting from the corporate income tax rate reduction enacted by the Tax Reform Act of 1986 and accumulated deferred investment tax credits should be treated for ratemaking purposes
NOx	Nitrogen oxide
NPDES	National Pollutant Discharge Elimination System
NUGs	Non-utility generators
OPEB	Other postretirement benefits
Panda	Panda-Brandywine, L.P.
Panda PPA	PPA between Pepco and Panda
PARS	Performance accelerated restricted stock
PCBs	Polychlorinated biphenyls
PCI	Potomac Capital Investment Corporation and its subsidiaries
Pepco	Potomac Electric Power Company

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Term	Definition
Pepco Energy Services	Pepco Energy Services, Inc. and its subsidiaries
Pepco Holdings or PHI	Pepco Holdings, Inc.
PHI Retirement Plan	PHI’s noncontributory retirement plan
PJM	PJM Interconnection, LLC
PJM RTO	PJM regional transmission organization
PM10	Particulate matter less than ten microns in diameter
Power Delivery	PHI’s Power Delivery business
PPA	Power Purchase Agreement
PRP	Potentially responsible party
PUHCA 2005	Public Utility Holding Company Act of 2005, which became effective February 8, 2006
QSPE	Qualifying special purpose entity
RECs	Renewable energy credits
RAR	IRS revenue agent’s report
RARM	Reasonable Allowance for Retail Margin
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
Revenue Decoupling Adjustment	An adjustment equal to the amount by which revenue from distribution sales differs from the revenue that Pepco and DPL are entitled to earn based on the approved distribution charge per customer
RI/FS	Remedial investigation and feasibility study
ROE	Return on equity
SEC	Securities and Exchange Commission
Sempra	Sempra Energy Trading LLC
SF6	Sulfur hexafluoride
SO2	Sulfur dioxide
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
T&D	Transmission and distribution
Transition Bond Charge	Revenue ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds and related taxes, expenses and fees
Transition Bonds	Transition Bonds issued by ACE Funding
VaR	Value at Risk
VRDBs	Variable Rate Demand Bonds
WACC	Weighted average cost of capital

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Part I

Item 1. BUSINESS

Overview

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.

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 investments in eight cross-border energy leases as described below under the heading “Other Business Operations.” PCI is no longer engaged in new investment activity.

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

1

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, 2010 as (i) Power Delivery, consisting of the operations of Pepco, DPL and ACE, (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 set forth in Part II, Item 8 of this Form 10-K.

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 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 set forth in Part II, Item 8 of this Form 10-K.

Investor Information

Each of PHI, Pepco, DPL and ACE files reports under the Securities Exchange Act of 1934, as amended. 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 of the companies 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 Securities and Exchange Commission (SEC). These reports may be found at http://www.pepcoholdings.com/investors.

Description of Business

Power Delivery

PHI’s primary business is Power Delivery. The Power Delivery business in 2010, 2009 and 2008, respectively, produced 73%, 67%, and 68% of PHI’s consolidated operating revenues and 81%, 78%, and 101% of PHI’s consolidated operating income. None of PHI’s three utilities owns any electric generation facilities.

The Power Delivery business consists of the operations of Pepco, DPL and ACE, each of which is a regulated electric utility in the jurisdictions that comprise its electricity distribution service territory. DPL also is a regulated natural gas utility serving portions of Delaware. In the aggregate, the Power Delivery business distributes electricity to more than 1.8 million customers in the mid-Atlantic region and delivers natural gas to approximately 123,000 customers in Delaware.

2

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 company 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 company 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 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.

PJM Interconnection, LLC (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.

Regulation

The operations of PHI’s utility subsidiaries, including the rates 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 Maryland Public Service Commission (MPSC) and in the District of Columbia by the District of Columbia Public Service Commission (DCPSC).

3

• DPL’s electricity distribution operations are regulated in Maryland by the MPSC and in Delaware by the Delaware Public Service Commission (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 New Jersey Board of Public Utilities (NJBPU).

• Each utility subsidiary’s transmission is regulated by FERC.

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

Seasonality

The operating results of the Power Delivery segment 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 state 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 the result of the implementation of a bill stabilization adjustment mechanism (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 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.

4

Regulated Utility Subsidiaries

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

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, 2010, Pepco distributed electricity to 787,000 customers (of which 256,000 were located in the District of Columbia and 531,000 were located in Maryland), as compared to 778,000 customers as of December 31, 2009 (of which 252,000 were located in the District of Columbia and 526,000 were located in Maryland).

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 megawatt hours were delivered 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 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 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 May 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 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.

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

5

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 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 1.3 million. As of December 31, 2010, DPL delivered electricity to 500,000 customers (of which 301,000 were located in Delaware and 199,000 were located in Maryland), as compared to 498,000 customers as of December 31, 2009 (of which 299,000 were located in Delaware and 199,000 were located in Maryland).

In 2010, DPL distributed a total of 12,853,000 megawatt hours of electricity to its customers, of which 66% was distributed within its Delaware territory and 34% within Maryland. Of this amount, 42% of the 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 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 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 (RARM). Components of the RARM 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.

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 SOS, known as 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.

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For the year ended December 31, 2010, 53% of DPL’s Delaware distribution sales (measured by megawatt hours) were to SOS customers, as compared to 51% in 2009, and 63% of its Maryland distribution sales (measured by megawatt hours) were to SOS customers for the years ended December 31, 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, 2010, DPL supplied 65% of the natural gas that it delivered, compared to 68% in 2009.

In each of the years ended December 31, 2010 and 2009, DPL delivered natural gas to 123,000 customers. In 2010, DPL delivered 19,000,000 Mcf (thousand cubic feet) of natural gas to customers in its Delaware service territory, of which 41% were sales to residential customers, 23% to commercial customers, 1% to industrial customers and 35% 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, 2010, ACE distributed electricity to 548,000 customers in its service territory, as compared to 547,000 customers as of December 31, 2009.

In 2010, ACE distributed a total of 10,185,000 megawatt hours of electricity to its customers, of which 46% 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 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.

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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, 2010, ACE’s BGS-FP peak load was approximately 1,638 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, 2010, ACE’s peak BGS-CIEP load was approximately 28 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, 2010, 65% of ACE’s total distribution sales (measured by megawatt hours) were to BGS customers, as compared to 73% in 2009.

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 2010, ACE purchased 2.5 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 Transition Funding LLC (ACE Funding) solely for the purpose of securitizing authorized portions of ACE’s recoverable stranded costs through the issuance and sale of bonds (Transition Bonds). The proceeds of the sale of each series of Transition Bonds were transferred to ACE in exchange for the transfer by ACE to ACE Funding of the right to collect a non-bypassable transition bond charge 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.

Other Power Delivery Initiatives and Activities

Reliability Enhancement Plans

During 2010, Pepco announced Comprehensive Reliability Enhancement Plans for Maryland and the District of Columbia. Each six point plan advances work on existing programs and initiates new activities designed to increase the reliability of Pepco distribution services in Maryland and the District of Columbia. The plans include enhanced vegetation management, identification and upgrading of underperforming feeder lines, addition of new facilities to support load growth, distribution automation, underground residential cable replacement and selective undergrounding of service lines. By focusing on these six areas, Pepco plans to increase the reliability of the distribution system by reducing both the frequency and the duration of power outages. The incremental cost of these reliability improvements over the next five years is estimated to be $100 million in the Maryland service territory and $90 million in the District of Columbia service territory. For a discussion of the capital expenditures associated with these plans, see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Capital Expenditure - Reliability Enhancement Plans” of this Form 10-K.

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Blueprint for the Future

Each of PHI’s three utilities are participating in a PHI initiative referred to as the “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. 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 allow each utility to better manage and operate their electrical and gas distribution systems. Blueprint for the future programs include:

• Rebates and other financial incentives to encourage residential customers to replace inefficient appliances and for business customers to use more energy-efficient equipment, such as improved lighting, heating, ventilation and air-conditioning systems.

• The installation of smart meters for all electric customers in their service territories, and for natural gas customers in the case of DPL (also known as Advanced Metering infrastructure (AMI)) as has been, or may be approved by state regulators. These smart meters allow the utilities, among other capabilities, to remotely read meters, significantly reduce estimated bills, improve outage management, and provide customers with more detailed information about their energy consumption.

• The installation, at the customer’s option, of smart thermostats or direct load control switches. This equipment reduces residential air conditioner load during times of high wholesale market prices or periods of system constraints. In exchange, customers receive additional financial incentives through bill credits or new dynamic pricing rate structures.

• Further automation of the electric distribution system and enhanced communications.

The status of some of the more significant aspects of these initiatives is as follows:

• Smart meters (AMI):

• Pepco in the District of Columbia: The DCPSC approved the implementation of AMI in December 2009, with cost recovery mechanisms. Full scale implementation of AMI began in October 2010.

• Pepco in Maryland: The MPSC approved full-scale implementation of AMI in August 2010, with implementation to begin following approval of a customer education plan.

• DPL in Maryland: Final approval of the MPSC is pending approval of an updated cost-benefit study and a customer communications plan.

• DPL in Delaware for both electric and gas operations: The DPSC approved implementation of AMI in September 2008, including cost recovery mechanisms. Implementation of AMI is expected to be completed in 2011.

• ACE: The NJBPU is not expected to approve ACE’s proposal for implementation of AMI in the near term.

• Direct load control programs:

• Pepco in the District of Columbia: The recovery of costs for the direct load control program through a surcharge was rejected by the DCPSC on December 20, 2010. As a result, program implementation has not yet been approved.

• Pepco in Maryland: The recovery of costs for the direct load control air-conditioners through a surcharge was approved by MPSC in January 2010. The recovery of costs for smart thermostats through a surcharge is still in progress.

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• DPL in Maryland: The installation of switches for air conditioners commenced in 2009, and the recovery of costs through a surcharge was approved in January 2010. The installation of smart thermostats has been temporarily suspended pending resolution of a technical issue.

• DPL in Delaware: The installation of smart thermostats and air-conditioning switches is dependent upon commission approval.

• ACE: The NJBPU approved the surcharge for residential direct load control program in June 2010.

For a discussion of the capital expenditures associated with Blueprint for the Future, See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Resources and Liquidity — Capital Expenditure — Blueprint for the Future” of this Form 10-K.

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 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 150-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 is currently estimated to be $1.2 billion and the planned in service date is June 1, 2015.

PHI understands that PJM currently is in the process of reassessing reliability requirements of the PJM RTO system in the context of the preparation of its 2011 Regional Transmission Expansion Plan, which is scheduled to be completed in June 2011. This reassessment is expected to take into account a revised load forecast for the PJM region that is significantly lower than the load that was forecast in prior PJM studies. This reassessment could result in a further deferral of the required operational date of all or a portion of the MAPP transmission line.

The construction of MAPP requires various permits and approvals, including the approval of the MPSC. The MPSC has issued a procedural schedule to consider a request for a Certificate of Public Convenience and Necessity filed by Pepco and DPL, which contemplates decision by January 31, 2012.

For a discussion of the capital expenditures associated with the MAPP project, see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Resources and Liquidity — Capital Expenditure — MAPP Project” of this Form 10-K.

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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. area.

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 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, 2010, Pepco Energy Services’ estimated retail electricity backlog was approximately 9.7 million megawatts for distribution through 2014, a decrease of approximately 10.4 million megawatts when compared to December 31, 2009. For additional information on the Pepco Energy Services wind-down, see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations – General Overview,” of this Form 10-K.

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. See Item 2, “Properties” of this Form 10-K. 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. Pepco Energy Services currently plans to deactivate both facilities in May 2012. PJM has informed Pepco Energy Services that these facilities are not expected to be needed for reliability after that time, but that its evaluation is dependent on the completion of transmission and distribution upgrades. Pepco Energy Services’ timing for deactivation of the facilities, in whole or in part, may be delayed based on reliability considerations, economic conditions and the operating condition of the facilities. Deactivation will not 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 and 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.

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PJM Capacity Markets

A source of revenue for Pepco Energy Services has been the sale of capacity associated with its generating facilities. The wholesale market for capacity in the PJM RTO region is administered by PJM, which 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. In accordance with PJM requirements, retail sellers of electricity in the PJM market are required to maintain capacity from generating facilities within the control area, or capacity for generating facilities outside the control area that have firm transmission rights into the control area that correspond to their load service obligations. This capacity can be obtained through the ownership of generation facilities, entry into bilateral contracts or the purchase of capacity credits in the auctions administered by PJM. Both generating facilities owned by Pepco Energy Services are located in the transmission control area administered by PJM.

Beginning on June 1, 2007, PJM replaced its former capacity market rules with a forward capacity auction procedure known as the Reliability Pricing Model (RPM), which provides for differentiation in capacity prices between “locational deliverability areas.” Under RPM, PJM holds annual auctions covering capacity to be supplied over consecutive 12-month periods. Pepco Energy Services is exposed to deficiency charges payable to PJM if their generation units fail to meet certain reliability levels. Some deficiency charges may be reduced by purchasing capacity from PJM or third parties. 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

In providing energy management services, Pepco Energy Services competes with numerous other providers. Competition in the market for energy management services is based primarily on overall value to customers.

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. As of December 31, 2010, PHI’s equity investment in its cross-border energy leases was approximately $1.4 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 set forth in Part II, Item 8 of this Form 10-K.

Employees

At December 31, 2010, PHI had 5,014 employees, including 1,375 employed by Pepco, 905 employed by DPL, 553 employed by ACE and 1,662 employed by PHI Service Company. The remaining employees were employed by Pepco Energy Services. Approximately 2,592 employees (including 1,028 employed by Pepco, 699 employed by DPL, 390 employed by ACE, 331 employed by the PHI Service Company, and 144 employed by Pepco Energy Services) are covered by collective bargaining agreements with various locals of the International Brotherhood of Electrical Workers.

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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. 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’ currently have no 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. 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 (CAA), 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 CAA 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 SO₂ 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 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 may implement CAIR by adopting EPA’s trading program or through regulations that at a minimum achieve the level of reductions that would be achieved through implementation of EPA’s program.

Each state covered by CAIR 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.

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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 2010, EPA proposed regulations to replace CAIR to address transport of air pollution across state boundaries. EPA’s proposed Transport Rule will impose stricter limits on SO₂ and NO_x (annual and ozone season) than CAIR, effective as early as 2012. The proposed Transport Rule will affect Benning generating facility because it has a stationary fossil-fuel fired boiler that was in operation after November 15, 1990 and is used in combination with a generator with nameplate capacity greater than 25 MW producing electricity for sale to the grid.

EPA will propose a Federal Implementation Plan for the District of Columbia and each state covered by the rule to address the lower limits. Alternatively, the District of Columbia Department of the Environment (DDOE) could develop its own State Implementation Plan (SIP). DDOE’s strategy for addressing the requirements is unknown at this time.

Although implementation of CAIR increases costs for Pepco Energy Services to operate these Benning Road units, PHI currently does not anticipate that CAIR or the proposed Transport Rule will have a material adverse impact on its results of operations, financial condition or cash flows, even assuming the units are not deactivated by May 2012 as planned. Pepco Energy Services’ Buzzard Point generating units and its landfill gas generating units produce fewer megawatts than the CAIR applicability threshold and therefore would not be affected by the proposed Transport Rule.

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 (PM₁₀ ) and for SO₂ and NOx to the extent not addressed by CAIR. Pepco Energy Services is evaluating the manner of addressing BART, including ceasing operation of the Benning Road generating units consistent with its previously announced plan to deactivate those units by May 2012.

On January 4, 2011, Pepco Energy Services received from the DDOE the draft of a Title V permit, which reflects Pepco’s agreement to deactivate the Benning Road units by the end of calendar year 2012 and DDOE’s agreement to delay the implementation BART until after the agreed upon retirement date. PHI expects the Title V permit to be finalized before the end of the second quarter 2011.

Pepco Energy Services’ Buzzard Point generating units and its landfill gas generating units are not subject to the Regional Haze Rule.

Hazardous Air Pollutant Emissions

In a March 2005 rulemaking, EPA removed coal- and oil-fired electric generating units from the list of source categories requiring Maximum Achievable Control Technology for hazardous air pollutants such as mercury and nickel under CAA Section 112. In a decision issued in February 2008, the U.S. Court of Appeals for the District of Columbia Circuit determined that this action by EPA was unlawful. To date, EPA has not proposed new regulations to address hazardous air pollutant emissions from existing electric generating units in response to the court’s decision.

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In January 2010, Pepco Energy Services received from EPA an Information Collection Request (ICR) under Section 114 of the Clean Air Act, requesting that it provide information regarding Benning Road units 15 and 16 that will allow EPA to assess the emissions of hazardous air pollutants from those units. The information requested includes historical data with respect to both units, as well as data to be obtained by stack testing during the operation of Benning Road unit 16. Pepco Energy Services provided timely responses to the ICR. In September 2010, Pepco Energy Services received a variance from EPA such that stack testing at Benning is not required.

Green House Gas Emissions

EPA has adopted regulations requiring sources that emit designated greenhouse gases – specifically, carbon dioxide (CO₂), 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 is required to report, beginning with calendar year 2010, 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 is required to report with respect to its gas distribution operations, beginning with calendar year 2010, CO₂ emissions that would result assuming the complete combustion or oxidation of the annual volume of natural gas it distributes to its customers. Beginning with calendar year 2011, DPL would have to report, with respect to its liquefied natural gas storage facility, fugitive CO₂ and methane (CH₄) emissions, if it met the reporting threshold (25,000 metric tons). Based on a preliminary analysis, DPL’s liquefied natural gas storage facility does not meet the reporting threshold.

• ACE, DPL and Pepco will be required to report sulfur hexafluoride (SF₆) emissions from electrical equipment beginning with calendar year 2011.

Water Quality Regulation

Clean Water Act

Provisions of the federal Water Pollution Control Act, also known as the Clean Water Act (CWA), establish the basic legal structure for regulating the discharge of pollutants from point sources to surface waters of the United States. Among other things, the CWA 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 generating 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 (BMPs) 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 BMPs for minimizing the presence of the substances in storm water. The capital expenditures, if any, that may be needed to implement BMPs to satisfy these new permit conditions will not be known until these studies are completed.

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NPDES General Permit for Pesticide Discharge

PHI operates and maintains approximately 3,600 miles of transmission right of way and approximately 30,000 miles of distribution right of way and uses a combination of mechanical and chemical controls (pesticides/herbicides) to manage vegetation in its rights-of-way through a process known as “Integrated Vegetation Management.” PHI’s application of pesticides and herbicides for vegetation management traditionally has been governed by the requirements of the Federal Insecticide, Fungicide and Rodenticide Act.

In response to a 2009 decision by the Sixth Circuit Court of Appeals in National Cotton Council, et al, v. EPA, which invalidated a 2006 EPA rulemaking exempting pesticide application from NPDES permit requirements, EPA, in June 2010, proposed a draft NPDES general permit for point source discharges from the application of pesticides to waters of the United States. Under the Court’s order, pesticide discharges are required to be permitted under either an EPA- or state- issued NPDES permit no later than April 9, 2011. State water pollution regulators and agriculture officials asked the EPA to seek a six month stay of the court’s order to provide sufficient time for EPA to finalize its general permit and for states to use the final EPA general permit as a guide for developing state NPDES general permits.

When permitting authorities make such permits available, PHI utility companies will apply for NPDES permits for pesticide application as part of vegetation management activities.

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 (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. In November 2008, ACE filed an appeal of these regulations with the Appellate Division of the Superior Court of New Jersey. The grounds for ACE’s appeal include the lack of administrative record justification for the FHACA regulations and conflict between the FHACA regulations and other state and federal regulations and standards for maintenance of electric power transmission and distribution facilities. The matter was argued before the Appellate Division on January 3, 2011, and the decision of the court is pending.

EPA Oil Pollution Prevention Regulations

In 2002, EPA amended its oil pollution prevention regulations to require facilities that, because of their location, could reasonably be expected to discharge oil in quantities that may be harmful to the environment, to amend existing Spill Prevention, Control, and Countermeasure (SPCC) Plans and implement secondary containment as necessary. After giving effect to additional amendments and delays in the effective date, PHI facilities subject to the regulations must comply with these regulatory requirements by November 10, 2011. PHI anticipates that compliance with the SPCC regulations will require physical modification of certain facilities through the construction of containment structures or replacement of oil-filled equipment with non-oil-filled equipment at a total anticipated cost to ACE, DPL and Pepco of approximately $1 million, $2 million and $2 million, respectively. PHI does not expect the compliance costs for Pepco Energy Services to be material.

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Hazardous Substance Regulation

The Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA) authorizes EPA, and comparable state laws authorize state environmental authorities, to issue orders and bring enforcement actions to compel responsible parties to investigate and take remedial actions at any site that is determined to present an actual or potential threat to human health or the environment because of an actual or threatened release of one or more hazardous substances. Parties that generated or transported hazardous substances to such sites, as well as the owners and operators of such sites, may be deemed liable under CERCLA or comparable state laws. 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 – Legal Proceedings – Environmental Litigation,” to the consolidated financial statements of PHI set forth in Part II, Item 8 of this Form 10-K.

Item 1A. RISK FACTORS

The businesses of PHI, Pepco, DPL and ACE 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 companies, including, depending on the circumstances, its financial condition, results of operations and cash flows. Unless otherwise noted, each risk factor set forth below applies to each of PHI, Pepco, DPL and ACE.

PHI and its subsidiaries are subject to substantial governmental regulation, and unfavorable regulatory treatment could have a negative effect.

The regulated utilities that comprise the Power Delivery businesses are subject to regulation by various federal, state and local regulatory agencies that significantly affects their operations. Each of Pepco, DPL and ACE is regulated by the public service commission for each service territory in which it operates, with respect to, among other things, the rates it can charge retail customers for the distribution and supply of electricity (and, additionally for DPL, the distribution and supply of natural gas). In addition, the rates that the companies can charge for electricity transmission are regulated by FERC, and DPL’s natural gas transportation is regulated by FERC. The companies cannot change these rates without approval by the applicable regulatory authority. While the approved rates are intended to permit the companies to recover their costs of service and earn a reasonable rate of return on invested capital, the profitability of the companies is affected by the rates they are able to charge. In addition, if the costs incurred by any of the companies in operating its facilities exceed the allowed amounts for costs included in the approved rates, the financial results of that company, and correspondingly PHI, will be adversely affected.

PHI’s utility subsidiaries, as well as Pepco Energy Services, are required to have numerous permits, approvals and certificates from governmental agencies that regulate their businesses. 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. None of the companies, however, are able 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.

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The operating results of the Power Delivery business 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 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 than normal in the winter and cooler than normal in the summer. The recent adoption for retail customers of Pepco and DPL in Maryland and for Pepco retail customers in the District of Columbia of a bill stabilization adjustment mechanism which decouples distribution revenue for a given reporting period from the amount of power delivered during the period, has had the effect of eliminating in those jurisdictions, changes in the use of electricity by such retail customers due to weather conditions or for other reasons as a factor having an impact on reported distribution revenue and income.

The adoption of bill stabilization adjustment or similar mechanisms for DPL electricity and natural gas customers in Delaware and ACE electricity customers in New Jersey are under consideration by the state public service commissions. In those jurisdictions that have not adopted a bill stabilization adjustment or similar mechanism, operating results continue to be affected by weather conditions.

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 maintenance expenditures, which could decrease revenues or increase expenses.

Operation of the Pepco, DPL and ACE transmission and distribution facilities and Pepco Energy Services’ generating facilities (scheduled for deactivation in May 2012) involves many risks, including the breakdown or failure of equipment, accidents, labor disputes 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. 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 or the operation of generation facilities below expected output levels, can reduce revenues and result in the incurrence of additional expenses that may not be recoverable from customers or through insurance, including deficiency charges imposed by PJM on generating facilities at a rate of up to two times the capacity payment that the generating facility receives. Furthermore, the transmission and generating facilities of the PHI companies are subject to reliability standards imposed by the North American Electric Reliability Corporation. Failure to comply with the standards may result in substantial monetary penalties.

Energy companies are subject to adverse publicity which makes them vulnerable to negative regulatory and litigation outcomes.

Utility companies, including PHI’s utility subsidiaries, 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. Adverse publicity of this nature may render legislatures, regulatory authorities and other 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.

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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 the 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.

The transmission facilities of the Power Delivery business are interconnected with the facilities of other transmission facility owners whose actions 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 contiguous utilities and are part of an interstate power transmission grid. FERC has designated a number of regional transmission organizations to coordinate the operation of portions of the interstate transmission grid. Pepco, DPL and ACE are members of the PJM RTO. The PJM RTO and the other regional transmission organizations have established sophisticated systems that are designed to ensure the reliability of the operation of transmission facilities and prevent the operations of one utility from having an adverse impact on the operations of the other utilities. However, the systems put in place by the PJM RTO and the other regional transmission organizations may not always be adequate to prevent problems at other utilities from causing service interruptions in the transmission facilities of Pepco, DPL or ACE. If any of Pepco, DPL or ACE were to suffer such a service interruption, it could have a negative impact on it and on PHI.

The cost of compliance with environmental laws, including laws relating to emissions of greenhouse gases, is significant and implementation of new and existing environmental laws may increase operating costs.

The operations of PHI’s subsidiaries, including Pepco, DPL and ACE, 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.

There is growing concern at the federal and state levels regarding the implications of CO₂ and other greenhouse gas emissions on the global climate. The implementation of restrictions on the emission of CO₂ and other greenhouse gases or regulatory action by the U.S. Environmental Protection Agency prior to deactivation of Pepco Energy Services’ generating facilities (scheduled for May 2012) could require Pepco Energy Services to incur increased capital expenditures or operating costs to replace existing equipment, install additional pollution control equipment or purchase CO₂ allowances and offsets.

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Alternatively, Pepco Energy Services could be required to discontinue or curtail the operations of one or more units prior to their planned deactivation date.

Until specific requirements are promulgated, the impact that any new environmental regulations, voluntary compliance guidelines, enforcement initiatives or legislation may have on the results of operations, financial position or liquidity of PHI and its subsidiaries is not determinable.

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

The ability of each of PHI and its subsidiaries, including Pepco, DPL and ACE, to implement its business strategy is dependent on its ability to recruit, retain and motivate employees. Competition for skilled employees in some areas is high and the inability to retain and attract these employees could adversely affect the business, operations and financial condition of PHI or the affected company.

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

The Energy Services business of Pepco Energy Services is highly competitive. This competition generally has the effect of limiting margins and requiring a continual focus on controlling costs.

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 would have an adverse effect on Pepco Energy Services.

The operation of Pepco Energy Services’ generating facilities depends on natural gas or diesel fuel supplied by others. If the fuel supply to these generating facilities were 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.

Changes in technology may adversely affect the Power Delivery business.

Increased conservation and end-user generation made possible through advances in technology could reduce demand for the transmission and distribution facilities of the Power Delivery business and adversely affect PHI and any one or more of its utility subsidiaries.

Pepco Energy Services’ risk management procedures may not be effective in preventing losses. (PHI only)

The retail energy supply and the electricity generation businesses of Pepco Energy Services are conducted in accordance with sophisticated risk management systems that are designed to quantify and control risk. However, actual results sometimes deviate from modeled expectations. Until the completion of the ongoing wind down of retail energy supply business and the deactivation of Pepco Energy Services’ two generating facilities (scheduled for May 2012), the ineffectiveness of Pepco Energy Service’s risk management procedures could have a material adverse effect on PHI’s results of operations.

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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 typically entered into electricity and natural gas sale contracts under which it committed to supply the electricity or natural gas requirements of its retail customers over a specified period at agreed upon prices. To acquire the required energy, Pepco Energy Services has entered into wholesale purchase contracts for electricity and natural gas. These contracts typically impose collateral requirements on each party designed to protect the other party against the risk of nonperformance between the date the contract was entered into and the date the energy is paid for. The collateral required to be posted can be of varying forms, including cash, letters of credit and guarantees. When energy market prices decrease relative to the supplier contract prices, Pepco Energy Service’s collateral obligations increase. While Pepco Energy Services no longer enters into new energy supply contracts, it has continuing supply obligations based on prior 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 Pepco Energy Services 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 credit facilities or other financing sources.

The retail energy supply business of Pepco Energy Services has significant exposure to counterparty risk. (PHI only)

Pepco Energy Services has entered into transactions with numerous counterparties. These include both commercial transactions for the purchase and sale of electricity and natural gas, and 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 no longer required. Under many of these contracts, Pepco Energy Services is entitled 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, bankruptcy law, in some circumstances, could require Pepco Energy Services to surrender collateral held or payments received.

Mark-to-market accounting treatment for instruments Pepco Energy Service’s 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. Pepco Energy Services accounts for its futures and swap contracts as cash flow hedges of forecasted transactions. 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 for its commodity contracts.

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Business operations could be adversely affected by terrorism.

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 disruptions of fuel supplies and markets. If any of its infrastructure facilities, including its 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. Corresponding instability in the financial markets as a result of terrorism also could adversely affect the ability to raise needed capital.

Insurance coverage may not be sufficient to cover all casualty 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. 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.

Revenues, profits and cash flows may be adversely affected by economic conditions.

Periods of slowed economic activity generally result in decreased demand for power, particularly by industrial and large commercial customers. As a consequence, recessions or other downturns in the economy may result in decreased revenues, profits and cash flows for the Power Delivery businesses of Pepco, DPL and ACE and the business of Pepco Energy Services.

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 eight cross-border energy lease investments, which as of December 31, 2010, had an equity value of approximately $1.4 billion and from which PHI currently derives approximately $59 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 issued in June 2006 and in March 2009 in connection with the audits of PHI’s federal 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 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.

In November 2010, the IRS approved a settlement with respect to the 2001-2002 tax returns in which PHI agreed to a disallowance of its depreciation and interest deductions in excess of rental income, but reserved the right to file refund claims contesting the allowances. In January 2011, PHI paid $74 million of additional tax, plus penalties of $1 million, in accordance with the terms of the settlement. PHI intends to file a claim for refund for the disallowed deductions, pursue litigation against the IRS if claim is denied. The 2003-2005 case is currently pending with the IRS Appeals Office.

In the event that that 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, 2010, it would be obligated to pay approximately $692 million in additional federal and state taxes and $133 million of interest, of which $74 million has been satisfied by the payment made in January 2011. In

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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 and ASC 850) 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 Part II, Item 8, Financial Statements and Supplementary Data — PHI — Note (17), “Commitments and Contingencies — Regulatory and Other Matters — PHI’s Cross-Border Energy Lease Investments,” of this Form 10-K.

PHI and its subsidiaries are dependent on 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. The companies rely primarily on cash flow from operations and access to the capital markets to meet these financing needs. The operating activities of the companies also require access to short-term money markets and bank financing as sources of liquidity that are not met by cash flow from operations. Adverse business developments or market disruptions could increase the cost of financing or prevent the companies from accessing one or more financial markets.

The financing costs of each of PHI, Pepco, DPL and ACE are closely linked, directly or indirectly, to its credit rating. 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 and collateral requirements and could make financing more difficult to obtain.

Under the terms of PHI’s primary credit facilities, the consolidated indebtedness of PHI cannot exceed 65% of its consolidated capitalization. If PHI’s equity were to decline to a level that caused PHI’s debt to exceed this limit, lenders would be entitled to refuse any further extension of credit and to declare all of the outstanding debt under the credit facilities immediately due and payable. To avoid such a default, a renegotiation of this covenant would be required which would likely increase funding costs and could result in additional covenants that would restrict PHI’s operational and financing flexibility. Events that could cause a reduction in PHI’s equity include a further write down of PHI’s cross-border energy lease investments or a significant write down of PHI’s goodwill.

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 attack or threatened attacks; or

• a significant electricity transmission disruption.

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In accordance with the requirements of the Sarbanes-Oxley Act of 2002 and the SEC rules thereunder, PHI’s management is responsible for establishing and maintaining internal control over financial reporting and is required to assess annually the effectiveness of these controls. The inability to certify the effectiveness of these controls due to the identification of one or more material weaknesses in these controls also could increase financing costs or could adversely affect the ability to access one or more financial markets.

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, 2010, of approximately $1.4 billion, primarily attributable to Pepco’s acquisition of Conectiv in 2002. Under accounting principles generally accepted in the United States of America, an impairment charge must be recorded 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 further 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.

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, PHI, Pepco, DPL or ACE 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 (the PHI Retirement 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 PHI, Pepco, DPL and ACE. 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 results of operations and financial condition of PHI, Pepco, DPL and ACE.

PHI’s cash flow, ability to pay dividends and ability to satisfy debt obligations depend on the performance of its operating subsidiaries. PHI’s unsecured obligations are effectively subordinated to the liabilities and the outstanding preferred stock of its subsidiaries. (PHI only)

PHI is a holding company that conducts its operations entirely through its 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 the subsidiaries and the distribution of such earnings to PHI in the form of dividends. The 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. Because the claims of

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the creditors of PHI’s subsidiaries and the preferred stockholders of ACE 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 and to the rights of the holders of ACE’s preferred stock to receive dividend payments.

Provisions of the Delaware General Corporation Law may discourage an acquisition of PHI. (PHI only)

As a Delaware corporation, PHI is subject to the business combination law set forth in Section 203 of the Delaware General Corporation Law, which could have the effect of delaying, discouraging or preventing an acquisition of PHI.

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 the company’s earnings, cash flow and capital structure and also may take into account the business plans and financial requirements of PHI and its other subsidiaries.

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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, 2010.

Electric Generating Facilities	Location	Owner	Generating Capacity (kilowatts)
Oil Fired Units
Benning Road	Washington, DC	Pepco Energy Services		550,000
Combustion Turbines/Combined Cycle Units
Buzzard Point	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

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, 2010, consisted of approximately 3,500 transmission circuit miles of overhead lines, 400 transmission circuit miles of underground cables, 18,600 distribution circuit miles of overhead lines, and 16,100 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 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 49,000 Mcf per day. DPL owns 8 natural gas city gate stations at various locations in New Castle County, Delaware. These stations have a total primary delivery point contractual entitlement of 262,961 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, set forth in Part II, Item 8 of this Form 10-K.

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—Legal Proceedings,” to the consolidated financial statements of PHI, set forth in Part II, Item 8 of this Form 10-K.

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—Legal Proceedings,” to the financial statements of Pepco, set forth in Part II, Item 8 of this Form 10-K.

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—Legal Proceedings,” to the financial statements of DPL, set forth in Part II, Item 8 of this Form 10-K.

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—Legal Proceedings,” to the consolidated financial statements of ACE, set forth in Part II, Item 8 of this Form 10-K.

Item 4. RESERVED

Part II

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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.

Period	Dividends Per Share		Price Range
			High		Low
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
2009:
First Quarter	$	.27	$	18.71	$	10.07
Second Quarter		.27		13.67		11.45
Third Quarter		.27		15.37		12.85
Fourth Quarter		.27		17.51		14.24
	$	1.08

See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Resources and Liquidity — Capital Requirements — Dividends,” of this Form 10-K for information regarding restrictions on the ability of PHI and its subsidiaries to pay dividends.

At December 31, 2010, there were 55,893 registered holders of record of Pepco Holdings common stock.

Dividends

On January 27, 2011, the PHI Board of Directors declared a dividend on common stock of 27 cents per share payable March 31, 2011, to shareholders of record on March 10, 2011.

PHI Subsidiaries

All of the common equity of Pepco, DPL and ACE is owned directly or indirectly by PHI. Pepco, DPL and ACE each customarily pays dividends on its common stock on a quarterly basis based on its earnings, cash flow and capital structure, and after taking into account the business plans and financial requirements of PHI and its other 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 2010 were used to support the payment of its common stock dividend.

Period	Aggregate Dividends
2010:
First Quarter	$	25,000,000
Second Quarter		25,000,000
Third Quarter		45,000,000
Fourth Quarter		20,000,000
	$	115,000,000
2009:
First Quarter	$	—
Second Quarter		—
Third Quarter		—
Fourth Quarter		—
	$	—

DPL

All of DPL’s common stock is held by 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 2010 and 2009 were passed through to PHI to support the payment of its common stock dividend.

Period	Aggregate Dividends
2010:
First Quarter	$	—
Second Quarter		23,000,000
Third Quarter		—
Fourth Quarter		—
	$	23,000,000
2009:
First Quarter	$	28,500,000
Second Quarter		—
Third Quarter		—
Fourth Quarter		—
	$	28,500,000

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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. Dividends received by Conectiv in 2009 were passed through to PHI to support the payment of its common stock dividend.

Period	Aggregate Dividends
2010:
First Quarter	$	—
Second Quarter		—
Third Quarter		—
Fourth Quarter		35,000,000
	$	35,000,000
2009:
First Quarter	$	24,100,000
Second Quarter		—
Third Quarter		—
Fourth Quarter		40,000,000
	$	64,100,000

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.

31

Item 6. SELECTED FINANCIAL DATA

The following table sets forth selected historical consolidated data for PHI as of December 31, 2010, 2009, 2008, 2007, and 2006, derived from PHI’s audited financial statements.

PEPCO HOLDINGS CONSOLIDATED FINANCIAL HIGHLIGHTS

	2010			2009			2008			2007			2006
	(in millions, except per share data)
Consolidated Operating Results
Total Operating Revenue	$	7,039		$	7,402		$	8,059	(f)	$	7,613		$	6,877
Total Operating Expenses		6,415	(a)		6,754	(d)		7,510			6,953	(h)		6,281	(j)
Operating Income		624			648			549			660			596
Other Expenses		474	(b)		321			276			255			252
Preferred Stock Dividend Requirements of Subsidiaries		—			—			—			—			1
Income from Continuing Operations Before Income Tax Expense		150			327			273			405			343
Income Tax Expense Related to Continuing Operations		11	(c)		104	(e)		90	(f)(g)		141	(i)		133
Income from Continuing Operations		139			223			183			264			210
(Loss) Income from Discontinued Operations, net of Income Taxes		(107	)		12			117			70			38	(k)
Net Income		32			235			300			334			248
Earnings Available for Common Stock		32			235			300			334			248
Common Stock Information
Basic Earnings Per Share of Common Stock from Continuing Operations	$	0.62		$	1.01		$	0.90		$	1.36		$	1.10
Basic (Loss) Earnings per Share of Common Stock from Discontinued Operations		(0.48	)		.05			0.57			0.36			0.20
Basic Earnings Per Share of Common Stock		0.14			1.06			1.47			1.72			1.30
Diluted Earnings Per Share of Common Stock from Continuing Operations		0.62			1.01			0.90			1.36			1.10
Diluted (Loss) Earnings per Share of Common Stock from Discontinued Operations		(0.48	)		.05			0.57			0.36			0.20
Diluted Earnings Per Share of Common Stock		0.14			1.06			1.47			1.72			1.30
Cash Dividends Per Share of Common Stock		1.08			1.08			1.08			1.04			1.04
Year-End Stock Price		18.25			16.85			17.76			29.33			26.01
Net Book Value per Common Share		18.79			19.15			19.14			20.04			18.82
Weighted Average Shares Outstanding		224			221			204			194			191
Other Information
Investment in Property, Plant and Equipment	$	12,120		$	11,431		$	10,860		$	10,392		$	10,003
Net Investment in Property, Plant and Equipment		7,673			7,241			6,874			6,552			6,317
Total Assets		14,480			15,779			16,133			15,111			14,244
Capitalization
Short-term Debt	$	534		$	530		$	465		$	289		$	350
Long-term Debt		3,629			4,470			4,859			4,175			3,769
Current Portion of Long-Term Debt and Project Funding		75			536			85			332			858
Transition Bonds issued by ACE Funding		332			368			401			434			464
Capital Lease Obligations due within one year		8			7			6			6			6
Capital Lease Obligations		86			92			99			105			111
Long-Term Project Funding		15			17			19			21			23
Non-controlling Interest		6			6			6			6			24
Common Shareholders’ Equity		4,230			4,256			4,190			4,018			3,612
Total Capitalization	$	8,915		$	10,282		$	10,130		$	9,386		$	9,217

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

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

(c) 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.

(d) Includes $40 million ($24 million after-tax) gain related to settlement of Mirant bankruptcy claims.

(e) 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.

(f) 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.

(g) 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.

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

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

(j) Includes $19 million of impairment losses ($14 million after-tax) related to certain energy services business assets.

(k) Includes $12 million gain ($8 million after-tax) on the sale of Conectiv Energy’s equity interest in a joint venture which owns a wood burning cogeneration facility.

32

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	34
Pepco	88
DPL	100
ACE	111

33

PEPCO HOLDINGS

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

Pepco Holdings, Inc.

General Overview

Pepco Holdings, Inc. (PHI or Pepco Holdings), 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, Inc. and its subsidiaries (collectively, 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 eight 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,
	2010			2009			2008
Percentage of Consolidated Operating Revenue
Power Delivery		73	%		67	%		68	%
Pepco Energy Services		27	%		32	%		33	%
Other Non-Regulated		—			1	%		(1	)%
Percentage of Consolidated Operating Income
Power Delivery		81	%		78	%		101	%
Pepco Energy Services		11	%		14	%		10	%
Other Non-Regulated		8	%		8	%		(11	)%
Percentage of Power Delivery Operating Revenue
Power Delivery Electric		95	%		95	%		94	%
Power Delivery Gas		5	%		5	%		6	%

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.

The Power Delivery business is conducted by PHI’s three utility subsidiaries: Potomac Electric Power Company (Pepco), Delmarva Power & Light Company (DPL) and Atlantic City Electric Company (ACE). Each of these companies is a regulated public utility in the jurisdictions that comprise 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. 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 Standard Office 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 service obligations are referred to generally as Default Electricity Supply.

34

PEPCO HOLDINGS

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 the Federal Energy Regulatory Commission (FERC). Transmission rates are updated annually based on a FERC-approved formula methodology.

The profitability of the Power Delivery business depends on its ability to recover costs and earn a reasonable return on its capital investments through the rates it is permitted to charge. The Power Delivery operating results historically have been seasonal, generally producing higher revenue and income in the warmest and coldest periods of the year. Operating results also can be affected by economic conditions, energy prices and the impact of energy efficiency measures on customer usage of electricity.

As a result of the implementation of a bill stabilization adjustment mechanism (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, Pepco and DPL recognize distribution revenue based on an approved distribution charge per customer. From a revenue recognition standpoint, this has the effect of decoupling distribution revenue recognized in a reporting period from the amount of power delivered during the period. As a consequence, 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. For customers to whom the BSA applies, 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.

As a result of 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 and 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.

Pepco Energy Services

The business of the Pepco Energy Services segment has consisted primarily of (i) the retail supply of electricity and natural gas and (ii) providing energy savings performance contracting services principally to federal, state and local government customers, and designing, constructing and operating combined heat and power and central energy plants for customers (Energy Services). Pepco Energy Services also owns and operates two oil-fired generation facilities. 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, 2010, 2009 and 2008 were $1.6 billion, $2.3 billion and $2.5 billion, respectively, and operating income for the same periods was $59 million, $88 million and $54 million, respectively.

PHI expects the retail energy supply business to remain profitable through December 31, 2012, based on its existing contract backlog 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.

35

PEPCO HOLDINGS

In connection with the operation of the retail energy supply business, as of December 31, 2010 and 2009, Pepco Energy Services has collateral pledged to counterparties primarily for the instruments it uses to hedge commodity price risk of approximately $230 million and $280 million, respectively. Of the December 31, 2010 collateral amount, $113 million was in the form of letters of credit and $117 million was posted in cash. Pepco Energy Services estimates that at current market prices, with the wind down of the retail energy supply business, this collateral will be released as follows: an aggregate of 64% by December 31, 2011, an aggregate of 92% by December 31, 2012, and substantially all collateral 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 Potomac Capital Investment Corporation, PHI maintains a portfolio of cross-border energy lease investments with a book value at December 31, 2010 of approximately $1.4 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 (17), “Commitments and Contingencies—Regulatory and Other Matters – PHI’s Cross-Border Energy Lease Investments,” to the consolidated financial statements of PHI set forth in Part II, Item 8 of this Form 10-K.

Discontinued Operations

On April 20, 2010, the Board of Directors of PHI approved a plan for the disposition of Conectiv Energy, which is comprised of Conectiv Energy Holding Company and its subsidiaries. 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 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 three years in the period ended December 31, 2010 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.

36

PEPCO HOLDINGS

Business Strategy

PHI’s business strategy is to remain a mid-Atlantic regional energy distribution utility company focused on value creation, operational excellence and environmental responsibility. The components of this strategy include:

• Achieving earnings growth in the Power Delivery business by focusing on transmission and distribution infrastructure investments and constructive regulatory outcomes, while maintaining a high level of operational excellence.

• Pursuing technologies and practices that promote energy efficiency, energy conservation and the reduction of greenhouse gas emissions.

• Supplementing PHI’s utility earnings through Pepco Energy Services by providing energy performance services and renewable energy and combined heat and power alternatives to commercial, industrial and government customers.

To further this business strategy, PHI may from time to time examine a variety of transactions involving its existing businesses, including the entry into joint ventures or the disposition of one or more businesses, as well as possible acquisitions. PHI also may reassess or refine the components of its business strategy as it deems necessary or appropriate in response to a wide variety of factors, including the requirements of its businesses, competitive conditions and regulatory requirements.

37

PEPCO HOLDINGS

Earnings Overview

Year Ended December 31, 2010 Compared to the Year Ended December 31, 2009

PHI’s net income from continuing operations for the year ended December 31, 2010 was $139 million, or $0.62 per share, compared to $223 million, or $1.01 per share, for the year ended December 31, 2009.

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 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.

Net income from continuing operations for the year ended December 31, 2009, included the credits set forth below in the Power Delivery segment, which are presented net of federal and state income taxes and are in millions of dollars:

Settlement of Pepco divestiture-related Mirant Corporation (Mirant) bankruptcy claims	$	24
Maryland income tax benefit, net of fees	$	11

Excluding these items, net income from continuing operations would have been $188 million, or $0.85 per share, for the year ended December 31, 2009.

PHI’s net loss from discontinued operations for the year ended December 31, 2010 was $107 million, or $0.48 per share, compared to net income of $12 million, or $0.05 per share, for the year ended December 31, 2009.

PHI’s net income (loss) for the years ended December 31, 2010 and 2009, by operating segment, is set forth in the table below (in millions of dollars):

	2010			2009			Change
Power Delivery	$	206		$	199		$	7
Pepco Energy Services		36			40			(4	)
Other Non-Regulated		25			31			(6	)
Corporate and Other		(128	)		(47	)		(81	)
Net Income from Continuing Operations		139			223			(84	)
Discontinued Operations		(107	)		12			(119	)
Total PHI Net Income	$	32		$	235		$	(203	)

38

PEPCO HOLDINGS

Discussion of Operating Segment Net Income Variances:

Power Delivery’s $7 million increase in earnings is primarily due to the following:

• $51 million increase from higher distribution revenue consisting of:

• a $24 million increase 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); and

• a $27 million increase due to higher distribution sales, primarily due to weather, usage and growth in the number of customers.

• $21 million increase from higher transmission revenue primarily due to higher rates effective June 1, 2010 related to an increase in transmission plant investment.

• $11 million increase in Other Income (Expense), primarily an increase in the Allowance for Funds Used During Construction and gains on the disposal of assets.

• $6 million increase associated with ACE Basic Generation Service primarily attributable to an increase in unbilled revenue due to higher usage and higher rates.

The aggregate of these increases was partially offset by:

• $27 million decrease due to higher operating and maintenance costs primarily resulting from February, July and August 2010 storm restoration activity, system maintenance (tree trimming) and estimated environmental remediation costs.

• $24 million decrease due to the 2009 favorable earnings impact of the approvals by the District of Columbia Public Service Commission (DCPSC) and the Maryland Public Service Commission (MPSC) of Pepco’s proposals for sharing the proceeds of the Mirant bankruptcy settlement remaining after the transfer of the Panda PPA to a third party.

• $17 million decrease due to a restructuring charge recorded in 2010.

• $8 million decrease related to income tax adjustments consisting of:

• $13 million decrease due to 2009 earnings impact of a Maryland income tax benefit related to a change in tax reporting for the disposition of certain assets in prior years; offset by

• $5 million net increase due to the impact of interest related to effectively settled and uncertain tax positions in 2010.

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

Pepco Energy Services’ $4 million decrease in earnings is primarily due to the following:

• $18 million decrease due to lower retail electricity sales volumes due to the ongoing wind down of the retail electricity supply business, and lower gross margins due to low demand in the retail natural gas business.

39

PEPCO HOLDINGS

• $6 million decrease due to repair costs associated with a thermal services’ distribution system pipe leak and higher costs associated with operating a customer’s cogeneration plant; partially offset by increased high voltage construction activity.

The aggregate amount of these decreases was partially offset by:

• $11 million increase due to higher electricity generation output that resulted from warmer than normal weather; partially offset by power plant maintenance costs.

• $8 million increase due to lower interest and other expenses, primarily associated with credit and collateral facilities for the retail energy supply business.

Other Non-Regulated’s $6 million decrease in earnings is primarily due to favorable income tax benefits recorded in 2009.

Corporate and Other’s $81 million decrease in earnings is primarily due to the unfavorable impact of $113 million of debt extinguishment costs related to the purchase of outstanding debt with the proceeds from the sale of the Conectiv Energy wholesale power generation business; partially offset by the favorable impact of $22 million of net state income tax benefits related to the April 2010 corporate restructuring and $8 million of lower interest expense.

The $119 million decrease in earnings from discontinued operations was primarily due to the recognition of a loss associated with the sale of the wholesale power generation business to Calpine Corporation and unrealized losses on derivative instruments no longer qualifying for cash flow hedge accounting, partially offset by gains recognized on sales of load service supply contracts.

40

PEPCO HOLDINGS

Consolidated Results of Operations

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 Transmission and Distribution (T&D) Electric Revenue includes revenue from the distribution of electricity, including the distribution of Default Electricity Supply, by PHI’s utility subsidiaries to customers within their service territories at regulated rates. Regulated T&D Electric Revenue also includes transmission service revenue that PHI’s utility subsidiaries receive as transmission owners from the PJM Interconnection, LLC (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 Standard Offer Service or Basic Generation Service (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 Atlantic City Electric Transition Funding LLC (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 (Transmission Enhancement Credits).

41

PEPCO HOLDINGS

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.

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
Other		292		253		39
Total Regulated T&D Electric Revenue	$	1,858	$	1,653	$	205

Other Regulated T&D Electric Revenue consists primarily of transmission service revenue.

	2010		2009		Change
Regulated T&D Electric Sales (Gigawatt hours(GWh))
Residential		18,398		16,871		1,527
Commercial and industrial		32,045		31,570		475
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		—
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.

42

PEPCO HOLDINGS

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).

• 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 2010 spring and summer months 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 (demand side management program for Pepco and DPL) 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 Regional Transmission Organization (RTO) market of energy and capacity purchased under contracts with unaffiliated non-utility generators (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	)

43

PEPCO HOLDINGS

	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.

• 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 2010 spring and summer months 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. Under the BGS terms approved by the New Jersey Board of Public Utilities, ACE is entitled to recover from its customers all of its costs of providing BGS. If the costs of providing BGS exceed the BGS revenue, then the excess costs are deferred in Deferred Electric Service Costs. ACE’s BGS unbilled revenue (which is the result of the recognition of revenue when the electricity is delivered, as opposed to when it is billed) is not included in the deferral calculation, and therefore has an impact on the results of operations in the period during which it is accrued. While the change in the amount of unbilled revenue from year to year typically is not significant, for the year ended December 31, 2010, BGS unbilled revenue increased by $8 million as compared to the year ended December 31, 2009, which resulted in a $5 million increase in PHI’s net income. The increase was primarily due to higher Default Electricity Supply rates and colder weather during the unbilled revenue period at the end of 2010 as compared to the corresponding period in 2009.

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	)

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	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.

• 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 decreases effective March 2009 and November 2009.

• A decrease of $14 million due to lower sales as a result of milder weather during the 2010 winter months 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 Reliability Pricing Model charges associated with the generating facilities.

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• An increase of $38 million due to increased high voltage and energy services construction 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	)

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 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 2010 spring and summer months 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.

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The decrease is partially offset by:

• An increase of $42 million due to increased high voltage and energy services construction 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

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 due to (i) the establishment of a reserve in the amount of $13 million relating to a possible discharge of polychlorinated biphenyls (PCBs) at the Benning Road transmission and distribution facility owned by Pepco, and (ii) a $4 million accrual in 2010 for future costs relating to a 1999 oil release at the Indian River generating facility then owned by DPL, as further discussed under the headings “Benning Road Site” and “Indian River Oil Release,” respectively, in Note (17), “Commitments and Contingencies,” to the consolidated financial statements of PHI set forth in Part II, Item 8 of this Form 10-K.

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

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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

With the ongoing wind down of the retail energy supply business of Pepco Energy Services and the disposition of Conectiv Energy, PHI is repositioning itself as a regulated transmission and distribution company. In connection with this repositioning, 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 that are allocated to its operating segments. This review has resulted in the adoption of a restructuring plan. PHI began implementing the plan during the third quarter, identifying 164 employee positions that were eliminated during the fourth quarter of 2010. The plan also focuses on identifying additional cost reduction opportunities through process improvements and operational efficiencies. PHI currently estimates that the implementation of the plan will result in an annual reduction of approximately $28 million in corporate overhead costs.

In connection with the plan, PHI recorded a pre-tax restructuring charge of $30 million for the year ended December 31, 2010, related to severance, pension, 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.

• 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 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

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purchased is reported under Fuel and Purchased Energy and the corresponding revenue is reported under Default Electricity Supply Revenue. The cost of 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.

Effect 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 is required to distribute to customers by approximately $11 million. While Pepco has filed an appeal of the DCPSC’s decision with the District of Columbia Court of Appeals, in view of the DCPSC order, PHI recognized a pre-tax expense of $11 million for the year ended December 31, 2010. The appeal is still pending.

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 Panda PPA. 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.

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 which was attributable to the retirement of the debt and $15 million 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, set forth in Part II, Item 8 of this Form 10-K.

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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 Internal Revenue Service (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 is subject to adjustment when the IRS finalizes its calculation of the amount 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.

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The following results of operations discussion is for the year ended December 31, 2009, compared to the year ended December 31, 2008. 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:

	2009			2008			Change
Power Delivery	$	4,980		$	5,488		$	(508	)
Pepco Energy Services		2,383			2,648			(265	)
Other Non-Regulated		51			(60	)		111
Corporate and Other		(12	)		(17	)		5
Total Operating Revenue	$	7,402		$	8,059		$	(657	)

Power Delivery Business

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

	2009		2008		Change
Regulated T&D Electric Revenue	$	1,653	$	1,690	$	(37	)
Default Electricity Supply Revenue		2,990		3,413		(423	)
Other Electric Revenue		69		67		2
Total Electric Operating Revenue		4,712		5,170		(458	)
Regulated Gas Revenue		228		204		24
Other Gas Revenue		40		114		(74	)
Total Gas Operating Revenue		268		318		(50	)
Total Power Delivery Operating Revenue	$	4,980	$	5,488	$	(508	)

Regulated Transmission and Distribution (T&D) Electric Revenue includes revenue from the distribution of electricity, including the distribution of Default Electricity Supply, by PHI’s utility subsidiaries to customers within their service territories at regulated rates. Regulated T&D Electric Revenue also includes transmission service revenue that PHI’s utility subsidiaries receive as transmission owners from the PJM Interconnection, LLC (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 Standard Offer Service or Basic Generation Service (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 Atlantic City Electric Transition Funding LLC (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 (Transmission Enhancement Credits).

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

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Regulated 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

	2009		2008		Change
Regulated T&D Electric Revenue
Residential	$	596	$	593	$	3
Commercial and industrial		804		786		18
Other		253		311		(58	)
Total Regulated T&D Electric Revenue	$	1,653	$	1,690	$	(37	)

Other Regulated T&D Electric Revenue consists primarily of: (i) transmission service revenue and (ii) revenue from the resale by Pepco in the PJM RTO market of energy and capacity purchased under the Panda PPA prior to the transfer of the Panda PPA to an unaffiliated third party in September 2008.

	2009		2008		Change
Regulated T&D Electric Sales (GWh)
Residential		16,871		17,186		(315	)
Commercial and industrial		31,570		32,520		(950	)
Other		261		261		—
Total Regulated T&D Electric Sales		48,702		49,967		(1,265	)
	2009		2008		Change
Regulated T&D Electric Customers (in thousands)
Residential		1,623		1,612		11
Commercial and industrial		198		198		—
Other		2		2		—
Total Regulated T&D Electric Customers		1,823		1,812		11

Regulated T&D Electric Revenue decreased by $37 million primarily due to:

• A decrease of $53 million in Other Regulated T&D Electric Revenue (which is matched by a corresponding decrease in Fuel and Purchased Energy) due to the absence of revenues from the resale of energy and capacity purchased under the Panda PPA after September 2008.

• A decrease of $12 million due to lower non-weather related customer usage.

The aggregate amount of these decreases was partially offset by:

• An increase of $16 million due to a distribution rate increase (which is substantially offset by a corresponding increase in Deferred Electric Service Costs) as part of a higher New Jersey Societal Benefit Charge that became effective in June 2008.

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• An increase of $15 million due to higher pass-through revenue (which is substantially offset by a corresponding increase in Other Taxes) primarily the result of increases in utility taxes that are collected on behalf of taxing jurisdictions.

Default Electricity Supply

	2009		2008		Change
Default Electricity Supply Revenue
Residential	$	1,915	$	1,882	$	33
Commercial and industrial		915		1,200		(285	)
Other		160		331		(171	)
Total Default Electricity Supply Revenue	$	2,990	$	3,413	$	(423	)

Other Default Electricity Supply Revenue consists primarily of revenue from the resale by ACE in the PJM RTO market of energy and capacity purchased under contracts with unaffiliated NUGs.

	2009		2008		Change
Default Electricity Supply Sales (GWh)
Residential		16,274		16,621		(347	)
Commercial and industrial		8,470		10,204		(1,734	)
Other		101		101		—
Total Default Electricity Supply Sales		24,845		26,926		(2,081	)
	2009		2008		Change
Default Electricity Supply Customers (in thousands)
Residential		1,572		1,572		—
Commercial and industrial		159		167		(8	)
Other		2		2		—
Total Default Electricity Supply Customers		1,733		1,741		(8	)

Default Electricity Supply Revenue decreased by $423 million primarily due to:

• A decrease of $175 million in wholesale energy revenues due to lower market prices for the sale of electricity purchased from NUGs.

• A decrease of $167 million due to lower sales, primarily the result of commercial customer migration to competitive suppliers.

• A decrease of $49 million due to lower non-weather related customer usage.

• A decrease of $33 million due to lower sales as a result of milder weather primarily during the 2009 summer months as compared to 2008.

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The decrease in total Default Electricity Supply Revenue includes a decrease of $8 million in unbilled revenue attributable to ACE’s BGS. Under the BGS terms approved by the New Jersey Board of Public Utilities (NJBPU), ACE is entitled to recover from its customers all of its costs of providing BGS. If the costs of providing BGS exceed the BGS revenue, then the excess costs are deferred in Deferred Electric Service Costs. ACE’s BGS unbilled revenue is not included in the deferral calculation, and therefore has an impact on the results of operations in the period during which it is accrued. While the change in the amount of unbilled revenue from year to year typically is not significant, for the year ended December 31, 2009, BGS unbilled revenue decreased by $8 million as compared to the year ended December 31, 2008, which resulted in a $5 million decrease in PHI’s net income. The decrease was due to increased customer migration and lower customer usage during the unbilled revenue period at the end of 2009 as compared to the corresponding period in 2008.

Regulated Gas

	2009		2008		Change
Regulated Gas Revenue
Residential	$	139	$	121	$	18
Commercial and industrial		81		75		6
Transportation and other		8		8		—
Total Regulated Gas Revenue	$	228	$	204	$	24
	2009		2008		Change
Regulated Gas Sales (billion cubic feet)
Residential		8		7		1
Commercial and industrial		5		6		(1	)
Transportation and other		6		7		(1	)
Total Regulated Gas Sales		19		20		(1	)
	2009		2008		Change
Regulated Gas Customers (in thousands)
Residential		113		113		—
Commercial and industrial		10		9		1
Transportation and other		—		—		—
Total Regulated Gas Customers		123		122		1

Regulated Gas Revenue increased by $24 million primarily due to:

• An increase of $15 million due to the Gas Cost Rate increase effective November 2008, partially offset by rate decreases in March 2009 and November 2009.

• An increase of $14 million (which is offset by a corresponding increase in Fuel and Purchased Energy) associated with the recognition of the unbilled portion of Gas Cost Rate revenue in 2009 which was not previously recognized.

The aggregate amount of these increases was partially offset by:

• A decrease of $5 million due to lower non-weather related customer usage.

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• A decrease of $4 million due to lower sales as result of warmer weather during the fourth quarter of 2009 as compared to the corresponding period in 2008.

Other Gas Revenue

Other Gas Revenue decreased by $74 million primarily due to lower revenue from off-system sales resulting from:

• A decrease of $67 million due to lower market prices.

• A decrease of $9 million due to lower demand from electric generators and natural gas marketers.

Pepco Energy Services

Pepco Energy Services’ operating revenue decreased $265 million primarily due to:

• A decrease of $170 million due to lower volumes of retail electric load served as a result of the expiration of existing retail contracts.

• A decrease of $72 million due to lower construction activities as a result of reduced high voltage construction and maintenance projects.

• A decrease of $20 million due to lower retail natural gas prices partially offset by higher customer load as a result of customer acquisitions.

• A decrease of $3 million due to lower generation output as a result of milder weather and lower overall load levels for the PJM RTO control area.

Other Non-Regulated

Other Non-Regulated revenues increased by $111 million from a $60 million loss in 2008 to a $51 million gain in 2009. This was primarily the result of a non-cash charge of $124 million that was recorded in the quarter ended June 30, 2008 as a result of revised assumptions regarding the estimated timing of tax benefits from cross-border energy lease investments of Potomac Capital Investment Corporation and its subsidiaries (PCI). In accordance with Financial Accounting Standards Board (FASB) guidance on leases (Accounting Standards Codification (ASC) 840), the charge was recorded as a reduction to lease revenue from these transactions, which is included in Other Non-Regulated revenues.

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:

	2009			2008			Change
Power Delivery	$	3,243		$	3,578		$	(335	)
Pepco Energy Services		2,179			2,489			(310	)
Corporate and Other		(7	)		(13	)		6
Total	$	5,415		$	6,054		$	(639	)

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Power Delivery Business

Power Delivery’s Fuel and Purchased Energy (other than expense associated with Regulated Gas Revenue and Other Gas revenue) consists of the cost of electricity purchased by its utility subsidiaries to fulfill their respective Default Electricity Supply obligations and, as such, is recoverable from customers in accordance with the terms of public service commission orders. Fuel and Purchased Energy expense decreased by $335 million primarily due to:

• A decrease of $236 million primarily due to commercial customer migration to competitive suppliers.

• A decrease of $73 million in the cost of natural gas purchases for off-systems sales, the result of lower average natural gas prices and volumes purchased.

• A decrease of $53 million (which is matched by a corresponding decrease in Other Regulated T&D Electric Revenue) due to the transfer of the Panda PPA.

• A decrease of $33 million due to lower electricity sales as a result of milder weather primarily during the 2009 summer months as compared to 2008.

• A decrease of $30 million in the cost of natural gas purchases for system sales, the result of lower average natural gas prices and volumes purchased.

• A decrease of $23 million due to lower average electricity costs under Default Electricity Supply contracts.

The aggregate amount of these decreases was partially offset by:

• An increase of $63 million due to a higher rate of recovery of electricity supply costs resulting in a decrease in the Default Electricity Supply deferral balance.

• An increase of $43 million from the settlement of financial hedges entered into as part of DPL’s hedge program for regulated natural gas.

• An increase of $12 million due to a higher rate of recovery of natural gas supply costs primarily as a result of recognizing the unbilled portion of Gas Cost Rate revenue in 2009, as discussed under Regulated Gas Revenue.

Pepco Energy Services

Pepco Energy Services’ Fuel and Purchased Energy and Other Services Cost of Sales decreased $310 million primarily due to:

• A decrease of $212 million due to lower volumes of electricity purchased to serve decreased retail customer load as the result of the continuing expiration of existing retail contracts.

• A decrease of $45 million due to lower wholesale natural gas prices partially offset by higher retail customer load as the result of customer acquisitions.

• A decrease of $42 million due to lower construction activities as a result of reduced high voltage construction and maintenance projects.

• A decrease of $11 million due to lower generation output due to milder weather and lower overall load levels for the PJM control area.

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Other Operation and Maintenance

A detail of PHI’s other operation and maintenance expense is as follows:

	2009			2008			Change
Power Delivery	$	752		$	702		$	50
Pepco Energy Services		90			87			3
Other Non-Regulated		2			2			—
Corporate and Other		(25	)		(16	)		(9	)
Total	$	819		$	775		$	44

Other Operation and Maintenance expense for Power Delivery increased by $50 million; however, excluding a decrease of $5 million primarily related to administrative expenses that are deferred and recoverable in Default Electricity Supply Revenue, Other Operation and Maintenance expense increased by $55 million. The $55 million increase was primarily due to:

• An increase of $39 million in employee-related costs, primarily due to higher pension and other postretirement benefit expenses.

• An increase of $13 million primarily due to higher preventative and corrective maintenance, and emergency restoration costs.

• An increase of $4 million in regulatory expenses primarily incurred in connection with the District of Columbia distribution rate case.

• An increase of $3 million due to higher non-deferrable bad debt expenses.

During 2008, PHI recorded adjustments, on a consolidated basis, to correct errors in Other Operation and Maintenance expenses for prior periods dating back to February 2005 during which (i) customer late payment fees were incorrectly recognized and (ii) stock-based compensation expense related to certain restricted stock awards granted under the Long-Term Incentive Plan was understated. The late payment fees and stock-based compensation adjustments resulted in increases in Other Operation and Maintenance expenses for the year ended December 31, 2008 of $6 million and $9 million, respectively. These adjustments were not considered material either individually or in the aggregate.

Depreciation and Amortization

Depreciation and Amortization expense increased by $11 million to $349 million in 2009 from $338 million in 2008 primarily due to an increase of $14 million due to utility plant additions and $4 million due to the accelerated depreciation of Pepco Energy Services generating facilities that will be decommissioned in 2012, partially offset by a decrease of $7 million due to lower amortization by ACE of stranded costs primarily as the result of lower revenue due to decreases in the Market Transition Charge Tax rate in October 2009 and October 2008 (partially offset in Default Electricity Supply Revenue).

Other Taxes

Other Taxes increased by $13 million to $368 million in 2009 from $355 million in 2008. 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) resulting from rate increases in utility taxes imposed by the taxing jurisdictions.

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Deferred Electric Service Costs

Deferred Electric Service Costs, which relate only to ACE, decreased by $152 million, to an expense reduction of $161 million in 2009 as compared to an expense reduction of $9 million in 2008. The decrease was primarily due to:

• A decrease of $186 million due to a lower rate of recovery of costs from the resale in the PJM RTO market of energy and capacity purchased under the NUG contracts.

The decrease was partially offset by:

• An increase of $15 million due to a higher rate of recovery through customer rates of deferred energy supply costs for Default Electricity Supply (included in Default Electricity Supply Revenue).

• An increase of $13 million due to a higher rate of recovery through customer rates of New Jersey Societal Benefit program costs (included in Regulated T&D Electric Revenue).

• An increase of $5 million due to a higher rate of recovery through customer rates of deferred transmission costs for Default Electricity Supply (included in Default Electricity Supply Revenue).

Effect of Settlement of Mirant Bankruptcy Claims

In September 2008, Pepco transferred the Panda PPA to an unaffiliated third party. 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 Panda PPA. As a result, Pepco recorded a pre-tax gain of $14 million 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 remaining after the transfer of the Panda PPA. As a result, Pepco recorded a pre-tax gain of $26 million reflecting the Maryland proceeds retained by Pepco.

Gain on Sale of Assets

Gain on Sale of Assets decreased by $3 million in 2009 due to a $3 million gain on the sale of the Virginia retail electric distribution and wholesale transmission assets in January 2008.

Other Income (Expenses)

Other Expenses (which are net of Other Income) increased by $45 million to a net expense of $321 million in 2009 from a net expense of $276 million in 2008, primarily due to an increase in interest expense. The increase in interest expense was due to a $33 million increase in interest expense on long-term debt as the result of a higher amount of outstanding debt, and an increase of $13 million in interest expense on short-term debt due primarily to the Pepco Energy Services credit intermediation agreement, as described below under the heading “Capital Resources and Liquidity - Collateral Requirements of Pepco Energy Services.”

Income Tax Expense

PHI’s consolidated effective tax rates from continuing operations for the years ended December 31, 2009 and 2008 were 31.8% and 33.0%, respectively. The decrease in the rate primarily resulted from 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 the tax reporting for the disposition of certain assets in prior years, and from the 2008 charge related to the cross-border energy lease investments described in Note (17), “Commitments and Contingencies,” and corresponding state tax benefits related to the charge.

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Discontinued Operations

Income from Discontinued Operations, net of income taxes, decreased by $105 million to $12 million in 2009 from $117 million in 2008. The decrease was primarily due to lower Conectiv Energy earnings as the result of (i) a $79 million decrease resulting from significantly reduced spark (natural gas) spreads, dark (coal) spreads and lower run-time, (ii) a $63 million decrease primarily related to economic fuel hedges that were favorable in 2008 due to rising fuel prices and unfavorable in 2009 due to falling fuel prices; partially offset by (iii) a $39 million increase due to higher capacity margins caused primarily by higher Reliability Pricing Model clearing prices.

Capital Resources and Liquidity

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

Working Capital

At December 31, 2010, Pepco Holdings’ current assets on a consolidated basis totaled $1.8 billion and its current liabilities totaled $1.8 billion. PHI expects the working capital deficit at December 31, 2010 to be funded during 2011 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 and the completion of the disposition of the Conectiv Energy business. At December 31, 2009, Pepco Holdings’ current assets on a consolidated basis totaled $1.9 billion and its current liabilities totaled $2.3 billion. The increase in working capital from December 31, 2009 to December 31, 2010 is primarily due to a reduction in the current portion of long-term debt.

At December 31, 2010, Pepco Holdings’ cash and current cash equivalents totaled $21 million, of which $1 million is reflected on the balance sheet in Conectiv Energy assets held for sale, 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, 2009, Pepco Holdings’ cash and current cash equivalents totaled $46 million, of which $2 million is 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, 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

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	As of December 31, 2009
	(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		324		—		—		60		—		—		384
Total Short-Term Debt	$	324	$	—	$	105	$	83	$	—	$	18	$	530
Current Maturities of Long-Term Debt and Project Funding	$	450	$	16	$	31	$	1	$	34	$	4	$	536

Credit Facilities

PHI, Pepco, DPL and ACE maintain an unsecured credit facility to provide for their respective short-term liquidity needs. The aggregate borrowing limit under this credit facility is $1.5 billion, all or any portion of which may be used to obtain loans or to issue letters of credit. PHI’s credit limit under the facility is $875 million. The credit limit of each of Pepco, DPL and ACE is the lesser of $500 million and the maximum amount of debt the company is permitted to have outstanding by its regulatory authorities, except that the aggregate amount of credit used by Pepco, DPL and ACE at any given time collectively may not exceed $625 million. 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 and the federal funds effective rate plus 0.5%, or (ii) the prevailing Eurodollar rate, plus a margin that varies according to the credit rating of the borrower. 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 $150 million. Any swingline loan must be repaid by the borrower within seven days of receipt thereof.

The facility commitment expiration date is May 5, 2012, with each company having the right to elect to have 100% of the principal balance of the loans outstanding on the expiration date continued as non-revolving term loans for a period of one year from such expiration date.

The facility is intended to serve primarily as a source of liquidity to support the commercial paper programs of the respective companies. The companies also are permitted to use the facility to borrow funds for general corporate purposes and issue letters of credit. 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 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) a restriction on sales or other dispositions of assets, other than certain sales and dispositions, 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 absence of a material adverse change in the borrower’s business, property, and results of operations or financial condition is not a condition to the availability of credit under the facility. The facility does not include any rating triggers.

On October 15, 2010, a $400 million unsecured credit facility maintained by PHI expired. To replace this facility, PHI, on October 27, 2010, entered into two bi-lateral 364 day unsecured credit agreements totaling $200 million. Under each of the credit agreements, PHI has access to revolving and floating rate loans over the terms of the agreements. Neither agreement provides for the issuance of letters of credit. The interest rate payable on funds borrowed is at PHI’s election, based on either (a) the prevailing Eurodollar rate plus 2.0% or (b) the highest of (i) the prevailing prime rate, (ii) the federal funds effective rate plus 0.5% or (iii) the one-month Eurodollar rate plus 1.0%, plus a margin of 1.0%. In order to obtain loans under either of the agreements, PHI must be in compliance with the same covenants and conditions that it is required to satisfy for utilization of its existing $1.5 billion credit facility. The absence of a material adverse change in PHI’s business, property, and results of operations or financial condition is not a condition to the availability of credit under either agreement. Neither agreement includes any rating triggers.

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The $1.5 billion credit facility and the two bi-lateral credit agreements are referred to herein collectively as PHI’s “primary credit facilities.” As of December 31, 2010, each borrower was in compliance with the covenants of each of the primary credit facilities.

On November 2, 2010, PHI’s $50 million bi-lateral credit agreement with The Bank of Nova Scotia expired. Both the $400 million PHI facility that expired in October 2010 and this agreement were established to provide additional liquidity and collateral support for Pepco Energy Services’ retail energy supply business and for the operations of Conectiv Energy. Based on the progress toward winding down the retail energy supply business and disposing of the Conectiv Energy segment, the level of liquidity and collateral needed to support these businesses has decreased. As a result, PHI has been able to reduce the total amount of its credit facility needs by $250 million.

Cash and Credit Facilities Available as of December 31, 2010

	Consolidated PHI		PHI Parent		Utility Subsidiaries
	(millions of dollars)
Credit Facilities (Total Capacity)	$	1,700	$	1,075	$	625
Less: Letters of Credit issued		122		117		5
Commercial Paper outstanding		388		230		158
Remaining Credit Facilities Available		1,190		728		462
Cash Invested in Money Market Funds (a)		—		—		—
Total Cash and Credit Facilities Available	$	1,190	$	728	$	462

(a) Cash and cash equivalents reported on the balance sheet total $20 million which was all held in cash and uncollected funds.

Collateral Requirements

At December 31, 2010 and 2009, the amount of cash, plus borrowing capacity under the primary credit facilities available to meet the future liquidity needs of Pepco Energy Services and Conectiv Energy totaled $728 million and $820 million, respectively.

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) agreed to supply 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 are being 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, 2010 and 2009, approximately $8 million and $16 million, respectively, of the fees have been amortized and reflected in interest expense. As the retail electric and natural gas supply businesses are wound down, Pepco Energy Services’ collateral requirements will be further reduced.

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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, 2010, Pepco Energy Services had posted net cash collateral of $117 million and letters of credit of $113 million. At December 31, 2009, Pepco Energy Services had posted net cash collateral of $123 million and letters of credit of $157 million.

Remaining Collateral Requirements of Conectiv Energy

Depending on the contract terms, the collateral required to be posted by Conectiv Energy is of varying forms, including cash and letters of credit. As of December 31, 2010, Conectiv Energy had posted net cash collateral of $104 million and there were no outstanding letters of credit. At December 31, 2009, Conectiv Energy had posted net cash collateral of $240 million and letters of credit of $22 million.

On January 6, 2011, as part of its ongoing divestiture efforts, Conectiv Energy entered into a financial transaction with a third party under which Conectiv Energy transferred 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 derivative instruments at February 1, 2011 and an administrative fee of approximately $2 million that will be expensed in the first quarter of 2011. No additional material gain or loss will be recognized as a result of this transaction as the derivatives were previously marked to fair value through earnings in 2010. Approximately $68 million of collateral was returned to Conectiv Energy upon the closing of the transaction in January 2011. Approximately $11 million of the remaining $36 million in outstanding collateral will be returned to Conectiv Energy in connection with this transaction upon the novation of several over-the-counter transactions.

All of the remaining posted cash collateral, other than the $11 million referred to above, is held by the PJM and ISO New England Inc. regional transmission organizations and will be returned within the next several months upon completion of a reconciliation process.

Pension and Other Postretirement Benefit Plans

In 2008, the pension and other postretirement benefit plans maintained by PHI experienced significant declines in the fair value of plan assets, which has resulted in increased pension and other postretirement benefit costs in 2009 and 2010 and increased plan funding requirements.

Based on the results of the 2010 actuarial valuation, PHI’s net periodic pension and other postretirement benefit costs were approximately $116 million in 2010 versus $149 million in 2009. The current estimate of benefit cost for 2011 is $107 million. The utility subsidiaries are responsible for substantially all of the total PHI net periodic pension and other postretirement benefit costs. Approximately 30% of net periodic pension and other postretirement benefit costs are capitalized. PHI estimates that its net periodic pension and other postretirement benefit expense will be approximately $75 million in 2011, as compared to $81 million in 2010 and $103 million in 2009.

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Pension benefits are provided under PHI’s defined benefit pension plan (the PHI Retirement Plan), a non contributory retirement 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 funding target as defined under the Pension Protection Act of 2006. The funding target under the Pension Protection Act is an amount that is being phased in over time. The funding target was 96% of the accrued liability for 2010 and is 100% of the accrued liability for 2011.

During 2010, PHI Service Company made discretionary tax-deductible contributions totaling $100 million to the PHI Retirement Plan, which brought plan assets to at least the funding target level for 2010 under the Pension Protection Act. Pepco, ACE and DPL did not make contributions to the pension plan in 2010.

In 2009, PHI made discretionary tax-deductible contributions totaling $300 million to the PHI Retirement Plan, which brought plan assets to at least the funding target level for 2009 under the Pension Protection Act. Of this amount, $240 million was contributed through tax-deductible contributions from Pepco, ACE and DPL in the amounts of $170 million, $60 million and $10 million, respectively. The remaining $60 million contribution was made through tax-deductible contributions from PHI Service Company.

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 in 2010, 2009 and 2008 and does not expect to have any required contributions in 2011. Although PHI projects there will be no minimum funding requirement under the Pension Protection Act guidelines in 2011, PHI currently estimates it may make discretionary tax-deductible contributions in 2011 of up to $150 million to bring the PHI Retirement Plan assets to at least the funding target level for 2011 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, set forth in Part II, Item 8 of this Form 10-K.

Cash Flow Activity

PHI’s cash flows during 2010, 2009, and 2008 are summarized below:

	Cash (Use) Source
	2010			2009			2008
	(millions of dollars)
Operating Activities	$	813		$	606		$	413
Investing Activities		718			(860	)		(714	)
Financing Activities		(1,556	)		(84	)		630
Net (decrease) increase in cash and cash equivalents	$	(25	)	$	(338	)	$	329

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Operating Activities

Cash flows from operating activities during 2010, 2009, and 2008 are summarized below:

	Cash Source (Use)
	2010			2009			2008
	(millions of dollars)
Net Income from continuing operations	$	139		$	223		$	183
Non-cash adjustments to net income		349			260			390
Pension contributions		(100	)		(300	)		—
Changes in cash collateral related to derivative activities		13			24			(138	)
Changes in other assets and liabilities		164			296			22
Changes in Conectiv Energy net assets held for sale		248			103			(44	)
Net cash from operating activities	$	813		$	606		$	413

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 compared to 2009 and a decrease in regulatory liabilities during the year ended December 31, 2010 as 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 as further described in Note (20), “Discontinued Operations.”

Net cash from operating activities was $193 million higher for the year ended December 31, 2009, compared to the same period in 2008. A portion of this increase is attributable to the release from restricted cash of $102 million related to the Mirant settlement and the 2009 receipt of a Federal income tax refund from the IRS of $138 million associated with the carryback of a 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 deductible for 2008) and the cumulative effect of adopting a new method of tax reporting for certain repairs. PHI also experienced reduced cash requirements related to purchases of inventory (associated with lower natural gas and electric prices). Offsetting these increases were the pension plan contributions of $300 million made during 2009. The change in Conectiv Energy net assets held for sale included a decrease of $99 million in collateral requirements between 2008 and 2009.

Net cash from operating activities in 2008 included a non-cash charge taken on the cross-border energy lease investments, and additional collateral requirements of $138 million primarily related to Pepco Energy Services’ retail energy supply business.

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Investing Activities

Cash flows used by investing activities during 2010, 2009, and 2008 are summarized below:

	Cash (Use) Source
	2010			2009			2008
	(millions of dollars)
Investment in property, plant and equipment	$	(802	)	$	(664	)	$	(643	)
DOE capital reimbursement awards received		13			—			—
Proceeds from sale of Conectiv Energy wholesale power generation business		1,640			—			—
Proceeds from sale of assets		3			4			56
Net other investing activities		2			—			11
Investment in property, plant and equipment associated with Conectiv Energy assets held for sale		(138	)		(200	)		(138	)
Net cash from (used by) investing activities	$	718		$	(860	)	$	(714	)

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 July 1, 2010 sale of the Conectiv Energy wholesale power generation business offset by a $143 million increase in Power Delivery capital expenditures primarily attributable to capital costs associated with transmission plant investment and PHI’s Blueprint for the Future initiatives.

Net cash used by investing activities increased by $146 million for the year ended December 31, 2009 compared to the same period in 2008. The increase was due primarily to an $83 million increase in capital expenditures, of which $62 million was attributable to Conectiv Energy assets held for sale and $35 million was attributable to Power Delivery, partially offset by a decrease in Pepco Energy Services capital expenditures. The increase in Conectiv Energy capital expenditures was primarily due to the construction of new generating facilities. The increase in Power Delivery capital expenditures was primarily attributable to capital costs associated with the Mid-Atlantic Power Pathway (MAPP) and Blueprint for the Future projects. The increase in cash used by investing activities also reflected a $52 million reduction in cash proceeds from the sale of other assets, primarily due to the receipt by DPL in 2008 of cash proceeds in the amount of $54 million from the sale of its retail electric distribution and wholesale electric transmission assets in Virginia.

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Financing Activities

Cash flows used by financing activities during 2010, 2009 and 2008 are summarized below.

	Cash (Use) Source
	2010			2009			2008
	(millions of dollars)
Dividends paid on common and preferred stock	$	(241	)	$	(238	)	$	(222	)
Common stock issued for the Dividend Reinvestment Plan and employee-related compensation		47			49			51
Issuance of common stock		—			—			265
Issuances of long-term debt		383			110			1,150
Reacquisition of long-term debt		(1,726	)		(83	)		(590	)
Issuances (repayments) of short-term debt, net		4			65			26
Cost of issuances		(7	)		(4	)		(30	)
Net other financing activities		(6	)		10			(21	)
Net financing activities associated with Conectiv Energy assets held for sale		(10	)		7			1
Net cash (used by) provided by financing activities	$	(1,556	)	$	(84	)	$	630

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

Net cash from financing activities decreased $714 million for the year ended 2009, compared to the same period in 2008, principally due to the decrease in 2009 of issuances of long-term debt and common stock, partially offset by the decrease in amounts spent to reacquire long-term debt.

Common Stock Dividends

Common stock dividend payments were $241 million in 2010, $238 million in 2009, and $222 million in 2008. The increase in common dividends paid in 2010 was the result of additional shares outstanding, primarily shares issued under the Shareholder Dividend Reinvestment Plan (DRP). The increase in common dividends paid in 2009 was the result of additional shares outstanding, primarily due to PHI’s sale of 16.1 million shares of common stock in November 2008.

Changes in Outstanding Common Stock

In November 2008, PHI sold 16.1 million shares of common stock in a registered offering at a price per share of $16.50, resulting in gross proceeds of $265 million.

Under the DRP, PHI issued 1.8 million shares of common stock in 2010, 2.2 million shares of common stock in 2009, and 1.3 million shares of common stock in 2008.

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Changes in Outstanding Long-Term Debt

Cash flows from the issuance and redemption of long-term debt in 2010, 2009 and 2008 are summarized in the charts below:

	2010		2009		2008
Issuances	(millions of dollars)
PHI
2.70% senior notes due 2015	$	250	$	—	$	—
		250		—		—
Pepco
6.20% tax-exempt bonds due 2022 (a)		—		110		—
6.50% senior notes due 2037 (b)		—		—		250
7.90% first mortgage bonds due 2038		—		—		250
		—		110		500
DPL
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		—		—
6.40% first mortgage bonds due 2013		—		—		250
		109		—		250	(f)
ACE
4.875% tax-exempt bonds due 2029 (e)		23		—		—
7.75% first mortgage bonds due 2018		—		—		250
		23		—		250
Pepco Energy Services		1		—		—
	$	383	$	110	$	1,000

(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, set forth in Part II, Item 8 of this Form 10-K.

(b) Secured by an outstanding series of Collateral First Mortgage Bonds. See Note (11), “Debt,” to the consolidated financial statements of PHI, set forth in Part II, Item 8 of this Form 10-K.

(c) Consists of Gas Facilities Refunding Revenue Bonds issued by the Delaware Economic Development Authority (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 Redemptions and Repurchases 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, set forth in Part II, Item 8 of this Form 10-K.

(f) Excludes DPL $150 million two year bank loan that was converted to a 364-day bank loan.

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	2010		2009		2008
Redemptions	(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		—
6.5% first mortgage bonds due 2008		—		—		78
Auction rate, tax-exempt bonds due 2022 (b)		—		—		110
5.875% first mortgage bonds due 2008		—		—		50
		16		50		238
DPL
5.5% tax-exempt bonds due 2025 (c)		15		—		—
5.65% tax-exempt bonds due 2028 (c)		16		—		—
Auction rate, tax-exempt bonds due 2030-2038 (b)		—		—		58
Auction rate, tax-exempt bonds due 2030-2031 (b)		—		—		36
6.95% first mortgage bonds due 2008		—		—		4
Auction rate, tax-exempt bonds due 2023 (b)		—		—		18
		31		—		116
ACE
7.25% medium-term notes due 2010		1		—		—
6.79% medium-term notes due 2008		—		—		15
Auction rate, tax-exempt bonds due 2029 (b)		—		—		55
6.77% medium-term notes due 2008		—		—		1
6.73%-6.75% medium-term notes due 2008		—		—		25
6.71%-6.73% medium-term notes due 2008		—		—		9
Securitization bonds due 2008-2010		34		32		31
		35		32		136
PCI
8.24% medium-term note due 2008		—		—		92
		—		—		92
Pepco Energy Services		—		1		8
	$	1,726	$	83	$	590

(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 the indicated company pending resale to the public. See “Purchase and Resale of Tax-Exempt Auction Rate Bonds” below.

(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

In 2008, PHI subsidiaries purchased at par $276 million in aggregate principal amount of insured tax-exempt auction rate bonds issued by municipal authorities for the benefit of the respective PHI subsidiaries. See footnote (b) to the Redemptions table above. These purchases were made in response to disruption in the market for municipal auction rate securities that made it difficult for the remarketing agent to successfully remarket the bonds at that time. Upon the purchase of the tax-exempt bonds, the obligations of the PHI subsidiaries with respect to these tax-exempt bonds were considered to be extinguished for accounting purposes; however, each of the companies continued to hold the bonds, while monitoring the market and evaluating the options for reselling the bonds to the public at some time in the future.

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

DPL purchased Exempt Facilities Refunding Revenue Bonds issued by DEDA in the aggregate principal amount of $112 million. In 2009, DPL redeemed $33 million in principal amount of the bonds. 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 the bonds purchased in 2008. See footnote (c) to the Issuances table above.

ACE purchased (i) Pollution Control Revenue Refunding Bonds issued by Cape May County in the aggregate principal amount of $32 million and (ii) Pollution Control Revenue Refunding Bonds issued by Salem County in the aggregate principal amount of $23 million. In 2009, ACE redeemed $32 million in principal amount of the bonds. In March 2010, the remaining $23 million in aggregate principal amount of the bonds was resold by ACE to the public. See footnote (e) to the Issuances table above.

Changes in Short-Term Debt

As of December 31, 2010, PHI had a total of $388 million of commercial paper outstanding as compared to $384 million of commercial paper outstanding at December 31, 2009 and no commercial paper outstanding at December 31, 2008.

Due to the capital and credit market disruptions in 2008, the market for commercial paper was severely restricted. As a result, PHI and its subsidiaries were unable to issue commercial paper on a day-to-day basis either in amounts, or with maturities, that were typically required for cash management purposes. Given their restricted access to the commercial paper market and the general uncertainty in the credit markets, PHI and each of its subsidiaries borrowed under the $1.5 billion credit facility to create a cash reserve for future short-term operating needs. As of December 31, 2008, PHI had a loan of $50 million outstanding and Pepco had a loan of $100 million outstanding under this facility. These loans were repaid in 2009.

In 2008, both DPL and Pepco entered into short-term bank loans. In March 2008, DPL obtained a $150 million unsecured bank loan that was repaid in July 2009. In May 2008, Pepco obtained a $25 million bank loan that was repaid in April 2009 and a $25 million bank loan that was repaid in September 2008.

In 2008 and 2009, the following insured Variable Rate Demand Bonds issued by The Pollution Control Financing Authority of Salem County for the benefit of ACE (ACE VRDBs) were tendered to The Bank of New York Mellon, as 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.

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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 issued by The Bank of New York Mellon. 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 2014. 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.

In November 2008, DPL repurchased $9 million of Variable Rate Demand Bonds issued by DPL that were due 2024.

For a further description of the Variable Rate Demand Bonds issued by or for the benefit of PHI’s utility subsidiaries, see Note (11), “Debt,” to the consolidated financial statements of PHI, set forth in Part II, Item 8 of this Form 10-K.

Sale of Virginia Retail Electric Distribution and Wholesale Transmission Assets

In January 2008, DPL completed (i) the sale of its retail electric distribution assets on the Eastern Shore of Virginia for a purchase price of approximately $49 million, and (ii) the sale of its wholesale electric transmission assets located on the Eastern Shore of Virginia for a purchase price of approximately $5 million.

Capital Requirements

Capital Expenditures

Pepco Holdings’ total capital expenditures for the year ended December 31, 2010 totaled $802 million, of which $359 million was incurred by Pepco, $250 million was incurred by DPL and $156 million was incurred by ACE, $7 million by Pepco Energy Services and $30 million by 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 which will be allocated to the Power Delivery Business 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 2011 through 2015. Pepco Holdings expects to fund these expenditures through internally generated cash and external financing.

	For the Year
	2011			2012			2013			2014		2015		Total
	(millions of dollars)
Power Delivery
Distribution	$	511		$	479		$	483		$	526	$	544	$	2,543
Distribution - Blueprint for the Future		128			59			8			92		—		287
Transmission		245			225			197			137		171		975
Transmission - MAPP		163			362			304			213		105		1,147
Gas Delivery		20			20			20			20		20		100
Other		75			50			44			42		53		264
Sub-Total		1,142			1,195			1,056			1,030		893		5,316
DOE Capital Reimbursement Awards (a)		(70	)		(26	)		(4	)		—		—		(100	)
Total for Power Delivery Business		1,072			1,169			1,052			1,030		893		5,216
Pepco Energy Services		16			12			9			2		1		40
Corporate and Other		3			3			3			3		3		15
Total PHI	$	1,091		$	1,184		$	1,064		$	1,035	$	897	$	5,271

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

• $105 million and $44 million in Pepco’s Maryland and District of Columbia service territories, respectively for the implementation of an 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 2010, Pepco received award payments of $15 million and ACE received award payments of $2 million.

The Internal Revenue Service 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), transmission (other than the MAPP project) and natural gas are primarily for facility replacements and upgrades to accommodate customer growth and reliability.

During 2010, Pepco announced Comprehensive Reliability Enhancement Plans for Maryland and the District of Columbia. For a more detailed discussion of these plans, see Item 1, “Business - Description of Business - Other Power Delivery Initiatives and Activities - Reliability Enhancement Plans” of this Form 10-K.

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 are designed to enhance reliability of ACE’s distribution system and support economic activity and job growth in New Jersey in the near term. ACE will achieve cost recovery through an Infrastructure Investment Surcharge, which became effective on June 1, 2009. This approved plan added incremental capital spending of approximately $8 million for 2009 and $19 million for 2010, and is expected to add an additional $1 million of capital spending for 2011, which is included in Distribution in the table above.

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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 they refer to as the Blueprint for the Future. For a discussion of the Blueprint for the Future initiative, see Item 1, “Business - Description of Business - Blueprint for the Future” of this Form 10-K. 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 230-mile, 500-kilovolt interstate transmission line as part of PJM’s regional transmission expansion plan. For a description of the MAPP project, see Item 1, “Business - Description of Business - MAPP Project” of this Form 10-K. 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 Department of Energy (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.

Smart Grid Workforce Training Grant

In April 2010, the DOE awarded $4 million in federal stimulus funds to PHI as part of a three year Smart Grid Workforce Training Grant. PHI and its utility subsidiaries will use the grant to train employees in new roles as energy specialists and energy advisors, as well as to provide enhanced or supplementary training for existing roles such as customer service representatives, billing specialists and distribution engineers. PHI began the training activities in the spring of 2010.

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 2010, PHI’s Board of Directors declared quarterly dividends of 27 cents per share of common stock payable on March 31, 2010, June 30, 2010, September 30, 2010 and December 31, 2010.

On January 27, 2011, the Board of Directors declared a dividend on common stock of 27 cents per share payable March 31, 2011, to shareholders of record on March 10, 2011.

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 existing and future preferred stock, 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 and DPL have no 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 $1,059 million and $1,268 million of retained earnings free of restrictions at December 31, 2010 and 2009, 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, 2010, 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		388		388		—		—		—
Long-term debt (a)		4,042		71		626		743		2,602
Long-term project funding		19		4		4		3		8
Interest payments on debt		3,326		238		467		374		2,247
Capital leases		136		15		30		30		61
Operating leases		533		34		64		58		377
Estimated pension plan contributions		150		150		—		—		—
Non-derivative fuel and purchase power contracts (b)		5,613		922		1,064		711		2,916
Total (c)	$	14,353	$	1,968	$	2,255	$	1,919	$	8,211

(a) Includes transition bonds issued by Atlantic City Electric Transition Funding, LLC.

(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 $148 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

For a 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, set forth in Part II, Item 8 of this Form 10-K.

Energy Contract Net Asset Activity

The following table provides detail on changes in the net asset or liability positions of both the Pepco Energy Services segment and the former Conectiv Energy segment with respect to energy commodity contracts for the year ended December 31, 2010. The balances in the table are pre-tax and the derivative assets and liabilities reflect netting by counterparty before the impact of collateral.

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	Energy Commodity Activities (a)
	(millions of dollars)
Total Fair Value of Energy Contract Net Liabilities at December 31, 2009	$	(328	)
Current period unrealized losses		(3	)
Effective portion of changes in fair value - recorded in Accumulated Other Comprehensive Loss		(100	)
Cash flow hedge ineffectiveness - recorded in income		—
Recognition of realized gains (losses) on settlement of contracts		137
Derivative activity associated with Conectiv Energy		76
Total Fair Value of Energy Contract Net Liabilities at December 31, 2010	$	(218	)
Detail of Fair Value of Energy Contract Net Liabilities at December 31, 2010 (see above)
Derivative assets (current assets)	$	22
Derivative assets (non-current assets)		—
Derivative assets held for sale		7
Total Fair Value of Energy Contract Assets		29
Derivative liabilities (current liabilities)		(144	)
Derivative liabilities (non-current liabilities)		(13	)
Derivative liabilities held for sale		(90	)
Total Fair Value of Energy Contract Liabilities		(247	)
Total Fair Value of Energy Contract Net Liabilities	$	(218	)

(a) Includes all effective hedging activities recorded at fair value through AOCL or trading activities recorded at fair value in the consolidated statements of income, as required.

The $218 million net liability on energy contracts at December 31, 2010 was primarily attributable to losses on power swaps and natural gas futures and swaps designated as hedges of future energy purchases for delivery to retail customers under FASB guidance on derivatives and hedging (ASC 815). Prices of electricity and natural gas declined during the year, which resulted in unrealized losses on the energy contracts of Pepco Energy Services and Conectiv Energy. Pepco Energy Services recorded unrealized losses of $100 million on energy contracts in AOCL as these energy contracts were effective hedges under the FASB guidance. PHI expects that when these energy contracts settle, the related realized gains or losses will be largely offset by the realized loss or gain on future energy purchases or production that will be used to settle the sales obligations with its customers.

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PHI uses its best estimates to determine the fair value of the commodity and derivative contracts that are held and sold by Pepco Energy Services and Conectiv Energy. The fair values in each category presented below reflect forward prices and volatility factors as of December 31, 2010 and are subject to change as a result of changes in these factors.

	Fair Value of Contracts at December 31, 2010 Maturities
Source of Fair Value	2011			2012			2013			2014 and Beyond			Total Fair Value
	(millions of dollars)
Energy Commodity Activities, net (a)
Actively Quoted (i.e., exchange-traded) prices	$	(54	)	$	(19	)	$	(6	)	$	(1	)	$	(80	)
Prices provided by other external sources (b)		(93	)		(42	)		(6	)		—			(141	)
Modeled (c)		—			—			1			2			3
Total	$	(147	)	$	(61	)	$	(11	)	$	1		$	(218	)

Notes:

(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, 2010, 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 $359 million, $62 million of which is related to the discontinued operations of Conectiv Energy, and $176 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, set forth in Part II, Item 8 of this Form 10-K. The remaining $121 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 utility 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, 2010, Pepco Energy Services provided net cash collateral in the amount of $117 million and Conectiv Energy provided net cash collateral in the amount of $104 million in connection with these activities.

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Environmental Remediation Obligations

PHI’s accrued liabilities as of December 31, 2010 include approximately $29 million, of which approximately $5 million is expected to be incurred in 2011, 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, set forth in Part II, Item 8 of this Form 10-K. For information regarding projected expenditures for environmental control facilities, see Item 1 “Business — Environmental Matters,” of this Form 10-K. The most significant environmental remediation obligations as of December 31, 2010, were approximately:

• $14 million, of which approximately $600,000 is expected to be incurred in 2011, in environmental investigation and remediation costs payable by Pepco with respect to the Benning Road site.

• $5 million, of which approximately $1 million is expected to be incurred in 2011, 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.

• $4 million, none of which is expected to be incurred in 2011, for potential ISRA compliance remediation costs payable by PHI associated with the retained environmental exposure from the sale of the Conectiv Energy wholesale power generation business.

• $2 million, of which approximately $1.6 million is expected to be incurred in 2011, 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.

• Less than $4 million, payable by various PHI subsidiaries to resolve miscellaneous alleged environmental liabilities. Approximately $115,000 is expected to be incurred in 2011.

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, securities issuances 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 Item 1A, “Risk Factors,” of this Form 10-K 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 the Power Delivery business 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.

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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.

Pepco Holdings maintains an ongoing commercial paper program of up to $875 million. Pepco and DPL have ongoing commercial paper programs of up to $500 million each, and ACE up to $250 million. 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 Delaware Public Service Commission. 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, typically seeks to maintain 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 non-utility generation sources (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 2011, Pepco currently expects to file an electricity base rate increase application in the District of Columbia and Maryland, and ACE currently expects to file an electricity base rate increase application in New Jersey. DPL currently expects to file a natural gas base rate increase application in early 2012.

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 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	%		July 2010
DPL:
Delaware (electricity)		10.00	%		February 2011
Maryland (electricity)		10.00	%		December 2009
Delaware (natural gas)		10.25	%		April 2007
ACE:
New Jersey (electricity)		10.30	%		June 2010

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 company’s 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. For example, 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 (17), “Commitments and Contingencies,” to the consolidated financial statements of PHI set forth in Part II, Item 8, of this Form 10-K.

Legal Proceedings and Other Regulatory Matters

For a discussion of legal proceedings and other regulatory matters, see Note (17), “Commitments and Contingencies,” to the consolidated financial statements of PHI, set forth in Part II, Item 8 of this Form 10-K.

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Critical Accounting Policies

General

Pepco Holdings has identified the following accounting policies, including 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. Pepco Holdings 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 based on the aggregation of components which have similar economic characteristics, similar products and services and operate in a similar regulatory environment. 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 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.

PHI’s November 1, 2010 annual impairment test indicated that its goodwill was not impaired. See Note (6), “Goodwill,” to the consolidated financial statements of PHI, set forth in Part II, Item 8 of this Form 10-K. Although PHI’s market capitalization remained below book value as of December 31, 2010, PHI did not perform an interim goodwill impairment test because its market capitalization relative to book value improved compared to earlier periods in which it performed an interim impairment test and there were no other indicators of potential impairment. PHI performed interim tests of goodwill for impairment as of March 31, 2009 and as of December 31, 2008 as its market capitalization was below its book value at both points in time and its market capitalization relative to book value had significantly declined. PHI concluded that its goodwill was not impaired at these interim dates.

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 the Power Delivery business 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, 2010 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

Pepco Holdings 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 Pepco Holdings’ estimates and the impact of such variations could be material, and (iii) the impact that recognizing an impairment would have on Pepco Holdings’ 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, Pepco Holdings considers historical cash flows. Pepco Holdings 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 done consistent with the process described in assessing the fair value of goodwill discussed above.

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Accounting for Derivatives

Pepco Holdings 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 Pepco Holdings’ 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, set forth in Part II, Item 8 of this Form 10-K for information on PHI’s accounting for derivatives.

Pepco Holdings 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

Pepco Holdings believes that the estimates involved in reporting the costs of providing pension and other postretirement 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 Pepco Holdings’ 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 other postretirement benefit 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 5.65% and 6.40% as of December 31, 2010 and 2009, respectively. The discount rate for determining the postretirement benefit obligation was 5.60% and 6.30% as of December 31, 2010 and 2009, 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.

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The expected long-term rate of return on plan assets was 8.00% and 8.25% as of December 31, 2010 and 2009, respectively. In selecting an expected long-term rate of return on plan assets, PHI considers actual historical returns, economic forecasts and the judgment of its investment consultants on expected long-term performance for the types of investments held by the plan. The estimated asset class returns are weighted by PHI’s target asset allocation. The plan assets consist of equity, fixed income investments, real estate and private equity, and when viewed over a long-term horizon, are expected to yield a return on assets of 8.00% as of December 31, 2010.

Assumptions about the future, including the expected return on plan assets, discount rate applied to benefit obligations, the anticipated rate of increase in health care costs and participant compensation have a significant impact on employee benefit costs.

The following table reflects the effect on the projected benefit obligation and the net periodic cost associated with changing the critical actuarial assumptions while holding all other actuarial assumptions constant:

(in millions, except percentages)	Change in Assumptions			Impact on Projected Benefit Obligation			Projected Increase in 2010 Net Periodic Cost
Pension Plan
Discount rate		(0.25	)%	$	40		$	3
Expected return		(0.25	)%		—	(a)		4
Postretirement Benefit Plan
Discount rate		(0.25	)%	$	16		$	1
Expected return		(0.25	)%		—	(a)		1
Healthcare cost trend		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 immediately recognized in the statements of income.

For additional discussion, see Note (10), “Pension and Other Postretirement Benefits,” to the consolidated financial statements of PHI, set forth in Part II, Item 8 of this Form 10-K.

Accounting for Regulated Activities

FASB guidance on the accounting for regulated activities, Regulated Operations (ASC 980), applies to the Power Delivery businesses of Pepco, DPL, and ACE 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 rates charged to its customers. 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. Pepco Holdings 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 from customers 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) writing off a regulatory asset because deferred costs are no longer probable of recovery in future rates charged to customers could have a material negative impact on Pepco Holdings’ assets and earnings.

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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 reviews its regulatory assets and liabilities to determine whether adjustments to its previous conclusions are necessary based on the current regulatory and legislative environment as well as recent rate orders.

Unbilled Revenue

Unbilled revenue represents an estimate of revenue earned from services rendered by Pepco Holdings’ utility operations that have not yet been billed. Pepco Holdings’ 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 and adjusted for estimated line loss (estimates of electricity and gas expected to be lost in the process of its transmission and distribution to customers).

Pepco Holdings believes that the 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 loss is inherently uncertain. Estimated line loss 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 loss can change the output available for sale which is a factor in the unbilled revenue calculation. Certain factors can influence the estimated line loss 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. Pepco Holdings 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

Pepco Holdings 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 must consider the effect of newly enacted tax law on its estimated effective tax rate and in measuring deferred tax balances; and (vii) it asserts that tax positions in its tax returns or expected to be taken in its tax returns are more likely than not to be sustained assuming that the tax positions will be examined by taxing authorities with full knowledge of all relevant information prior to recording the related tax benefit in the financial statements and that the benefit recognized in the financial statements is the largest amount of benefit that is greater than 50% likely of being realized.

Assumptions, judgment and the use of estimates are required in determining if the “more likely than not” standard has been met when developing the provision for current and deferred income taxes and the associated current and deferred tax assets and liabilities. Pepco Holdings’ assumptions, judgments and estimates take into account current tax laws and regulations, interpretation of current tax laws and

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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. Pepco Holdings has established reserves for income taxes to address potential exposures involving tax positions that could be challenged by tax authorities. Although Pepco Holdings 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. Pepco Holdings reviews its application of the “more likely than not” standard quarterly.

Pepco Holdings also evaluates quarterly the probability of realizing deferred tax assets by reviewing a forecast of future taxable income and the availability of 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, set forth in Part II, Item 8 of this Form 10-K.

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Forward-Looking Statements

Some of the statements contained in this Annual Report on Form 10-K are forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and are subject to the safe harbor created by the Private Securities Litigation Reform Act of 1995. These statements include declarations regarding Pepco Holdings’ intents, beliefs and current expectations. In some cases, you can identify forward-looking statements by terminology such as “may,” “will,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “predicts,” “potential” or “continue” or the negative of such terms or other comparable terminology. Any forward-looking statements are not guarantees of future performance, and actual results could differ materially from those indicated by the forward-looking statements. Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may cause PHI’s 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.

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 Pepco Holdings’ 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;

• Weather conditions affecting usage and emergency restoration costs;

• Population growth rates and changes in demographic patterns;

• Changes in customer demand for electricity and natural gas 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 electricity and natural gas usage;

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

• Changes in tax rates or policies;

• Changes in rates of inflation;

• Changes in accounting standards or practices;

• Unanticipated changes in operating expenses and capital expenditures;

• Rules and regulations imposed by federal and/or state regulatory commissions, PJM, the North American Electric Reliability Corporation and other applicable electric reliability organizations;

• Legal and administrative proceedings (whether civil or criminal) and settlements that affect PHI’s business and profitability;

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• 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.

Any forward-looking statements speak only as to the date of this Annual Report on Form 10-K and Pepco Holdings undertakes no 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 Pepco Holdings to predict all of such factors, nor can Pepco Holdings assess the impact of any such factor on Pepco Holding’s business 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 review of factors should not be construed as exhaustive.

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

Potomac Electric Power Company

Potomac Electric Power Company (Pepco) meets the conditions set forth in General Instruction I(1)(a) and (b) to the Form 10-K, and accordingly information otherwise required under this Item has been omitted in accordance with General Instruction I(2)(a) to the 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 Standard Offer Service (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, 2010, approximately 57% of delivered electricity sales were to Maryland customers and approximately 43% were to the District of Columbia customers.

Effective June 2007, the Maryland Public Service Commission (MPSC) approved a bill stabilization adjustment mechanism (BSA) for retail customers. The District of Columbia Public Service Commission (DCPSC) also approved a BSA for retail customers, effective in November 2009. For customers to whom the BSA applies, Pepco recognizes distribution revenue based on the approved distribution charge per customer. From a revenue recognition standpoint, this has the effect of decoupling distribution revenue recognized in a reporting period from the amount of power delivered during the period. As a consequence, 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. For customers to whom the BSA applies, 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.

As a result of 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 Pepco Holdings, Inc. (PHI or Pepco Holdings). 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 the regulatory oversight of the Federal Energy Regulatory Commission (FERC) under PUHCA 2005.

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Results Of Operations

The following results of operations discussion compares the year ended December 31, 2010 to the year ended December 31, 2009. All amounts in the tables (except sales and customers) are in millions of dollars.

Operating Revenue

	2010		2009		Change
Regulated T&D Electric Revenue	$	1,068	$	947	$	121
Default Electricity Supply Revenue		1,185		1,251		(66	)
Other Electric Revenue		35		33		2
Total Operating Revenue	$	2,288	$	2,231	$	57

The table above shows the amount of Operating Revenue earned that is subject to price regulation (Regulated Transmission & Distribution (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 Interconnection, LLC (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 Standard Offer Service. 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.

Regulated T&D Electric

Regulated T&D Electric Revenue	2010		2009		Change
Residential	$	314	$	271	$	43
Commercial and industrial		631		571		60
Other		123		105		18
Total Regulated T&D Electric Revenue	$	1,068	$	947	$	121

Other Regulated T&D Electric Revenue consists primarily of transmission service revenue.

Regulated T&D Electric Sales (Gigawatt hours (GWh))	2010		2009		Change
Residential		8,350		7,669		681
Commercial and industrial		19,155		18,719		436
Other		160		161		(1	)
Total Regulated T&D Electric Sales		27,665		26,549		1,116

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Regulated T&D Electric Customers (in thousands)	2010		2009		Change
Residential		713		704		9
Commercial and industrial		74		74		—
Other		—		—		—
Total Regulated T&D Electric Customers		787		778		9

Regulated T&D Electric Revenue increased by $121 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 $17 million in transmission revenue primarily attributable to higher rates effective June 1, 2010 related to an increase in transmission plant investment.

• An increase of $14 million due to distribution rate increases in the District of Columbia that became effective in November 2009 and March 2010.

• An increase of $6 million due to higher revenue in the District of Columbia service territory as a result of milder than normal weather during the 2009 spring and summer months as compared to the base period used in establishing the 2010 BSA rates. The BSA was not implemented in the District of Columbia until November 2009; therefore, a change in weather was a factor when comparing revenue from period to period.

• An increase of $10 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).

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

Default Electricity Supply

Default Electricity Supply Revenue	2010		2009		Change
Residential	$	865	$	850	$	15
Commercial and industrial		309		390		(81	)
Other		11		11		—
Total Default Electricity Supply Revenue	$	1,185	$	1,251	$	(66	)
Default Electricity Supply Sales (GWh)	2010		2009		Change
Residential		7,576		7,173		403
Commercial and industrial		3,113		3,739		(626	)
Other		10		10		—
Total Default Electricity Supply Sales		10,699		10,922		(223	)

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Default Electricity Supply Customers (in thousands)	2010		2009		Change
Residential		644		660		(16	)
Commercial and industrial		47		50		(3	)
Other		—		—		—
Total Default Electricity Supply Customers		691		710		(19	)

Default Electricity Supply Revenue decreased by $66 million primarily due to:

• A decrease of $82 million due to lower sales, primarily as a result of commercial customer migration to competitive suppliers.

• A decrease of $47 million as a result of lower Default Electricity Supply rates.

The aggregate amount of these decreases was partially offset by:

• An increase of $67 million due to higher sales primarily as a result of warmer weather during the 2010 spring and summer months as compared to 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.

	2010			2009
Sales to District of Columbia customers		29	%		31	%
Sales to Maryland customers		46	%		49	%

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 $71 million to $1,152 million in 2010 from $1,223 million in 2009 primarily due to:

• A decrease of $85 million primarily due to commercial customer migration to competitive suppliers.

• A decrease of $39 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 $8 million due to lower average electricity costs under Default Electricity Supply contracts.

The aggregate amount of these decreases was partially offset by:

• An increase of $60 million due to higher sales primarily as a result of warmer weather during the 2010 spring and summer months as compared to 2009.

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Other Operation and Maintenance

Other Operation and Maintenance increased by $26 million to $354 million in 2010 from $328 million in 2009. Excluding an increase of $2 million primarily related to bad debt expenses that are deferred and recoverable in Default Electricity Supply Revenue, Other Operation and Maintenance expense increased by $24 million. The $24 million increase was primarily due to:

• An increase of $22 million in emergency restoration costs primarily due to severe storms in February, July and August 2010.

• An increase of $13 million in estimated environmental remediation costs due to the establishment of a reserve relating to a possible discharge of polychlorinated biphenyls (PCBs) at the Benning Road transmission and distribution facility, as further discussed under the heading “Benning Road Site” in Note (13), “Commitments and Contingencies,” to the Pepco financial statements set forth in Part II, Item 8 of this Form 10-K.

• An increase of $3 million primarily due to system support and customer support services costs.

• An increase of $3 million primarily due to higher tree trimming costs.

• An increase of $2 million due to higher non-deferrable bad debt expenses.

The aggregate amount of these increases was partially offset by:

• A decrease of $11 million primarily due to Pepco deferrals 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.

• A decrease of $7 million in employee-related costs, primarily due to lower pension and other postretirement benefit expenses.

Restructuring Charge

With the ongoing wind down of the retail energy supply business of Pepco Energy Services and the disposition of Conectiv Energy, PHI is repositioning itself as a regulated transmission and distribution company. In connection with this repositioning, 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 that are allocated to its operating segments. This review has resulted in the adoption of a restructuring plan. PHI began implementing the plan during the third quarter, identifying 164 employee positions that were eliminated during the fourth quarter of 2010. The plan also focuses on identifying additional cost reduction opportunities through process improvements and operational efficiencies. PHI currently estimates that the implementation of the plan will result in an annual reduction of approximately $28 million in corporate overhead costs.

In connection with the plan, Pepco recorded a pre-tax restructuring charge of $15 million for the year ended December 31, 2010, related to severance, pension, and health and welfare benefits to be provided to terminated employees.

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Depreciation and Amortization

Depreciation and Amortization expense increased by $17 million to $162 million in 2010 from $145 million in 2009 primarily due to:

• An increase of $9 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 $4 million due to utility plant additions.

• An increase of $2 million in the amortization of Demand Side Management deferred expenses.

Other Taxes

Other Taxes increased by $62 million to $364 million in 2010 from $302 million in 2009. The increase was primarily due to increased pass-throughs resulting from utility tax rate increases imposed by Montgomery County, Maryland (which are substantially offset by a corresponding increase in Regulated T&D Electric Revenue).

Effect of 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 is required to distribute to customers by approximately $11 million. While Pepco has filed an appeal of the DCPSC’s decision with the District of Columbia Court of Appeals, in view of the DCPSC order, PHI recognized a pre-tax expense of $11 million for the year ended December 31, 2010. The appeal is still pending.

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 Corporation (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.

Other Income (Expenses)

Other Expenses (which are net of Other Income) decreased by $6 million to a net expense of $85 million in 2010 from a net expense of $91 million in 2009. The decrease was primarily due to:

• An increase of $4 million in income related to Allowance for Funds Used During Construction that is applied to capital projects.

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

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Income Tax Expense

Pepco’s effective tax rates for the years ended December 31, 2010 and 2009 were 25.5% and 41.8%, respectively. The decrease in the effective tax rate resulted primarily from the November 2010 settlement PHI reached with the Internal Revenue Service (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 reallocations, Pepco has recalculated the estimated interest due for the tax years 1996 to 2002. The revised estimate has 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 2010, and is subject to adjustment when the IRS finalizes its calculation of the amount due. This benefit was partially offset by an $8 million reversal of previously recorded tax benefits and $5 million of other adjustments.

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 Item 1A, “Risk Factors,” of this Form 10-K, 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.

Information concerning the principal amount and terms of Pepco’s outstanding debt securities, as of December 31, 2010, is set forth in Note (10), “Debt,” to the financial statements of Pepco set forth in Part II, Item 8 of this Form 10-K.

Bank Financing

As further discussed in Note (10), “Debt,” to the financial statements of Pepco set forth in Part II, Item 8 of this Form 10-K, Pepco participates in a $1.5 billion credit facility, along with PHI, Delmarva Power & Light Company (DPL) and Atlantic City Electric Company (ACE). The facility, all or any portion of which may be used to obtain loans or to issue letters of credit, expires in 2012. Pepco’s credit limit under the facility is the lesser of $500 million and the maximum amount of debt Pepco is permitted to have outstanding by its regulatory authorities, except that the aggregate amount of credit used by Pepco, DPL and ACE at any given time may not collectively exceed $625 million.

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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 PHI $1.5 billion credit facility.

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, 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 seeks to maintain standing authority sufficient to cover its projected financing needs over a multi-year period. Under the Federal Power Act, 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, Pepco is required to obtain FERC authorization for the issuance of short-term debt.

Capital Expenditures

Pepco’s capital expenditures for the year ended December 31, 2010, totaled $359 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 the Power Delivery business 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 2011 through 2015. Pepco expects to fund these expenditures through internally generated cash, external financing and capital contributions from PHI.

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	For the Year
	2011			2012			2013			2014		2015		Total
	(millions of dollars)
Pepco
Distribution	$	291		$	273		$	259		$	288	$	317	$	1,428
Distribution – Blueprint for the Future		103			19			—			—		—		122
Transmission		136			86			74			30		64		390
Transmission – MAPP		112			216			166			139		45		678
Other		28			16			10			13		19		86
Sub-Total		670			610			509			470		445		2,704
DOE Capital Reimbursement Awards (a)		(65	)		(22	)		(3	)		—		—		(90	)
Total Pepco	$	605		$	588		$	506		$	470	$	445	$	2,614

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

Reliability Enhancement Plans

During 2010, Pepco announced Comprehensive Reliability Enhancement Plans for Maryland and the District of Columbia. For a more detailed discussion of these plans, see Item 1, “Business - Description of Business - Other Power Delivery Initiatives and Activities - Reliability Enhancement Plans” of this Form 10-K.

Stimulus Funds Related to Blueprint for the Future

In 2009, the U.S. Department of Energy (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. 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 2010, Pepco received award payments of $15 million.

The Internal Revenue Service 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 (other than the Mid-Atlantic Power Pathway (MAPP) project) are primarily for facility replacements and upgrades to accommodate customer growth and reliability.

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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 Item 1, “Business - Description of Business - Blueprint for the Future” of this Form 10-K. 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 230-mile, 500-kilovolt interstate transmission line as part of PJM’s regional transmission expansion plan. For a description of the MAPP project, see Item 1, “Business - Description of Business - MAPP Project” of this Form 10-K. 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 Department of Energy (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.

Pension and Postretirement Benefit Plans

Pepco participates in pension and postretirement benefit plans sponsored by PHI for its employees. While the plans have not experienced any significant impact in terms of liquidity or counterparty exposure due to the disruption of the capital and credit markets, the stock market declines in 2008 caused a decrease in the market value of benefit plan assets at the end of 2008. Pepco contributed zero and $170 million to the pension plan during 2010 and 2009, respectively.

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Forward-Looking Statements

Some of the statements contained in this Annual Report on Form 10-K are forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and are subject to the safe harbor created by the Private Securities Litigation Reform Act of 1995. These statements include declarations regarding Pepco’s intents, beliefs and current expectations. In some cases, you can identify forward-looking statements by terminology such as “may,” “will,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “predicts,” “potential” or “continue” or the negative of such terms or other comparable terminology. Any forward-looking statements are not guarantees of future performance, and actual results could differ materially from those indicated by the forward-looking statements. Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may cause Pepco’s 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.

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 Pepco’s 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;

• Weather conditions affecting usage and emergency restoration costs;

• Population growth rates and changes in demographic patterns;

• Changes in customer demand for electricity 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 electricity usage;

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

• Changes in tax rates or policies;

• Changes in rates of inflation;

• Changes in accounting standards or practices;

• Unanticipated changes in operating expenses and capital expenditures;

• Rules and regulations imposed by federal and/or state regulatory commissions, PJM, the North American Electric Reliability Corporation and other applicable electric reliability organizations;

• Legal and administrative proceedings (whether civil or criminal) and settlements that affect Pepco’s business and profitability;

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

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• Effects of geopolitical events, including the threat of domestic terrorism.

Any forward-looking statements speak only as to the date of this Annual Report on Form 10-K and Pepco undertakes no 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 Pepco to predict all of such factors, nor can Pepco assess the impact of any such factor on Pepco’s business 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 review of factors should not be construed as exhaustive.

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DPL

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

Delmarva Power & Light Company

Delmarva Power & Light Company (DPL) meets the conditions set forth in General Instruction I(1)(a) and (b) to the Form 10-K, and accordingly information otherwise required under this Item has been omitted in accordance with General Instruction I(2)(a) to the 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 Standard Offer Service (SOS) in both Delaware and Maryland. DPL’s electricity distribution service territory covers approximately 5,000 square miles and has a population of approximately 1.3 million. As of December 31, 2010, 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.

As a result of the implementation of a bill stabilization adjustment mechanism (BSA) for retail customers of DPL in Maryland in June 2007, DPL recognizes Maryland distribution revenue based on an approved distribution charge per customer. From a revenue recognition standpoint, this has the effect of decoupling distribution revenue recognized in a reporting period with the amount of power delivered during the period. As a consequence, the only factors that will cause distribution revenue in Maryland to fluctuate from period to period are changes in the number of customers and changes in the approved distribution charge per customer. For customers to whom the BSA applies, 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.

As a result of 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 Pepco Holdings, Inc. (PHI or Pepco Holdings). 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 DPL and certain activities of DPL are subject to the regulatory oversight of the Federal Energy Regulatory Commission (FERC) under PUHCA 2005.

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Results Of Operations

The following results of operations discussion compares the year ended December 31, 2010 to the year ended December 31, 2009. All amounts in the tables (except sales and customers) are in millions of dollars.

Electric Operating Revenue

	2010		2009		Change
Regulated T&D Electric Revenue	$	375	$	343	$	32
Default Electricity Supply Revenue		768		769		(1	)
Other Electric Revenue		20		23		(3	)
Total Electric Operating Revenue	$	1,163	$	1,135	$	28

The table above shows the amount of Electric Operating Revenue earned that is subject to price regulation (Regulated Transmission & Distribution (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 Interconnection, LLC (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 Standard Offer Service. 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

Regulated T&D Electric Revenue	2010	2009		Change
Residential	$184	$	164	$	20
Commercial and industrial	110		102		8
Other	81		77		4
Total Regulated T&D Electric Revenue	$375	$	343	$	32

Other Regulated T&D Electric Revenue consists primarily of transmission service revenue.

Regulated T&D Electric Sales(Gigawatt hours (GWh))	2010		2009		Change
Residential		5,357		4,922		435
Commercial and industrial		7,445		7,521		(76	)
Other		51		51		—
Total Regulated T&D Electric Sales		12,853		12,494		359

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Regulated T&D Electric Customers (in thousands)	2010		2009		Change
Residential		440		438		2
Commercial and industrial		59		59		—
Other		1		1		—
Total Regulated T&D Electric Customers		500		498		2

Regulated T&D Electric Revenue increased by $32 million primarily due to:

• An increase of $15 million due to distribution rate increases in Maryland effective December 2009 and in Delaware effective April 2010.

• An increase of $7 million due to higher revenue as a result of warmer weather during the 2010 spring and summer months as compared to 2009.

• An increase of $5 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).

Default Electricity Supply

Default Electricity Supply Revenue	2010		2009		Change
Residential	$	577	$	551	$	26
Commercial and industrial		181		209		(28	)
Other		10		9		1
Total Default Electricity Supply Revenue	$	768	$	769	$	(1	)
Default Electricity Supply Sales (GWh)	2010		2009		Change
Residential		5,199		4,821		378
Commercial and industrial		1,954		2,050		(96	)
Other		37		42		(5	)
Total Default Electricity Supply Sales		7,190		6,913		277
Default Electricity Supply Customers (in thousands)	2010		2009		Change
Residential		423		431		(8	)
Commercial and industrial		45		47		(2	)
Other		1		1		—
Total Default Electricity Supply Customers		469		479		(10	)

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

• A decrease of $31 million due to lower sales, primarily as a result of Delaware commercial and Maryland residential customer migration to competitive suppliers.

• A decrease of $31 million as a result of lower Default Electricity Supply rates.

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The aggregate amount of these decreases was partially offset by:

• An increase of $37 million due to higher sales primarily as a result of warmer weather during the 2010 spring and summer months as compared to 2009.

• An increase of $22 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:

	2010			2009
Sales to Delaware customers		53	%		51	%
Sales to Maryland customers		63	%		63	%

Natural Gas Operating Revenue

	2010		2009		Change
Regulated Gas Revenue	$	191	$	228	$	(37	)
Other Gas Revenue		46		40		6
Total Natural Gas Operating Revenue	$	237	$	268	$	(31	)

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

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

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

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

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

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 $11 million to $740 million in 2010 from $751 million in 2009 primarily due to:

• A decrease of $20 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 $20 million due to lower average electricity costs under Default Electricity Supply contracts.

• A decrease of $4 million primarily due to commercial and residential customer migration to competitive suppliers.

The aggregate amount of these decreases was partially offset by:

• An increase of $33 million due to higher sales primarily as a result of warmer weather during the 2010 spring and summer months as compared to 2009.

Gas Purchased

Gas Purchased consists of the cost of natural gas purchased by DPL to fulfill its obligation to regulated natural 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 natural gas purchased for off-system sales. Total Gas Purchased decreased by $29 million to $164 million in 2010 from $193 million in 2009 primarily due to:

• 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 $12 million from the settlement of financial hedges entered into as part of DPL’s hedge program for regulated natural gas.

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Other Operation and Maintenance

Other Operation and Maintenance increased by $17 million to $255 million in 2010 from $238 million in 2009. Excluding an increase of $3 million primarily related to administrative expenses that are deferred and recoverable in Default Electricity Supply Revenue, Other Operation and Maintenance expense increased by $14 million. The $14 million increase was primarily due to:

• An increase of $6 million primarily due to higher corrective and preventative maintenance, and tree trimming costs.

• An increase of $4 million in emergency restoration costs primarily due to the February 2010 severe winter storms.

• A $4 million accrual in 2010 for estimated future environmental remediation costs related to a 1999 oil release at the Indian River generating facility then owned by DPL, as further discussed under “Indian River Oil Release” in Note (15), “Commitments and Contingencies,” to the financial statements of DPL.

• An increase of $2 million primarily due to system support and customer support services costs.

The aggregate amount of these increases was partially offset by:

• A decrease of $5 million in employee-related costs, primarily due to lower pension and other postretirement benefit expenses.

Restructuring Charge

With the ongoing wind down of the retail energy supply business of Pepco Energy Services and the disposition of Conectiv Energy, PHI is repositioning itself as a regulated transmission and distribution company. In connection with this repositioning, 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 that are allocated to its operating segments. This review has resulted in the adoption of a restructuring plan. PHI began implementing the plan during the third quarter, identifying 164 employee positions that were eliminated during the fourth quarter of 2010. The plan also focuses on identifying additional cost reduction opportunities through process improvements and operational efficiencies. PHI currently estimates that the implementation of the plan will result in an annual reduction of approximately $28 million in corporate overhead costs.

In connection with the plan, DPL recorded a pre-tax restructuring charge of $8 million for the year ended December 31, 2010, related to severance, pension, and health and welfare benefits to be provided to terminated employees.

Depreciation and Amortization

Depreciation and Amortization expense increased by $7 million to $83 million in 2010 from $76 million in 2009 primarily due to:

• An increase of $3 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 $3 million due to utility plant additions.

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Other Income (Expenses)

Other Expenses (which are net of Other Income) decreased by $5 million to a net expense of $37 million in 2010 from a net expense of $42 million in 2009. The decrease was primarily due to an increase of $3 million in income related to Allowance for Funds Used During Construction that is applied to capital projects.

Income Tax Expense

DPL’s effective tax rates for the years ended December 31, 2010 and 2009 were 40.8% and 23.5%, respectively. The increase in the effective tax rate resulted primarily from the impact of a refund of state taxes DPL received in 2009. DPL received a refund of $6 million (after-tax) of state income taxes and established a state tax benefit carryforward of $7 million (after-tax), each related to a change in tax reporting for certain asset dispositions occurring in prior years.

In addition, the effective tax rate increased in 2010 as a result of the November 2010 settlement PHI reached with the Internal Revenue Service (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 has recalculated the estimated interest due for the tax years 1996 to 2002. The revised estimate has resulted in an additional $3 million (after-tax) of estimated interest due to the IRS. This additional interest expense has been recorded in 2010 and is subject to adjustment when the IRS finalizes its calculation of the amount due. 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 Item 1A, “Risk Factors,” of this Form 10-K, 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 Variable Rate Demand Bonds. To fund the construction of pollution control facilities, DPL also has from time to time issued tax-exempt bonds, including tax-exempt Variable Rate Demand Bonds, 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 Variable Rate Demand Bonds, and tax-exempt bonds issued for the benefit of DPL, as of December 31, 2010, is set forth in Note (11), “Debt,” to the financial statements of DPL set forth in Part II, Item 8 of this Form 10-K.

Bank Financing

As further discussed in Note (11), “Debt,” to the financial statements of DPL set forth in Part II, Item 8 of this Form 10-K, DPL participates in a $1.5 billon credit facility, along with PHI, Potomac Electric Power Company (Pepco) and Atlantic City Electric Company (ACE). The facility, all or any portion of which may be used to obtain loans or to issue letters of credit, expires in 2012. DPL’s credit limit under the facility is the lesser of $500 million and the maximum amount of debt DPL is permitted to have outstanding by its regulatory authorities, except that the aggregate amount of credit used by DPL, Pepco and ACE at any given time may not collectively exceed $625 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 PHI $1.5 billion credit facility.

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 Delaware Public Service Commission and the Maryland Public Service Commission. Through its periodic filings with the respective utility commissions, DPL generally seeks to maintain standing authority sufficient to cover its projected financing needs over a multi-year period. Under the Federal Power Act, 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, DPL is required to obtain FERC authorization for the issuance of short-term debt.

Capital Expenditures

DPL’s capital expenditures for the year ended December 31, 2010, totaled $250 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 the Power Delivery business 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 2011 through 2015. DPL expects to fund these expenditures through internally generated cash, external financing and capital contributions from PHI.

	For the Year
	2011		2012		2013		2014		2015		Total
	(millions of dollars)
DPL
Distribution	$	113	$	105	$	116	$	126	$	113	$	573
Distribution - Blueprint for the Future		21		40		—		—		—		61
Transmission		76		107		88		82		80		433
Transmission - MAPP		51		146		138		74		60		469
Gas Delivery		20		20		20		20		20		100
Other		27		21		18		16		19		101
Total DPL	$	308	$	439	$	380	$	318	$	292	$	1,737

DPL has not received any awards from the U. S. Department of Energy under the American Recovery and Reinvestment Act of 2009 in support of its Blueprint for the Future and other initiatives.

Transmission and Distribution

The projected capital expenditures listed in the table for distribution (other than Blueprint for the Future), transmission (other than the Mid-Atlantic Power Pathway (MAPP) project) and natural gas are primarily for facility replacements and upgrades to accommodate customer growth and reliability.

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 Item 1, “Business - Description of Business - Blueprint for the Future” of this Form 10-K. 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 230-mile, 500-kilovolt interstate transmission line as part of PJM’s regional transmission expansion plan. For a description of the MAPP project, see Item 1, “Business - Description of Business - MAPP Project” of this Form 10-K. 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 Department of Energy (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.

Pension and Postretirement Benefit Plans

DPL participates in pension and postretirement benefit plans sponsored by PHI for its employees. While the plans have not experienced any significant impact in terms of liquidity or counterparty exposure due to the disruption of the capital and credit markets, the stock market declines in 2008 caused a decrease in the market value of benefit plan assets at the end of 2008. DPL contributed zero and $10 million to the pension plan during 2010 and 2009, respectively.

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DPL

Forward-Looking Statements

Some of the statements contained in this Annual Report on Form 10-K are forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and are subject to the safe harbor created by the Private Securities Litigation Reform Act of 1995. These statements include declarations regarding DPL’s intents, beliefs and current expectations. In some cases, you can identify forward-looking statements by terminology such as “may,” “will,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “predicts,” “potential” or “continue” or the negative of such terms or other comparable terminology. Any forward-looking statements are not guarantees of future performance, and actual results could differ materially from those indicated by the forward-looking statements. Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may cause DPL’s 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.

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 DPL’s 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;

• Weather conditions affecting usage and emergency restoration costs;

• Population growth rates and changes in demographic patterns;

• Changes in customer demand for electricity and natural gas 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 electricity and natural gas usage;

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

• Changes in tax rates or policies;

• Changes in rates of inflation;

• Changes in accounting standards or practices;

• Unanticipated changes in operating expenses and capital expenditures;

• Rules and regulations imposed by federal and/or state regulatory commissions, PJM, the North American Electric Reliability Corporation and other applicable electric reliability organizations;

• Legal and administrative proceedings (whether civil or criminal) and settlements that affect DPL’s business and profitability;

• 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.

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Any forward-looking statements speak only as to the date of this Annual Report on Form 10-K and DPL undertakes no 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 DPL to predict all of such factors, nor can DPL assess the impact of any such factor on DPL’s business 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 review of factors should not be construed as exhaustive.

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ACE

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

Atlantic City Electric Company

Atlantic City Electric Company (ACE) meets the conditions set forth in General Instruction I(1)(a) and (b) to the Form 10-K, and accordingly information otherwise required under this Item has been omitted in accordance with General Instruction I(2)(a) to the 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 Basic Generation Service (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 Pepco Holdings, Inc. (PHI or Pepco Holdings). 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 ACE and certain activities of ACE are subject to the regulatory oversight of the Federal Energy Regulatory Commission (FERC) under PUHCA 2005.

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ACE

RESULTS OF OPERATIONS

The following results of operations discussion compares the year ended December 31, 2010 to the year ended December 31, 2009. All amounts in the tables (except sales and customers) are in millions of dollars.

Operating Revenue

	2010		2009		Change
Regulated T&D Electric Revenue	$	415	$	363	$	52
Default Electricity Supply Revenue		998		970		28
Other Electric Revenue		17		18		(1	)
Total Operating Revenue	$	1,430	$	1,351	$	79

The table above shows the amount of Operating Revenue earned that is subject to price regulation (Regulated Transmission & Distribution (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 Interconnection, LLC (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 Basic Generation Service (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 Atlantic City Electric Transition Funding LLC (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 ACE receives as a transmission owner from PJM for approved regional transmission expansion plan costs (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

Regulated T&D Electric Revenue	2010		2009		Change
Residential	$	185	$	161	$	24
Commercial and industrial		142		131		11
Other		88		71		17
Total Regulated T&D Electric Revenue	$	415	$	363	$	52

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Other Regulated T&D Electric Revenue consists primarily of transmission service revenue.

Regulated T&D Electric Sales (Gigawatt hours (GWh))	2010		2009		Change
Residential		4,691		4,280		411
Commercial and industrial		5,445		5,330		115
Other		49		49		—
Total Regulated T&D Electric Sales		10,185		9,659		526
Regulated T&D Electric Customers (in thousands)	2010		2009		Change
Residential		482		481		1
Commercial and industrial		65		65		—
Other		1		1		—
Total Regulated T&D Electric Customers		548		547		1

Regulated T&D Electric Revenue increased by $52 million primarily due to:

• An increase of $17 million in transmission revenue primarily attributable to higher rates effective June 1, 2010 related to an increase in transmission plant investment.

• An increase of $17 million due to a distribution rate increase that became effective in June 2010.

• An increase of $13 million due to higher revenue primarily as a result of warmer weather during the 2010 spring and summer months as compared to 2009.

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

Default Electricity Supply

Default Electricity Supply Revenue	2010		2009		Change
Residential	$	580	$	514	$	66
Commercial and industrial		243		316		(73	)
Other		175		140		35
Total Default Electricity Supply Revenue	$	998	$	970	$	28

Other Default Electricity Supply Revenue consists primarily of: (i) revenue from the resale in the PJM Regional Transmission Organization market of energy and capacity purchased under contracts with unaffiliated, non-utility generators (NUGs), and (ii) revenue from Transmission Enhancement Credits.

Default Electricity Supply Sales (GWh)	2010		2009		Change
Residential		4,610		4,280		330
Commercial and industrial		1,967		2,681		(714	)
Other		46		49		(3	)
Total Default Electricity Supply Sales		6,623		7,010		(387	)

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Default Electricity Supply Customers (in thousands)	2010		2009		Change
Residential		458		481		(23	)
Commercial and industrial		56		62		(6	)
Other		—		1		(1	)
Total Default Electricity Supply Customers		514		544		(30	)

Default Electricity Supply Revenue increased by $28 million primarily due to:

• An increase of $40 million due to higher sales primarily as a result of warmer weather during the 2010 spring and summer months as compared to 2009.

• 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 $20 million due to higher non-weather related average customer usage.

• An increase of $19 million as a result of higher Default Electricity Supply rates.

• An increase of $6 million due to an increase in revenue from Transmission Enhancement Credits.

The aggregate amount of these increases was partially offset by:

• A decrease of $87 million due to lower sales, primarily as a result of commercial and industrial customer migration to competitive suppliers.

Total Default Electricity Supply Revenue for the 2010 period includes an increase of $8 million in unbilled revenue attributable to ACE’s BGS. Under the BGS terms approved by the New Jersey Board of Public Utilities (NJBPU), ACE is entitled to recover from its customers all of its costs of providing BGS. If the costs of providing BGS exceed the BGS revenue, then the excess costs are deferred in Deferred Electric Service Costs. ACE’s BGS unbilled revenue (which is the result of the recognition of revenue when the electricity is delivered, as opposed to when it is billed) is not included in the deferral calculation, and therefore has an impact on the results of operations in the period during which it is accrued. While the change in the amount of unbilled revenue from year to year typically is not significant, for the year ended December 31, 2010, BGS unbilled revenue increased by $8 million as compared to the year ended December 31, 2009, which resulted in a $5 million increase in ACE’s net income. The increase was primarily due to higher Default Electricity Supply rates and colder weather during the unbilled revenue period at the end of 2010 as compared to the corresponding period in 2009.

For the years ended December 31, 2010 and 2009, the percentages of ACE’s total distribution sales that are derived from customers receiving Default Electricity Supply are 65% and 73%, respectively.

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ACE

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 $46 million to $1,030 million in 2010 from $1,076 million in 2009 primarily due to:

• A decrease of $109 million due to lower sales, primarily due to commercial and industrial customer migration to competitive suppliers.

The decrease was partially offset by:

• An increase of $49 million due to higher sales primarily as a result of warmer weather during the 2010 spring and summer months as compared to 2009.

• An increase of $14 million due to higher average electricity costs under Default Electricity Supply contracts.

Other Operation and Maintenance

Other Operation and Maintenance increased by $14 million to $204 million in 2010 from $190 million in 2009. Excluding an increase of $6 million primarily related to bad debt expenses and New Jersey Societal Benefit Program costs that are deferred and recoverable, Other Operation and Maintenance expense increased by $8 million. The $8 million increase was primarily due to:

• An increase of $7 million in emergency restoration costs primarily due to the severe winter storms in February 2010.

• An increase of $5 million due to higher tree trimming costs.

• An increase of $2 million due to an adjustment for non-recoverable litigation costs related to ACE’s former interests in certain nuclear generating facilities in accordance with a May 2010 settlement approved by the NJBPU.

The aggregate amount of these increases was partially offset by:

• A decrease of $6 million in employee-related costs, primarily due to lower pension and other postretirement benefit expenses.

Restructuring Charge

With the ongoing wind down of the retail energy supply business of Pepco Energy Services and the disposition of Conectiv Energy, PHI is repositioning itself as a regulated transmission and distribution company. In connection with this repositioning, 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 that are allocated to its operating segments. This review has resulted in the adoption of a restructuring plan. PHI began implementing the plan during the third quarter, identifying 164 employee positions that were eliminated during the fourth quarter of 2010. The plan also focuses on identifying additional cost reduction opportunities through process improvements and operational efficiencies. PHI currently estimates that the implementation of the plan will result in an annual reduction of approximately $28 million in corporate overhead costs.

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In connection with the plan, ACE recorded a pre-tax restructuring charge of $6 million for the year ended December 31, 2010, related to severance, pension, and health and welfare benefits to be provided to terminated employees.

Depreciation and Amortization

Depreciation and Amortization expense increased by $10 million to $112 million in 2010 from $102 million in 2009 primarily due to higher amortization of stranded costs as the result of higher revenues due to increases in sales (partially offset in Default Electricity Supply Revenue).

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 $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.

Income Tax Expense

ACE’s consolidated effective tax rates for the years ended December 31, 2010 and 2009 were 44.8% and 29.3%, respectively. The increase in the effective tax rate resulted primarily from two reversals of previously accrued interest on uncertain and effectively settled tax positions. The first reversal was the result of the November 2010 settlement PHI reached with the Internal Revenue Service (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, ACE has recalculated the estimated interest due for the tax years 1996 to 2002. The revised estimate has resulted in an additional $1 million (after-tax) of estimated interest due to the IRS. This additional interest expense has been recorded in 2010 and is subject to adjustment when the IRS finalizes its calculation of the amount due. The second reversal of $6 million of accrued interest income was recorded in 2010 to eliminate interest on uncertain and effectively settled state income tax positions that had been erroneously accrued in prior periods.

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 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 Item 1A, “Risk Factors,” of this Form 10-K, for additional discussion of important factors that may have an effect on ACE’s sources of capital.

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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 Variable Rate Demand Bonds. To fund the construction of pollution control facilities, ACE also has from time to time issued tax-exempt bonds, including tax-exempt Variable Rate Demand Bonds, through a municipality, the proceeds of which are loaned to ACE by the municipality.

Information concerning the principal amount and terms of ACE’s outstanding First Mortgage Bonds, senior notes and Variable Rate Demand Bonds, and tax-exempt bonds issued for the benefit of ACE, as of December 31, 2010, is set forth in Note (10), “Debt,” to the consolidated financial statements of ACE set forth in Part II, Item 8 of this Form 10-K.

Bank Financing

As further discussed in Note (10), “Debt,” to the consolidated financial statements of ACE set forth in Part II, Item 8 of this Form 10-K, ACE participates in a $1.5 billion credit facility, along with PHI, Potomac Electric Power Company (Pepco) and Delmarva Power & Light Company (DPL). The facility, all or any portion of which may be used to obtain loans or to issue letters of credit expires in 2012. ACE’s credit limit under the facility is the lesser of $500 million and the maximum amount of debt ACE is permitted to have outstanding by its regulatory authorities, except that the aggregate amount of credit used by ACE, Pepco and DPL at any given time may not collectively exceed $625 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 PHI $1.5 billion credit facility.

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.

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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, 2010, is set forth in Note (12), “Preferred Stock,” to the consolidated financial statements of ACE set forth in Part II, Item 8 of this Form 10-K. As of December 31, 2010, ACE had issued $6 million of Cumulative Preferred Stock that will be redeemed on February 25, 2011. No shares of No Par Preferred Stock or Preference Stock were outstanding at December 31, 2010.

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 seeks to maintain 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%.

Capital Expenditures

ACE’s capital expenditures for the year ended December 31, 2010, totaled $156 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 the Power Delivery business 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 2011 through 2015. ACE expects to fund these expenditures through internally generated cash, external financing and capital contributions from PHI.

	For the Year
	2011			2012			2013			2014		2015		Total
	(millions of dollars)
ACE
Distribution	$	107		$	101		$	108		$	112	$	114	$	542
Distribution - Blueprint for the Future		4			—			8			92		—		104
Transmission		33			32			35			25		27		152
Other		20			13			16			13		15		77
Sub-Total		164			146			167			242		156		875
DOE Capital Reimbursement Awards (a)		(5	)		(4	)		(1	)		—		—		(10	)
Total ACE	$	159		$	142		$	166		$	242	$	156	$	865

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

118

ACE

Stimulus Funds Related to Blueprint for the Future

In 2009, the U.S. Department of Energy (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 2010, ACE received award payments of $2 million.

The Internal Revenue Service 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.

Blueprint for the Future

ACE 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 Item 1, “Business - Description of Business - Blueprint for the Future” of this Form 10-K. 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 are designed to enhance reliability of ACE’s distribution system and support economic activity and job growth in New Jersey in the near term. ACE will achieve cost recovery through an Infrastructure Investment Surcharge, which became effective on June 1, 2009. This approved plan added incremental capital spending of approximately $8 million for 2009 and $19 million for 2010, and is expected to add an additional $1 million of capital spending for 2011, which is included in Distribution in the table above.

Pension and Postretirement Benefit Plans

ACE participates in pension and postretirement benefit plans sponsored by PHI for its employees. While the plans have not experienced any significant impact in terms of liquidity or counterparty exposure due to the disruption of the capital and credit markets, the stock market declines in 2008 caused a decrease in the market value of benefit plan assets at the end of 2008. ACE contributed zero and $60 million to the pension plan during 2010 and 2009, respectively.

119

ACE

Forward-Looking Statements

Some of the statements contained in this Annual Report on Form 10-K are forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and are subject to the safe harbor created by the Private Securities Litigation Reform Act of 1995. These statements include declarations regarding ACE’s intents, beliefs and current expectations. In some cases, you can identify forward-looking statements by terminology such as “may,” “will,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “predicts,” “potential” or “continue” or the negative of such terms or other comparable terminology. Any forward-looking statements are not guarantees of future performance, and actual results could differ materially from those indicated by the forward-looking statements. Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may cause ACE’s 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.

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 ACE’s 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;

• Weather conditions affecting usage and emergency restoration costs;

• Population growth rates and changes in demographic patterns;

• Changes in customer demand for electricity 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 electricity usage;

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

• Changes in tax rates or policies;

• Changes in rates of inflation;

• Changes in accounting standards or practices;

• Unanticipated changes in operating expenses and capital expenditures;

• Rules and regulations imposed by federal and/or state regulatory commissions, PJM, the North American Electric Reliability Corporation and other applicable electric reliability organizations;

• Legal and administrative proceedings (whether civil or criminal) and settlements that affect ACE’s business and profitability;

• 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.

120

ACE

Any forward-looking statements speak only as to the date of this Annual Report on Form 10-K and ACE undertakes no 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 ACE to predict all of such factors, nor can ACE assess the impact of any such factor on ACE’s business 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 review of factors should not be construed as exhaustive.

121

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, 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 Corporate Risk Management Committee 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 disclosed herein, refer to Note (2), “Significant Accounting Policies - Accounting For Derivatives,” Note (15), “Derivative Instruments and Hedging Activities” and Note (20), “Discontinued Operations” to the consolidated financial statements of PHI set forth in Part II, Item 8 of this Form 10-K.

Pepco Holdings, Inc.

Commodity Price Risk

The Pepco Energy Services segment engages in commodity risk management activities to reduce their financial exposure to changes in the value of their assets and obligations due to commodity price fluctuations. Certain of these risk management activities are conducted using instruments classified as derivatives based on Financial Accounting Standards Board (FASB) guidance on derivatives and hedging (Accounting Standards Codification (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 wholesale and retail sales commitments and the cost of supply used to service those commitments in order to ensure stable and known cash flows and fix favorable prices and margins. The discontinued operations of Conectiv Energy have engaged in similar commodity risk management activities throughout 2010. Prior to the sale of the wholesale power generation business on July 1, 2010, the risk management objective of the Conectiv Energy segment also included the management of the spread between the cost of fuel used to operate its electric generating facilities and the revenue received from the sale of the power produced by those facilities by selling forward a portion of their projected generating facility output and buying forward a portion of their projected fuel supply requirements. Conectiv Energy sold its remaining derivatives in January 2011, and no longer engages in such activities.

PHI’s risk management policies place oversight at the senior management level through the Corporate Risk Management Committee, 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 and Conectiv Energy. 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. In January 2009, PHI changed its VaR estimation model from a delta-normal variance / covariance model to a delta-gamma model. The other parameters, a 95 percent, one-tailed confidence level and a one-day holding period, remained the same. Since VaR is an estimate, it is not necessarily indicative of actual results that may occur.

122

The table below provides the VaR associated with energy contracts of both the Pepco Energy Services segment and the former Conectiv Energy segment for the year ended December 31, 2010 in millions of dollars:

	VaR for Conectiv Energy Commodity Activities (a)		VaR for Pepco Energy Services Commodity Activities (a)
95% confidence level, one-day holding period, one-tailed
Period end	$	—	$	3
Average for the period	$	2	$	1
High	$	5	$	3
Low	$	—	$	1

(a) These columns represent all energy derivative contracts, normal purchase and normal sales contracts, modeled generation output and fuel requirements, and modeled customer load obligations for PHI’s energy commodity activities.

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 futures and swap contracts as cash flow hedges of forecasted transactions. Its options contracts and certain commodity contracts that do not qualify as cash flow hedges 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 accounted for using accrual accounting.

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, 2010, credit exposure to wholesale energy counterparties was weighted 99% with investment grade counterparties, 1% with counterparties without external credit-quality ratings, and there were no investments with non-investment grade counterparties.

123

The following table provides information on the credit exposure on competitive wholesale energy contracts, net of collateral, to wholesale counterparties as of December 31, 2010, 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)	$	74	$	—	$	74		5	$	53
Non-Investment Grade		—		—		—		—		—
No External Ratings		1		—		1		—		—
Credit reserves						1

(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 (MTM) energy contract net assets for open/unrealized transactions, the net receivable/payable for realized transactions and net open positions for contracts not subject to MTM. 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, 2010.

Potomac Electric Power Company

Interest Rate Risk

Pepco does not have any debt with variable or floating rates.

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 Gas Cost Rate clause included in DPL’s natural gas tariff rates approved by the Delaware Public Service Commission and are deferred until recovered. 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. At December 31, 2009, after the effects of cash collateral and netting, DPL had a net derivative liability of $28 million, offset by a $42 million regulatory asset.

124

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, 2010.

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, 2010.

125

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	127	218	252	289
Report of Independent Registered Public Accounting Firm	128	219	253	290
Consolidated Statements of Income	129	220	254	291
Consolidated Statements of Comprehensive Income	130	N/A	N/A	N/A
Consolidated Balance Sheets	131	221	255	292
Consolidated Statements of Cash Flows	133	223	257	294
Consolidated Statements of Equity	134	224	258	295
Notes to Consolidated Financial Statements	135	225	259	296

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

126

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) under the Securities Exchange Act of 1934, as amended. 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 assessed its internal control over financial reporting as of December 31, 2010 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, 2010.

PricewaterhouseCoopers LLP, the independent registered public accounting firm that audited the 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.

127

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, 2010 and December 31, 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010 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, 2010, 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 24, 2011

128

PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

For the Year Ended December 31,	2010			2009			2008
	(millions of dollars, except per share data)
Operating Revenue
Power Delivery	$	5,114		$	4,980		$	5,488
Pepco Energy Services		1,883			2,383			2,648
Other		42			39			(77	)
Total Operating Revenue		7,039			7,402			8,059
Operating Expenses
Fuel and purchased energy		4,644			5,330			5,927
Other services cost of sales		127			85			127
Other operation and maintenance		884			819			775
Restructuring charge		30			—			—
Depreciation and amortization		393			349			338
Other taxes		434			368			355
Deferred electric service costs		(108	)		(161	)		(9	)
Impairment losses		—			4			—
Effect of Pepco divestiture-related claims		11			(40	)		—
Gain on sale of assets		—			—			(3	)
Total Operating Expenses		6,415			6,754			7,510
Operating Income		624			648			549
Other Income (Expenses)
Interest and dividend income		—			2			17
Interest expense		(306	)		(340	)		(305	)
(Loss) gain from equity investments		(1	)		2			(4	)
Loss on extinguishment of debt		(189	)		—			—
Other income		22			16			19
Other expenses		—			(1	)		(3	)
Total Other Expenses		(474	)		(321	)		(276	)
Income from Continuing Operations Before Income Tax Expense		150			327			273
Income Tax Expense Related to Continuing Operations		11			104			90
Net Income from Continuing Operations		139			223			183
(Loss) Income from Discontinued Operations, net of Income Taxes		(107	)		12			117
Net Income	$	32		$	235		$	300
Basic and Diluted Share Information
Weighted average shares outstanding (millions)		224			221			204
Earnings per share of common stock from Continuing Operations	$	0.62		$	1.01		$	0.90
(Loss) earnings per share of common stock from Discontinued Operations		(0.48	)		0.05			0.57
Basic and diluted earnings per share	$	0.14		$	1.06		$	1.47

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

129

PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

For the Year Ended December 31,	2010			2009			2008
	(millions of dollars)
Net income	$	32		$	235		$	300
Other comprehensive income (loss) from continuing operations
Gains (loss) from continuing operations on commodity derivatives designated as cash flow hedges:
Losses arising during period		(100	)		(129	)		(210	)
Amount of losses (gains) reclassified into income		135			166			(8	)
Net gains (losses) on commodity derivatives		35			37			(218	)
Losses on treasury rate locks reclassified into income		18			5			5
Amortization of losses for prior service cost		—			(13	)		(3	)
Other comprehensive income (loss) from continuing operations, before income taxes		53			29			(216	)
Income tax expense (benefit) from continuing operations		21			12			(87	)
Other comprehensive income (loss) from continuing operations, net of income taxes		32			17			(129	)
Other comprehensive income (loss) from discontinued operations, net of income taxes		103			4			(87	)
Comprehensive income	$	167		$	256		$	84

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

130

PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS	December 31, 2010			December 31, 2009
	(millions of dollars)
CURRENT ASSETS
Cash and cash equivalents	$	20		$	44
Restricted cash equivalents		11			11
Accounts receivable, less allowance for uncollectible accounts of $51 million and $44 million, respectively		1,027			1,019
Inventories		126			124
Derivative assets		45			22
Prepayments of income taxes		276			167
Deferred income tax assets, net		90			126
Prepaid expenses and other		51			67
Conectiv Energy assets held for sale		111			346
Total Current Assets		1,757			1,926
INVESTMENTS AND OTHER ASSETS
Goodwill		1,407			1,407
Regulatory assets		1,915			1,801
Investment in finance leases held in trust		1,423			1,386
Income taxes receivable		114			141
Restricted cash equivalents		5			4
Assets and accrued interest related to uncertain tax positions		11			12
Derivative assets		—			16
Other		169			194
Conectiv Energy assets held for sale		6			29
Total Investments and Other Assets		5,050			4,990
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		12,120			11,431
Accumulated depreciation		(4,447	)		(4,190	)
Net Property, Plant and Equipment		7,673			7,241
Conectiv Energy assets held for sale		—			1,622
Total Property, Plant and Equipment		7,673			8,863
TOTAL ASSETS	$	14,480		$	15,779

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

131

PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

LIABILITIES AND EQUITY	December 31, 2010			December 31, 2009
	(millions of dollars, except shares)
CURRENT LIABILITIES
Short-term debt	$	534		$	530
Current portion of long-term debt and project funding		75			536
Accounts payable and accrued liabilities		587			574
Capital lease obligations due within one year		8			7
Taxes accrued		96			47
Interest accrued		45			68
Liabilities and accrued interest related to uncertain tax positions		3			1
Derivative liabilities		66			67
Other		321			281
Liabilities associated with Conectiv Energy assets held for sale		62			191
Total Current Liabilities		1,797			2,302
DEFERRED CREDITS
Regulatory liabilities		528			613
Deferred income taxes, net		2,714			2,600
Investment tax credits		26			35
Pension benefit obligation		332			290
Other postretirement benefit obligations		429			409
Income taxes payable		2			5
Liabilities and accrued interest related to uncertain tax positions		148			96
Derivative liabilities		21			54
Other		175			147
Liabilities associated with Conectiv Energy assets held for sale		10			19
Total Deferred Credits		4,385			4,268
LONG-TERM LIABILITIES
Long-term debt		3,629			4,470
Transition bonds issued by ACE Funding		332			368
Long-term project funding		15			17
Capital lease obligations		86			92
Total Long-Term Liabilities		4,062			4,947
COMMITMENTS AND CONTINGENCIES (NOTE 17)
EQUITY
Common stock, $.01 par value - authorized 400,000,000 shares, 225,082,252 and 222,269,895 shares outstanding, respectively		2			2
Premium on stock and other capital contributions		3,275			3,227
Accumulated other comprehensive loss		(106	)		(241	)
Retained earnings		1,059			1,268
Total Shareholders’ Equity		4,230			4,256
Non-controlling interest		6			6
Total Equity		4,236			4,262
TOTAL LIABILITIES AND EQUITY	$	14,480		$	15,779

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

132

PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Year Ended December 31,	2010			2009			2008
	(millions of dollars)
OPERATING ACTIVITIES
Net income	$	32		$	235		$	300
Loss (income) from discontinued operations		107			(12	)		(117	)
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		393			349			338
Non-cash rents from cross-border energy lease investments		(55	)		(54	)		(65	)
Non-cash charge to reduce equity value of PHI’s cross-border energy lease investments		2			3			124
Effects of Pepco divestiture-related claims		11			(40	)		—
Changes in restricted cash equivalents related to Mirant settlement		—			102			315
Deferred income taxes		345			249			313
Losses on treasury rate locks reclassified into income		18			5			5
Other		(20	)		(3	)		(12	)
Changes in:
Accounts receivable		(12	)		136			(71	)
Inventories		(2	)		20			(35	)
Prepaid expenses		7			(17	)		1
Regulatory assets and liabilities, net		(154	)		(221	)		(325	)
Accounts payable and accrued liabilities		73			(153	)		29
Pension contributions		(100	)		(300	)		—
Pension benefit obligation, excluding contributions		68			95			19
Cash collateral related to derivative activities		13			24			(138	)
Taxes accrued		(213	)		76			(241	)
Other assets and liabilities		52			9			17
Net Conectiv Energy assets held for sale		248			103			(44	)
Net Cash From Operating Activities		813			606			413
INVESTING ACTIVITIES
Investment in property, plant and equipment		(802	)		(664	)		(643	)
DOE capital reimbursement awards received		13			—			—
Proceeds from sale of Conectiv Energy wholesale power generation business		1,640			—			—
Proceeds from sale of assets		3			4			56
Net other investing activities		2			—			11
Investment in property, plant and equipment associated with Conectiv Energy assets held for sale		(138	)		(200	)		(138	)
Net Cash From (Used By) Investing Activities		718			(860	)		(714	)
FINANCING ACTIVITIES
Dividends paid on common stock		(241	)		(238	)		(222	)
Common stock issued for the Dividend Reinvestment Plan and employee-related compensation		47			49			51
Issuance of common stock		—			—			265
Issuances of long-term debt		383			110			1,150
Reacquisition of long-term debt		(1,726	)		(83	)		(590	)
Issuances (repayments) of short-term debt, net		4			65			26
Cost of issuances		(7	)		(4	)		(30	)
Net other financing activities		(6	)		10			(21	)
Net financing activities associated with Conectiv Energy assets held for sale		(10	)		7			1
Net Cash (Used By) From Financing Activities		(1,556	)		(84	)		630
Net (Decrease) Increase In Cash and Cash Equivalents		(25	)		(338	)		329
Cash and Cash Equivalents of Discontinued Operations		(1	)		(2	)		(9	)
Cash and Cash Equivalents at Beginning of Year		46			384			55
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	20		$	44		$	375
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for interest (net of capitalized interest of $9 million, $11 million and $11 million, respectively)	$	310		$	353		$	316
Cash (received) paid for income taxes		(13	)		(76	)		99

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

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PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY

	Common Stock				Premium			Accumulated Other Comprehensive			Retained
(millions of dollars, except shares)	Shares		Par Value		on Stock			(Loss) Income			Earnings			Total
BALANCE, DECEMBER 31, 2007		200,512,890	$	2	$	2,869		$	(46	)	$	1,193		$	4,018
Net Income		—		—		—			—			300			300
Other comprehensive loss		—		—		—			(216	)		—			(216	)
Dividends on common stock ($1.08 per share)		—		—		—			—			(222	)		(222	)
Issuance of common stock:
Original issue shares, net		17,095,081		—		277			—			—			277
DRP original shares		1,298,249		—		29			—			—			29
Net activity related to stock-based awards		—		—		4			—			—			4
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
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
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

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 Pepco, DPL and ACE is also a reporting company under the Securities Exchange Act of 1934, as amended. Together the three companies constitute a single 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 the 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 company 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 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 commissions. 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 Standard Office Service in Delaware, the District of Columbia and Maryland, and Basic Generation Service (BGS) 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

The business of the Pepco Energy Services segment has consisted primarily of (i) the retail supply of electricity and natural gas and (ii) providing energy savings performance contracting services principally to federal, state and local government customers, and designing, constructing and operating combined heat and power and central energy plants for customers (Energy Services). Pepco Energy Services also owns and operates two oil-fired generation facilities. In December 2009, PHI announced that it will wind down 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 expiration dates.

The retail energy supply business 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, 2010, 2009 and 2008 were $1.6 billion, $2.3 billion and $2.5 billion, respectively, while operating income for the same periods was $59 million, $88 million and $54 million, respectively. In connection with the operation of the retail energy supply business, as of December 31, 2010, Pepco Energy Services provided letters of credit of $113 million and posted net cash collateral of $117 million. These collateral requirements, which are based on existing wholesale energy purchase and sale contracts and current market prices, will decrease over time as the contracts expire, with the collateral expected to be fully released by June 1, 2014. The Energy Services business will not be affected by the wind down of the retail energy supply business.

As further discussed in Note (6), “Goodwill,” 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 this business and (ii) a pre-tax charge of less than $1 million related to employee severance. In accordance with Financial Accounting Standards Board (FASB) guidance, the Pepco Energy Services retail electric and natural gas supply business will be reflected as a discontinued operation when the wind down is complete.

Other Business Operations

Through its subsidiary Potomac Capital Investment Corporation (PCI), PHI maintains a portfolio of cross-border energy lease investments, with a book value at December 31, 2010 of approximately $1.4 billion. 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 (2), “Significant Accounting Policies - Changes in Accounting Estimates,” Note (8), “Leasing Activities - Investment in Finance Leases Held in Trust,” Note (12), “Income Taxes,” and Note (17), “Commitments and Contingencies - PHI’s Cross-Border Energy Lease Investments.”

Discontinued Operations

On April 20, 2010, the Board of Directors of PHI approved a plan for the disposition of PHI’s competitive wholesale power generation business 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 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 constitutes a separate segment for financial reporting purposes. In addition, 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 a 20% to 50% voting interest and cannot exercise control over the operations and policies of the investment. Certain transmission and other facilities currently held, are consolidated in proportion to PHI’s percentage interest in the facility.

Change in Accounting Principle

Historically PHI performed its goodwill impairment test on July 1 each year. After the completion of the July 1, 2009 goodwill impairment test, PHI adopted a new accounting policy whereby PHI’s annual impairment review of goodwill will be performed annually as of November 1. Management believes that PHI’s new annual impairment testing date is preferable because it better aligns the timing of the test with management’s annual update of its long-term financial forecast. This change in accounting principle had no effect on PHI’s consolidated financial statements. For additional discussion on this matter see Note (6), “Goodwill.”

Consolidation of Variable Interest Entities

In accordance with FASB guidance on the consolidation of variable interest entities (Accounting Standards Codification (ASC) 810), Pepco Holdings consolidates variable interest entities with respect to which Pepco Holdings or a subsidiary is the primary beneficiary. The guidance addresses conditions under which an entity should be consolidated based upon variable interests rather than voting interests. Subsidiaries of Pepco Holdings have contractual arrangements with several entities 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). Due to a variable element in the pricing structure of the PPAs, PHI potentially assumes the variability in the operations of the generating facilities related to the NUGs and, therefore, has a variable interest in the entities. Despite exhaustive efforts to obtain information from these entities during 2010, PHI continues to be unable to obtain sufficient information to conduct the analysis required under FASB guidance to determine whether these three entities were variable interest entities or if ACE was the primary beneficiary. As a result, Pepco Holdings has applied the scope exemption from the guidance for enterprises that have conducted exhaustive efforts to obtain the necessary information, but have not been able to obtain such information.

Net purchase activities with the NUGs for the years ended December 31, 2010, 2009, and 2008, were approximately $292 million, $282 million and $349 million, respectively, of which approximately $270 million, $262 million and $305 million, respectively, consisted of power purchases under the PPAs. The power purchase costs are recoverable from ACE’s customers through regulated rates.

Pepco Power Purchase Agreement

During the third quarter of 2008, Pepco transferred to Sempra Energy Trading LLP an agreement with Panda-Brandywine, L.P. (Panda) under which Pepco was obligated to purchase from Panda 230 megawatts of capacity and energy annually through 2021 (the Panda PPA). Net purchase activities under the Panda PPA for the year ended December 31, 2008 were approximately $59 million.

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DPL Renewable Energy Transactions

PHI, through its DPL subsidiary, has entered into four wind PPAs in the aggregate amount of 350 megawatts that include the purchase of renewable energy credits (RECs) and one solar REC purchase agreement with a nine megawatt facility. The Delaware Public Service Commission (DPSC) has approved DPL’s entry into each of the agreements and the recovery of DPL’s purchase costs through customer rates. The RECs purchased under all the agreements will help DPL fulfill a portion of its requirements under the State of Delaware’s Renewable Energy Portfolio Standards Act.

Of the wind PPAs, three of the PPAs are with land-based facilities and one of the PPAs is with an offshore facility. One of the land-based facilities became operational and went into service in December 2009. DPL is obligated to purchase energy and RECs from this facility through 2024 in amounts generated and delivered not to exceed 50.25 megawatts at rates that are primarily fixed. DPL’s purchases under this PPA totaled $12 million for 2010. Purchases under the other wind agreements, which have terms ranging from 20 to 25 years, are currently expected to start in 2011 for the other two land-based contracts and 2016 for the offshore contract, if the projects are ultimately completed and operational. When they become operational, DPL is obligated to purchase energy and RECs in amounts generated and delivered by the sellers at rates that are primarily fixed under these agreements. Under one of the agreements, DPL is also obligated to purchase the capacity associated with the facility at rates that are generally fixed. If the offshore wind facility developer is unable to obtain all necessary permits and financing commitments, this could result in setbacks in the construction schedules and the operational start dates of the offshore wind facility. If the wind facilities are not operational by specified dates, DPL has the right to terminate the PPAs. The term of the agreement with the solar facility is 20 years and DPL is obligated to purchase RECs in an amount up to seventy percent of the energy output from the solar facility at a fixed price once the facility is operational, which is expected to be in the third quarter of 2011.

DPL concluded that consolidation is not required for any of these agreements under FASB guidance on the consolidation of variable interest entities.

ACE Transition Funding, LLC

ACE 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 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 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 has consolidated ACE Funding in its financial statements. An amendment to the variable interest entity consolidation guidance effective January 1, 2010 resulted in ACE Funding meeting the definition of a variable interest entity. PHI continued to consolidate ACE Funding in its financial statements upon the effective date of the amended variable interest entity consolidation guidance as ACE is the primary beneficiary of ACE Funding under the amended variable interest entity consolidation guidance.

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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 these 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 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 the loss is determined to be probable and is reasonably estimable.

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 have 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 the fourth quarter of 2010. This recalculated interest estimate is subject to adjustment when the IRS finalizes its calculation of the amount due.

Restructuring Charges

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 will be 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.

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. In the first half of 2010, PHI recorded an increase in transmission service revenue of $12 million that was then estimated to be collected over the 2010-2011 service year for costs incurred in the 2009 service year. In the fourth quarter of 2010, PHI recorded a decrease in transmission service revenue of $2 million that it estimates will be reflected as a reduction in transmission service rates for the 2011-2012 service year based on costs incurred during the first seven months of the 2010 service year. PHI will update its estimate of the reduction in transmission service revenue for the 2011-2012 service year in the

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first and second quarters of 2011 as its utility subsidiaries progress toward the completion of the 2010-2011 service year and final cost information from the 2010-2011 service year becomes available. In the second quarter of 2011, PHI expects to record the true-ups filed by its utility subsidiaries as part of their updated transmission service rates that are submitted to FERC.

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 has sought to recharacterize the leases as loan transactions as to which PHI would be subject to original issue discount income.

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.

As further described in Note (17), “Commitments and Contingencies,” PHI has recorded charges related to its cross-border energy lease investments of $2 million in 2010, $3 million in 2009 and $124 million in 2008.

Revenue Recognition

Regulated Revenue

The Power Delivery business recognizes revenue upon distribution of electricity and gas to its customers, including amounts for services rendered but not yet billed (unbilled revenue). Pepco Holdings recorded amounts for unbilled revenue of $218 million and $199 million as of December 31, 2010 and 2009, respectively. These amounts are included in Accounts receivable. Pepco Holdings’ 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 judgements 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.

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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 Revenues. Accruals for 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 (ISO) 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, which recognizes revenue as work is completed on the contract. Revenues from its operation and maintenance and other products and services contracts are recognized when earned.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in Pepco Holdings’ gross revenues were $373 million, $293 million and $278 million for the years ended December 31, 2010, 2009 and 2008, respectively.

Accounting for Derivatives

Pepco Holdings 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.

PHI accounts for its derivative activities in accordance with FASB guidance on derivatives and hedging which requires derivative instruments to be measured at fair value. Derivatives are recorded on the consolidated balance sheets as derivative assets or derivative liabilities unless designated as normal purchases or normal sales.

Mark-to-market gains and losses on derivatives that are not designated as hedges are presented on the consolidated statements of income as Operating revenue. PHI uses mark-to-market accounting through earnings for derivatives that either do not qualify for hedge accounting or that management does not designate as hedges.

The gain or loss on a derivative that hedges 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.

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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 under FASB guidance. This type of contract is used in normal operations, settles physically and follows standard accrual accounting. Unrealized gains and losses on these contracts do not appear on the consolidated balance sheets. Examples of these normal purchase transactions include purchases of fuel to be consumed in generating facilities or for delivery to customers. Normal sales transactions include agreements to deliver natural gas and electric power to customers. Normal purchases and normal sales transactions are 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.

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.

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.

Stock-Based Compensation

Pepco Holdings 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.

PHI’s compensation awards include both time-based restricted stock awards that vest over a three-year service period and performance-based restricted stock units that are earned based on performance over a three-year period. 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.

Pepco Holdings estimates the fair value of each stock option award on the date of grant using the Black-Scholes-Merton option pricing model. This model uses assumptions related to expected option term, expected volatility, expected dividend yield, and the risk-free interest rate. Pepco Holdings uses historical data to estimate option exercise and employee termination within the valuation model; groups of employees that have similar historical exercise behavior are considered separately for valuation purposes.

Pepco Holdings’ current policy is to issue new shares to satisfy stock option exercises and as restricted stock awards.

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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 Assets and Regulatory Liabilities,” for additional information.

PHI recognizes interest on under or over payments of income taxes, interest on uncertain tax positions and tax-related penalties in income tax expense. Deferred income tax expense generally represents the net change during the reporting period in the net deferred tax liability and deferred recoverable income taxes.

Investment tax credits are amortized to income over the useful lives of the related property.

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand, cash invested in money market funds and commercial paper held with original maturities of three months or less.

Restricted Cash Equivalents

The restricted cash equivalents included in Current Assets and the restricted cash equivalents included in 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 the Power Delivery business 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 becomes known.

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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, fuel oil and coal.

PHI utilizes the weighted average cost method of accounting for inventory items, other than fuel oil held for resale. 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 costs of natural gas, coal and fuel oil for generating facilities, including transportation costs, are included in inventory when purchased and charged to fuel expense when used. For PHI, the first-in-first-out method is not materially different from the weighted average cost method due to the high inventory turnover rate in the oil marketing business.

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 Pepco Holdings’ Power Delivery reporting unit for purposes of impairment testing based on the aggregation of its components. 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 further 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, 2010 and did not record an impairment charge as described in Note (6), “Goodwill.”

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 New Jersey Board of Public Utilities (NJBPU).

The transmission of electricity by Pepco, DPL, and ACE are regulated by FERC.

The FASB guidance on Regulated Operations (ASC 980) applies to the Power Delivery businesses of Pepco, DPL, and ACE. 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.

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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 (17) “Commitments and Contingencies — Regulatory and Other Matters — Rate 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.

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 use and control property, plant or equipment. If so, PHI determines the appropriate lease accounting classification.

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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, 2010, 2009, and 2008.

	Transmission and Distribution									Generation
	2010			2009			2008			2010			2009			2008
Pepco		2.6	%		2.7	%		2.7	%		—			—			—
DPL		2.8	%		2.8	%		2.8	%		—			—			—
ACE		2.8	%		2.8	%		2.8	%		—			—			—
Pepco Energy Services (a)		—			—			—			16.9	%		11.4	%		9.5	%

(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 (DOE) 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. 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.

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.

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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 $8 million, $7 million, and $5 million for the years ended December 31, 2010, 2009 and 2008, respectively.

Pepco Holdings recorded amounts for the equity component of AFUDC of $10 million, $3 million and $5 million for the years ended December 31, 2010, 2009, and 2008, 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, 2010 and 2009, $361 million and $352 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 a non-contributory defined benefit retirement plan that covers substantially all employees of Pepco, DPL, ACE and certain employees of other Pepco Holdings subsidiaries (the PHI Retirement Plan). Pepco Holdings also provides supplemental retirement benefits to certain eligible executives and key employees through 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).

See Note (10), “Pension and Other Postretirement Benefits,” for additional information.

Preferred Stock

As of December 31, 2010 and 2009, 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, 2010 and 2009.

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:

Operating Revenue

During 2009, DPL recorded additional revenue of $14 million related to the unbilled portion of the Gas Cost Rate (GCR) revenue, which was not previously recognized. Because the GCR revenue is deferred, an additional expense of $14 million was recorded in 2009. Consequently, there was no impact on consolidated net income.

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Operating Expenses

During 2010, Pepco recorded an adjustment to correct certain errors which resulted in a decrease to Other taxes 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.

During 2008, PHI identified an error in the accounting for certain of its restricted stock awards granted under the Long-Term Incentive Plan that resulted in an understatement of stock-based compensation expense in 2007 and 2006. Pepco and DPL also recorded adjustments to correct errors in Other operation and maintenance expenses for prior periods dating back to February 2005 for which late payment fees were incorrectly recognized. These errors were corrected in 2008, resulting in an increase in Other operation and maintenance expenses for the year ended December 31, 2008 of $15 million.

Income Tax Expense Related to Continuing Operations

During 2010, PHI recorded an adjustment to correct certain income tax errors related to prior periods. The pre-tax adjustment resulted in a decrease in income tax expense of $5 million for the year ended December 31, 2010.

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.

(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Transfers and Servicing (ASC 860)

The FASB issued new guidance that removes the concept of a qualifying special-purpose entity (QSPE) from the guidance on transfers and servicing and the QSPE scope exception in the guidance on consolidation. The new guidance also changes the requirements for derecognizing financial assets and requires additional disclosures about a transferor’s continuing involvement in transferred financial assets. The guidance was effective for transfers of financial assets occurring in fiscal periods beginning on January 1, 2010 for PHI. This guidance did not have a material impact on PHI’s overall financial condition, results of operations, or cash flows.

Fair Value Measurement and Disclosures (ASC 820)

The FASB issued new disclosure requirements for recurring and non-recurring fair value measurements. The guidance, effective beginning with PHI’s March 31, 2010 financial statements, requires the disaggregation of balance sheet items measured at fair value into subsets of balance sheet items based on the nature and risks of the items. The standard requires descriptions of pricing inputs and valuation methodologies for instruments with Level 2 or 3 valuation inputs. In addition, the standard requires information about any significant transfers of instruments between Level 1 and 2 valuation categories. These additional disclosures are included in Note (16), “Fair Value Disclosures.”

Consolidation of Variable Interest Entities (ASC 810)

The FASB issued new consolidation guidance regarding variable interest entities effective January 1, 2010 that eliminates the quantitative analysis requirement and adds new qualitative factors to determine whether consolidation is required. The new qualitative factors are applied on a quarterly basis to interests in

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variable interest entities. Under the new guidance, the holder of the interest with the power to direct the most significant activities of the entity and the right to receive benefits or absorb losses significant to the entity would consolidate. The new guidance retains the provision that allows entities created before December 31, 2003 to be scoped out from a consolidation assessment if exhaustive efforts are taken and there is insufficient information to determine whether there is a relationship with a variable interest entity or the primary beneficiary of a variable interest entity. This guidance did not have a material impact on PHI’s overall financial condition, results of operations, or cash flows.

Subsequent Events (ASC 855)

The FASB issued new guidance that eliminates the requirement for PHI to disclose the date through which it has evaluated subsequent events beginning with its March 31, 2010 financial statements.

Receivables (ASC 310)

The FASB issued new disclosure requirements relating to an entity’s credit exposure to financing receivables that became effective beginning with PHI’s December 31, 2010 financial statements. The new guidance requires disclosures about the credit quality of receivables with maturities of greater than one year and related accounting policies. The primary impact to PHI was additional disclosures about the credit quality of its lessees under its cross-border energy lease investments, which disclosures are included in Note (8), “Leasing Activities.”

(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Fair Value Measurement and Disclosures (ASC 820)

The FASB issued new disclosure requirements that require the disaggregation of the Level 3 fair value measurement reconciliations into separate categories for significant purchases, sales, issuances, and settlements. This requirement is effective beginning with PHI’s March 31, 2011 financial statements. PHI is evaluating the impact of this new guidance on its financial statement footnote disclosures.

Revenue Recognition (ASC 605)

The FASB has issued new revenue recognition guidance related to the determination of separate units of accounting for multiple-deliverables within a single contract. PHI’s revenues potentially affected by this guidance are primarily those of Pepco Energy Services’ energy services business, which enters into contracts that have multiple deliverables, such as design, installation, operation and maintenance, measurement, and verification. The guidance is effective January 1, 2011 for PHI, and it is not expected to have a material impact on Pepco Energy Services’ revenue recognition methods or results.

Goodwill (ASC 350)

In December 2010, the FASB issued new guidance on performing goodwill impairment tests. The new guidance eliminates the option to exclude liabilities that are part of the capital structure of the reporting unit when calculating the carrying value of the reporting unit. This is effective for PHI beginning January 1, 2011. Under the new guidance, the carrying value of the reporting unit is the net amount of the assets and liabilities allocated to the reporting unit. PHI allocates liabilities to the reporting unit when performing its goodwill impairment test, so the new guidance is not expected to change how PHI currently performs its goodwill impairment test.

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(5) SEGMENT INFORMATION

Pepco Holdings’ management has identified its operating segments at December 31, 2010 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 acquisition financing costs. Segment financial information for continuing operations, for the years ended December 31, 2010, 2009, and 2008, is as follows:

	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			1,699			14,480
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 the Power Delivery segment for purposes of assessing impairment. Total assets also include capital expenditures related to certain hardware and software expenditures which primarily benefit the Power Delivery business. 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 Medicare Part D subsidy.

	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

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(a) Total Assets in this column includes Pepco Holdings’ goodwill balance of $1.4 billion, all of which is allocated to the Power Delivery segment for purposes of assessing impairment. Total assets also include capital expenditures related to certain hardware and software expenditures which primarily benefit the Power Delivery business. 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.

(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.

	Year Ended December 31, 2008
	(millions of dollars)
	Power Delivery		Pepco Energy Services		Other Non- Regulated			Corporate and Other  (a)			PHI Consolidated
Operating Revenue	$	5,488	$	2,648	$	(60	)(c)	$	(17	)	$	8,059
Operating Expenses (b)		4,932		2,592		4			(18	)		7,510
Operating Income (Loss)		556		56		(64	)		1			549
Interest Income		14		4		4			(5	)		17
Interest Expense		195		5		19			86			305
Other Income (Expenses)		14		2		(5	)		1			12
Preferred Stock Dividends		—		—		3			(3	)		—
Income Tax Expense (Benefit)		139		18		(30	)(c)		(37	)		90
Net Income (Loss) from Continuing Operations		250		39		(57	)(c)		(49	)		183
Total Assets		10,089		798		1,452			1,843			14,182
Construction Expenditures	$	587	$	31	$	—		$	25		$	643

(a) Total Assets in this column includes Pepco Holdings’ goodwill balance of $1.4 billion, all of which is allocated to the Power Delivery segment for purposes of assessing impairment. Total assets also include capital expenditures related to certain hardware and software expenditures which primarily benefit the Power Delivery business. 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, $(11) million for Operating Expense, $(70) million for Interest Income, $(67) million for Interest Expense, and $(3) million for Preferred Stock Dividends.

(b) Includes depreciation and amortization of $338 million, consisting of $317 million for Power Delivery, $13 million for Pepco Energy Services, $2 million for Other Non-Regulated and $6 million for Corporate and Other.

(c) Included in Operating Revenue is 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 Tax Benefit is a $7 million after-tax charge for the additional interest accrued on the related tax obligations.

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(6) GOODWILL

Substantially all of PHI’s $1.4 billion goodwill balance was generated by Pepco’s acquisition of Conectiv in 2002 and is allocated entirely to the Power Delivery reporting unit based on the aggregation of its regulated public utility company components for purposes of assessing impairment under FASB guidance on goodwill and other intangibles (ASC 350). PHI’s annual impairment test as of November 1, 2010 indicated that goodwill was not impaired. As of December 31, 2010, after review of its significant assumptions in the goodwill impairment analysis, PHI concluded that there were no events requiring it to perform an interim goodwill impairment test. Although PHI’s market capitalization was below book value at December 31, 2010, PHI’s market capitalization has improved compared to earlier periods when it performed interim impairment tests. PHI performed its previous annual goodwill impairment test as of November 1, 2009, and interim impairment tests as of March 31, 2009 and December 31, 2008 when its market capitalization was further below book value than at November 1, 2009. PHI concluded that its goodwill was not impaired at those earlier dates.

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 the Power Delivery business 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, Other Non-Regulated, and Corporate and Other) at November 1, 2010. The sum of the fair value of all reporting units was reconciled to PHI’s market capitalization at November 1, 2010 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, 2010. 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. Given the lack of a fundamental change in the Power Delivery reporting unit’s business, PHI does not believe that the decline in its stock price since mid-2008 indicated a commensurate decline in the fair value of PHI’s Power Delivery reporting unit. PHI’s Power Delivery reporting unit consists of regulated companies with regulated recovery rates and approved rates of return allowing for generally predictable and steady streams of revenues and cash flows over an extended period of time.

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PHI will continue to closely monitor for indicators of goodwill impairment, including the sustained period of time that PHI’s stock price has been below its book value.

As discussed in Note (1), “Organization,” on December 7, 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 therefore, PHI recorded a goodwill impairment charge of $4 million in the fourth quarter of 2009 to write-off the goodwill associated with this business.

A roll forward of PHI’s goodwill balance is set forth below in millions of dollars:

Balance, December 31, 2008	$	1,411
Less: Impairment charge associated with wind-down of Pepco Energy Services retail energy business		(4	)
Balance, December 31, 2009		1,407
Less: Adjustments		—
Balance, December 31, 2010	$	1,407

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(7) REGULATORY ASSETS AND REGULATORY LIABILITIES

The components of Pepco Holdings’ regulatory asset and liability balances at December 31, 2010 and 2009 are as follows:

	2010		2009
	(millions of dollars)
Regulatory Assets
Pension and OPEB costs (a)	$	848	$	752
Securitized stranded costs (a)		559		620
Deferred income taxes		139		135
Deferred energy supply costs (a)		61		24
Deferred debt extinguishment costs (a)		61		67
Recoverable meter-related costs (a)		44		5
Deferred losses on gas derivatives		31		42
Other		172		156
Total Regulatory Assets	$	1,915	$	1,801
Regulatory Liabilities
Asset removal costs	$	361	$	352
Deferred income taxes due to customers		50		53
Excess depreciation reserve		42		58
Federal and New Jersey tax benefits, related to securitized stranded costs		22		25
Deferred energy supply costs		35		117
Other		18		8
Total Regulatory Liabilities	$	528	$	613

(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 the unfunded portion of Pepco Holdings’ defined benefit pension and other postretirement benefit (OPEB) plans that is probable of recovery by Pepco, DPL and ACE in rates.

Securitized Stranded Costs: Includes contract termination payments under a contract between ACE and an unaffiliated non-utility generator 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.

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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 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 territory as a result of the Advanced Metering Infrastructure (AMI) project.

Deferred Losses on Gas Derivatives: Represents losses associated with hedges of natural gas purchases that are recoverable by DPL through the Gas Cost Rate approved by the DPSC.

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: 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.

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 issues its final regulations with respect to normalization of these federal excess deferred taxes.

Other: Includes miscellaneous regulatory liabilities.

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(8) LEASING ACTIVITIES

Investment in Finance Leases Held in Trust

As of December 31, 2010 and 2009, Pepco Holdings had cross-border energy lease investments of $1.4 billion consisting of hydroelectric generation and coal-fired electric generation facilities and natural gas distribution networks located outside of the United States.

As further discussed in Note (2), “Significant Accounting Policies — Changes in Accounting Estimates,” and Note (17), “Commitments and Contingencies - PHI’s Cross-Border Energy Lease Investments,” during 2010, 2009 and 2008, 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, $3 million and $124 million in 2010, 2009 and 2008, respectively.

The components of the cross-border energy lease investments, as of December 31, are summarized below:

	2010			2009
	(millions of dollars)
Scheduled lease payments to PHI, net of non-recourse debt	$	2,265		$	2,281
Less: Unearned and deferred income		(842	)		(895	)
Investment in finance leases held in trust		1,423			1,386
Less: Deferred income tax liabilities		(816	)		(748	)
Net investment in finance leases held in trust	$	607		$	638

Income recognized from cross-border energy lease investments was comprised of the following for the years ended December 31:

	2010			2009			2008
	(millions of dollars)
Pre-tax income from PHI’s cross-border energy lease investments (included in Other Revenue)	$	55		$	54		$	75
Non-cash charge to reduce equity value of PHI’s cross-border energy lease investments		(2	)		(3	)		(124	)
Pre-tax income (loss) from PHI’s cross-border energy lease investments after adjustment		53			51			(49	)
Income tax expense (benefit)		14			16			(12	)
Net income (loss) from PHI’s cross-border energy lease investments	$	39		$	35		$	(37	)

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 for each of the years 2011 through 2015 are zero, and $1,423 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

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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 the 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, 2010, 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)	2010
	(millions of dollars)
Rated Entities
AA/Aa and above	$	709
A		549
Total		1,258
Non Rated Entities		165
Total	$	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.

Capital lease assets recorded within Property, Plant and Equipment at December 31, 2010 and 2009, in millions of dollars, are comprised of the following:

At December 31, 2010	Original Cost		Accumulated Amortization		Net Book Value
Transmission	$	76	$	29	$	47
Distribution		76		29		47
General		3		3		—
Total	$	155	$	61	$	94
At December 31, 2009
Transmission	$	76	$	27	$	49
Distribution		76		26		50
General		3		3		—
Total	$	155	$	56	$	99

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The approximate annual commitments under all capital leases are $15 million for each year 2011 through 2015, and $61 million thereafter.

Rental expense for operating leases was $45 million, $45 million, and $47 million for the years ended December 31, 2010, 2009, and 2008, respectively.

Total future minimum operating lease payments for Pepco Holdings as of December 31, 2010, are $34 million in 2011, $33 million in 2012, $31 million in 2013, $29 million in 2014, $29 million in 2015 and $377 million thereafter.

(9) PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment is comprised of the following:

At December 31, 2010	Original Cost		Accumulated Depreciation		Net Book Value
	(millions of dollars)
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
At December 31, 2009
Generation	$	96	$	56	$	40
Distribution		7,229		2,639		4,590
Transmission		2,193		751		1,442
Gas		398		116		282
Construction work in progress		415		—		415
Non-operating and other property		1,100		628		472
Total	$	11,431	$	4,190	$	7,241

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.

Asset Sales

In January 2008, DPL completed (i) the sale of its retail electric distribution assets located on the Eastern Shore of Virginia for approximately $49 million, and (ii) the sale of its wholesale electric transmission assets located on the Eastern Shore of Virginia for approximately $5 million.

Jointly Owned Plant

PHI’s consolidated balance sheets include its proportionate share of assets and liabilities related to jointly owned plant. At December 31, 2010 and 2009, PHI’s subsidiaries had a $14 million net book value ownership interest 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.

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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 the PJM Interconnection, LLC (PJM). In February 2007, Pepco Energy Services provided notice to PJM of its intention to deactivate these facilities. Pepco Energy Services currently plans to deactivate both facilities by May 2012. PJM has informed Pepco Energy Services that these facilities are not expected to be needed for reliability after that time, but that its evaluation is dependent on the completion of transmission and distribution upgrades. Pepco Energy Services’ timing for deactivation of the facilities, in whole or in part, may be accelerated or delayed based on the operating condition of the facilities, economic conditions, and reliability considerations. PHI has recorded decommissioning costs of $4 million related to these generating facilities in 2010.

(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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All amounts in the following tables are in millions of dollars:

At December 31,	Pension Benefits						Other Postretirement Benefits
	2010			2009			2010			2009
Change in Benefit Obligation
Benefit obligation at beginning of year	$	1,796		$	1,753		$	651		$	653
Service cost		35			36			5			7
Interest cost		110			111			39			40
Amendments		(7	)		1			—			—
Actuarial loss (gain)		179			72			42			(10	)
Benefits paid (a)		(146	)		(177	)		(39	)		(39	)
Termination benefits		3			—			6			—
Benefit obligation at end of year	$	1,970		$	1,796		$	704		$	651
Change in Plan Assets
Fair value of plan assets at beginning of year	$	1,500		$	1,123		$	242		$	192
Actual return on plan assets		173			248			26			40
Company contributions		105			306			46			49
Benefits paid (a)		(146	)		(177	)		(39	)		(39	)
Fair value of plan assets at end of year	$	1,632		$	1,500		$	275		$	242
Funded Status at end of year (plan assets less plan obligations)	$	(338	)	$	(296	)	$	(429	)	$	(409	)

(a) Other Postretirement Benefits paid is net of Medicare Part D subsidy receipts of $3 million in 2010 and $3 million in 2009.

At December 31, 2010, PHI Retirement Plan assets were $1.6 billion and the accumulated benefit obligation (ABO) was approximately $1.9 billion. At December 31, 2009, PHI’s Retirement Plan assets were approximately $1.5 billion and the ABO was approximately $1.6 billion.

The following table provides the amounts recognized in PHI’s consolidated balance sheets as of December 31, in millions of dollars:

	Pension Benefits						Other Postretirement Benefits
	2010			2009			2010			2009
Regulatory asset	$	655		$	583		$	193		$	169
Current liabilities		(6	)		(6	)		—			—
Pension benefit obligation		(332	)		(290	)		—			—
Other postretirement benefit obligations		—			—			(429	)		(409	)
Deferred income taxes, net		12			11			—			—
Accumulated other comprehensive loss, net of tax		17			17			—			—
Net amount recognized	$	346		$	315		$	(236	)	$	(240	)

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Amounts included in AOCL (pre-tax) and regulatory assets at December 31, in millions of dollars, consist of:

	Pension Benefits					Other Postretirement Benefits
	2010			2009		2010			2009
Unrecognized net actuarial loss	$	692		$	611	$	208		$	188
Unamortized prior service cost (credit)		(8	)		—		(17	)		(21	)
Unamortized transition liability		—			—		2			2
Total	$	684		$	611	$	193		$	169
Accumulated other comprehensive loss ($17 million, net of tax, at December 31, 2010 and 2009)	$	29		$	28	$	—		$	—
Regulatory assets		655			583		193			169
Total	$	684		$	611	$	193		$	169

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 $48 million and $1 million, respectively. The estimated net loss and prior service credit for the other postretirement benefit plan that will be amortized from AOCL into net periodic benefit cost over the next reporting year are $12 million and $4 million, respectively.

The table below provides the components of net periodic benefit costs recognized for the years ended December 31, in millions of dollars:

	Pension Benefits									Other Postretirement Benefits
	2010			2009			2008			2010			2009			2008
Service cost	$	35		$	36		$	36		$	5		$	7		$	7
Interest cost		110			111			108			39			40			40
Expected return on plan assets		(117	)		(101	)		(130	)		(16	)		(13	)		(16	)
Amortization of prior service cost		—			—			—			(5	)		(4	)		(4	)
Amortization of net actuarial loss		42			56			10			13			16			13
Recognition of benefit contract		—			1			—			—			—			—
Plan amendments		1			—			—			—			—			—
Termination benefits		3			—			—			6			—			—
Net periodic benefit cost	$	74		$	103		$	24		$	42		$	46		$	40

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, in million of dollars:

	2010		2009		2008
Pepco	$	40	$	38	$	24
DPL		28		25		3
ACE		23		20		12
Other subsidiaries		25		66		25
Total	$	116	$	149	$	64

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The following weighted average assumptions were used to determine the benefit obligations at December 31:

	Pension Benefits						Other Postretirement Benefits
	2010			2009			2010			2009
Discount rate		5.65	%		6.40	%		5.60	%		6.30	%
Rate of compensation increase		5.00	%		5.00	%		5.00	%		5.00	%
Health care cost trend rate assumed for current year		—			—			7.50	%		8.00	%
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		—			—			2015			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	$	(2)
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
	2010			2009			2008			2010			2009			2008
Discount rate		6.40	%		6.50	%		6.25	%		6.30	%		6.50	%		6.25	%
Expected long-term return on plan assets		8.00	%		8.25	%		8.25	%		8.00	%		8.25	%		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.

In selecting an expected rate of return on plan assets, PHI considers actual historical returns, economic forecasts and the judgment of its investment consultants on expected long-term performance for the types of investments held by the plan. The estimated asset class returns are weighted by PHI’s target 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 8.00% at December 31, 2010. PHI periodically reviews its asset mix and rebalances assets back to the target allocation.

In 2008, PHI and its actuaries conducted an experience study, a periodic analysis of plan experience against actuarial assumptions. The study reviewed withdrawal, retirement and salary increase assumptions. As a result of the study, assumed retirement rates were changed and the age-related salary scale assumption was increased from 4.50% to 5.00% over an average employee’s career. No changes were made for the 2010 and 2009 valuations.

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In addition, for the 2008 Other Postretirement Benefit Plan valuation, the medical trend rate was changed to 8.5%, declining 0.5% per year to 5.00% in 2015 and beyond, from the 2007 valuation assumption for 2008 of 7%, declining 1% per year to 5% in 2010 and beyond. No changes were made for the 2010 and 2009 valuations.

Plan Assets

Investment Policies and Strategies

The goal of PHI’s investment policy is to preserve capital and maximize investment earnings in excess of inflation within acceptable levels of volatility to meet the actuarial projected liabilities of the benefit plans. To accomplish this goal, PHI actively manages its plan assets with the objective of optimizing long-term returns while maintaining a high standard of portfolio quality and proper diversification.

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 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.

Under these guidelines, PHI diversifies assets in order to protect against large investment losses and to reduce the probability of excessive volatility while earning a return that is commensurate with an acceptable risk level. Assets are diversified by allocating investments to various asset classes and investment styles within those asset classes and by retaining investment management firms with complementary investment styles and approaches.

Based on the assessment of employee demographics, actuarial funding, and PHI’s business and financial circumstances, PHI believes that its risk posture is slightly below average relative to other pension plans. On a periodic basis, PHI reviews its asset mix and rebalances assets back to the target allocation over a reasonable period of time.

The PHI Retirement Plan asset allocations at December 31, 2010 and 2009, by asset category, were as follows:

	Plan Assets at December 31,						Target Plan Asset Allocation			Minimum  Maximum
	2010			2009
Asset Category
Equity		53	%		56	%		60	%		55% - 65%
Fixed Income		40	%		37	%		30	%		30% - 50%
Other (real estate, private equity)		7	%		7	%		10	%		0% - 10%
Total		100	%		100	%		100	%

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PHI’s other postretirement benefit plan asset allocations at December 31, 2010 and 2009, by asset category, were as follows:

	Plan Assets at December 31,						Target Plan Asset Allocation			Minimum  Maximum
	2010			2009
Asset Category
Equity		61	%		60	%		60	%		55% - 65%
Fixed Income		35	%		35	%		35	%		20% - 50%
Cash		4	%		5	%		5	%		0% - 10%
Total		100	%		100	%		100	%

Risk Management and General Investment Manager Guidelines

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.

For equity managers, the maximum position in a single issuer’s securities should not exceed 5% of the portfolio’s cost or 8% of the portfolio’s market value. The holdings in any one industry should not exceed 25% of the portfolio’s market value, and the holdings in any one economic sector should not exceed 40% of the portfolio’s market value. International equity managers should not invest more than 25% of the portfolio’s market value in emerging markets and no more than 50% in any single country. Market and currency hedges are limited to defensive purposes.

For fixed income managers, the maximum position in a single issuer’s securities should not exceed 5% of the portfolio’s market value, with the exception of US Treasury or US Government agencies and instrumentalities. The investment manager is expected to maintain a weighted average bond portfolio quality rating of at least “A.” The manager may invest up to 20% of the portfolio’s market value in bonds rated below investment grade. A manager may invest in non-dollar securities up to 20% of the portfolio’s market value, and currency hedging is allowed if it is a normal approach to international fixed income management. No more than 30% of the portfolio’s market value can be invested in combined non-dollar and below investment grade securities.

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. PHI common stock is not a permitted plan asset.

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

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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 investments.

• 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.

The following tables present the fair values of PHI’s Retirement Plan and other postretirement benefit plan assets by asset category within the fair value hierarchy levels, as of December 31, 2010 and 2009:

	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

(b) Predominantly includes domestic common stock and commingled funds.

(c) Predominantly includes foreign common and preferred stock and warrants.

(d) Predominantly includes corporate bonds, government bonds, municipal/provincial bonds, collateralized mortgage obligations, asset backed securities and commingled funds.

(e) 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, 2009
	(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)	$	627	$	340	$	287	$	—
International (b)		198		197		1		—
Fixed Income (c)		553		84		457		12
Other
Private Equity		55		—		—		55
Real Estate		40		—		—		40
Cash Equivalents (d)		27		27		—		—
Pension Plan Assets Subtotal		1,500		648		745		107
Other Postretirement Plan Assets:
Equity (e)		145		125		20		—
Fixed Income (f)		85		85		—		—
Cash Equivalents		12		12		—		—
Postretirement Plan Assets Subtotal		242		222		20		—
Total Pension and Other Postretirement Plan Assets	$	1,742	$	870	$	765	$	107

(a) Predominantly includes domestic common and preferred stock, warrants and commingled funds.

(b) Predominantly includes foreign common and preferred stock.

(c) Predominantly includes corporate bonds, government bonds, municipal/provincial bonds, collateralized mortgage obligations, asset backed securities, commingled funds and guaranteed contracts.

(d) Predominantly includes investment in short term investment funds with $21 million held in equity accounts and $2 million held in fixed income accounts.

(e) Includes domestic and international commingled funds.

(f) Includes fixed income commingled funds.

There were no significant concentrations of risk in pension and other postretirement benefit plan assets at December 31, 2010 and 2009.

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.

As a practical expedient, the fair values of PHI’s interests in commingled funds are based on the Net Asset Value (NAV) of those funds. These funds have ongoing subscription and redemption activities. Commingled funds with publicly quoted NAV and active trading are classified as level 1 investments. Investments in commingled funds that are not publicly traded, but the underlying assets held in these funds are traded in active markets and the prices for these assets are readily observable, are classified as level 2 investments. Investments in commingled funds with redemption restrictions 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.

As a practical expedient, the fair values of PHI’s interests in commingled funds are based on the NAV. These funds have ongoing subscription and redemption activities. Commingled funds with publicly quoted NAV and active trading are classified as level 1 investments. Investments in commingled funds that are not publicly traded, but the underlying assets held in these funds are traded in active markets and the prices for these assets are readily observable, are classified as level 2 investments. Investments in commingled funds with redemption restrictions 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 valued at the 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 the measurement of 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, 2010 and 2009 totaled $42 million and $26 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, 2010 and 2009 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, 2010	$	—	$	12		$	55	$	40		$	107
Transfer in (out) of Level 3		23		—			—		—			23
Purchases, sales, and other		3		(10	)		1		16			10
Unrealized gain/loss		4		—			2		(1	)		5
Realized gain/loss		—		1			4		—			5
Ending balance as of December 31, 2010	$	30	$	3		$	62	$	55		$	150

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	Fair Value Measurement Using Significant Unobservable  Inputs (Level 3)
	(millions of dollars)
	Fixed Income			Private Equity		Real Estate			Total Level 3
Beginning balance as of January 1, 2009	$	20		$	32	$	69		$	121
Transfer in (out) of Level 3		(8	)		—		—			(8	)
Purchases, sales, and other		—			5		6			11
Unrealized gain/loss		—			18		(29	)		(11	)
Realized gain/loss		—			—		(6	)		(6	)
Ending balance as of December 31, 2009	$	12		$	55	$	40		$	107

Cash Flows

Contributions - PHI Retirement Plan

During 2010, the PHI Service Company made discretionary tax-deductible contributions totaling $100 million to the PHI Retirement Plan, which brought plan assets to at least the funding target level for 2010 under the Pension Protection Act. In 2009, PHI made discretionary tax-deductible contributions totaling $300 million to the PHI Retirement Plan, which brought plan assets to at least the funding target level for 2009 under the Pension Protection Act. Of this amount, $240 million was contributed through tax-deductible contributions from Pepco, ACE and DPL in the amounts of $170 million, $60 million and $10 million, respectively. The remaining $60 million contribution was made through tax-deductible contributions from the PHI Service Company.

Although PHI projects there will be no quarterly minimum funding requirements under the Pension Protection Act guidelines in 2011, PHI currently plans to make a discretionary tax-deductible contribution of up to $150 million to bring its plan assets to at least the funding target level for 2011 under the Pension Protection Act.

Contributions - Other Postretirement Benefit Plan

In 2010 and 2009, Pepco contributed $10 million and $8 million, respectively, DPL contributed $9 million and $10 million, respectively, and ACE contributed $8 million and $6 million, respectively, to the other postretirement benefit plan. In 2010 and 2009, contributions of $8 million and $16 million, respectively, were made by other PHI subsidiaries. Assuming no changes to the other postretirement benefit plan assumptions, PHI expects to contribute similar amounts in 2011.

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 (millions of dollars):

Years	Pension Benefits		Other  Postretirement Benefits
2011	$	138	$	47
2012		123		48
2013		121		50
2014		126		51
2015		127		52
2016 through 2020	$	657	$	261

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Medicare Prescription Drug Improvement and Modernization Act of 2003

On December 8, 2003, the Medicare Prescription Drug Improvement and Modernization Act of 2003 (the Medicare Act) became effective. The Medicare Act introduced a prescription drug benefit under Medicare (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. At December 31, 2010, the accumulated postretirement benefit obligation has been reduced by the present value of projected Medicare Part D subsidies of $51 million. In each of 2010 and 2009, Pepco Holdings received $3 million 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, $12 million, and $12 million for the years ended December 31, 2010, 2009, and 2008, 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	2010		2009
		(millions of dollars)
First Mortgage Bonds
Pepco:
5.75% (a)	2010	$	—	$	16
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:
7.25% - 7.63%	2010 - 2014		7		8
6.63%	2013		69		69
7.68%	2015 - 2016		17		17
7.75%	2018		250		250
6.80% (a)	2021		39		39
5.60% (a)	2025		4		4
4.875% (a)(b)(c)	2029		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
4.90% (a)(e)	2026		35		35
Total First Mortgage Bonds			2,598		2,592
Unsecured Tax-Exempt Bonds
DPL:
5.50% (d)	2025		—		15
5.65% (f)	2028		—		16
1.80% (d)	2025		15		—
2.30% (f)	2028		16		—
5.40%	2031		78		—
Total Unsecured Tax-Exempt Bonds		$	109	$	31

(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) The tax-exempt bonds secured by these Collateral First Mortgage Bonds are subject to mandatory tender on May 1, 2011.

(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		2010			2009
			(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:
7.47% - 7.69%		2017		11			9
Notes (unsecured)
PHI:
Variable		2010		—			250
4.00%		2010		—			200
6.45%		2012		—			750
2.70%		2015		250			—
5.90%		2016		190			200
6.125%		2017		81			250
6.00%		2019		—			200
7.45%		2032		185			250
DPL:
5.00%		2014		100			100
5.00%		2015		100			100
Total Notes (unsecured)				906			2,300
Total Long-Term Debt				3,675			4,983
Other long-term debt				2			—
Net unamortized discount				(12	)		(14	)
Current portion of long-term debt				(36	)		(499	)
Total Net Long-Term Debt			$	3,629		$	4,470
Transition Bonds Issued by ACE Funding
4.21%		2013	$	9		$	34
4.46%		2016		39			49
4.91%		2017		118			118
5.05%		2020		54			54
5.55%		2023		147			147
Total				367			402
Net unamortized discount				—			—
Current portion of long-term debt				(35	)		(34	)
Total Net Long-Term Transition Bonds issued by ACE Funding			$	332		$	368

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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 the discussion under the heading “Consolidation of Variable Interest Entities — ACE Transition Funding, LLC” in Note (2), “Significant Accounting Policies.” The aggregate amounts of maturities for long-term debt and Transition Bonds outstanding at December 31, 2010, are $71 million in 2011, $68 million in 2012, $558 million in 2013, $334 million in 2014, $409 million in 2015, and $2,602 million thereafter.

PHI’s long-term debt is subject to certain covenants. As of December 31, 2010, PHI and its subsidiaries were in compliance with all such covenants.

Unsecured Notes

On October 1, 2010, PHI issued $250 million of 2.70% Senior Notes due 2015.

Long-Term Project Funding

As of December 31, 2010 and 2009, Pepco Energy Services had outstanding total long-term project funding (including current maturities) of $19 million and $20 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, 2010, are $4 million for 2011, $2 million for each year 2012 through 2014, $1 million for 2015 and $8 million thereafter.

Tax-Exempt Bonds

DPL

In 2010, DEDA issued $78 million of 5.40% Gas Facilities Refunding Revenue Bonds due 2031 for the benefit of DPL. DPL used the proceeds to effect the redemption of the outstanding amounts of five series of tax-exempt bonds in an aggregate principal amount of $78 million that were purchased by DPL in 2008.

In 2010, DPL resold (i) $15 million of 1.80% Pollution Control Refunding Revenue Bonds (Delmarva Power & Light Company Project) Series 2000C due 2025, and (ii) $16 million of 2.30% Pollution Control Refunding Revenue Bonds (Delmarva Power & Light Company Project) Series 2000D due 2028. The bonds were originally issued for the benefit of DPL in 2000 and had been purchased by DPL in July 2010 pursuant to a mandatory repurchase provision in the respective indentures for the bonds that was triggered by the expiration of the original interest period for the bonds. The bonds are subject to mandatory purchase by DPL on June 1, 2012.

ACE

In 2010, ACE resold $23 million of 4.875% Pollution Control Revenue Refunding Bonds due 2029, issued by The Pollution Control Financing Authority of Salem County for the benefit of ACE. The bonds had been repurchased by ACE in 2008 in response to the disruption in the tax-exempt bond market.

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Short-Term Debt

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. A detail of the components of Pepco Holdings’ short-term debt at December 31, 2010 and 2009 is as follows:

	2010		2009
	(millions of dollars)
Commercial Paper	$	388	$	384
Variable Rate Demand Bonds		146		146
Total	$	534	$	530

Commercial Paper

Pepco Holdings maintains an ongoing commercial paper program of up to $875 million. 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 that company’s borrowing capacity under PHI’s $1.5 billion primary credit facility, which is described below under the heading “Credit Facilities.”

Pepco Holdings and ACE had $230 million and $158 million, respectively, of commercial paper outstanding at December 31, 2010. Pepco did not issue any commercial paper during 2010, and DPL had no commercial paper outstanding at December 31, 2010. The weighted average interest rate for Pepco Holdings, DPL and ACE commercial paper issued during 2010 was 0.63%, 0.34% and 0.36%, respectively. The weighted average maturity of all commercial paper issued by Pepco Holdings, DPL and ACE in 2010 was nine, two and seven 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 the 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, 2010, $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 Pollution Control Financing Authority of Salem County has issued tax-exempt VRDBs for the benefit of ACE in the aggregate principal of $23 million. In June 2009, ACE completed the remarketing of these VRDBs supported by letters of credit issued by The Bank of New York Mellon. In June 2010, ACE (i) replaced the letter of credit associated with $18.2 million of Pollution Control Revenue Refunding Bonds, 1997 Series A (Atlantic City Electric Company Project) due 2014 with a new irrevocable direct pay letter of credit expiring in April 2014, and (ii) replaced the letter of credit associated with $4.4 million of Pollution Control Revenue Refunding Bonds, 1997 Series B (Atlantic City Electric Company Project) due 2017 with a new irrevocable direct pay letter of credit expiring in June 2014.

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The VRDBs outstanding at December 31, 2010 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 0.45% during 2010 and 1.44% during 2009.

Credit Facilities

PHI, Pepco, DPL and ACE maintain an unsecured credit facility to provide for their respective short-term liquidity needs. The aggregate borrowing limit under the facility is $1.5 billion, all or any portion of which may be used to obtain loans or to issue letters of credit. PHI’s credit limit under the facility is $875 million. The credit limit of each of Pepco, DPL and ACE is the lesser of $500 million and the maximum amount of debt the company is permitted to have outstanding by its regulatory authorities, except that the aggregate amount of credit used by Pepco, DPL and ACE at any given time collectively may not exceed $625 million. 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 and the federal funds effective rate plus 0.5% or (ii) the prevailing Eurodollar rate, plus a margin that varies according to the credit rating of the borrower. 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 $150 million. Any swingline loan must be repaid by the borrower within seven days of receipt thereof.

The facility commitment expiration date is May 5, 2012, with each company having the right to elect to have 100% of the principal balance of the loans outstanding on the expiration date continued as non-revolving term loans for a period of one year from such expiration date.

The facility is intended to serve primarily as a source of liquidity to support the commercial paper programs of the respective companies. The companies are also permitted to use the facility to borrow funds for general corporate purposes and issue letters of credit. 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 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 excludes from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) a restriction on sales or other dispositions of assets, other than certain sales and dispositions, 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 absence of a material adverse change in the borrower’s business, property and results of operations or financial condition is not a condition to the availability of credit under the facility. The facility does not include any rating triggers.

On October 15, 2010, a $400 million unsecured credit facility maintained by PHI expired. To replace this facility, PHI, on October 27, 2010, entered into two bi-lateral 364 day unsecured credit agreements totaling $200 million. Under each of the credit agreements, PHI has access to revolving and floating rate loans over the terms of the agreements. Neither agreement provides for the issuance of letters of credit. The interest rate payable on funds borrowed is at PHI’s election, based on either (a) the prevailing Eurodollar rate plus 2.0% or (b) the highest of (i) the prevailing prime rate, (ii) the federal funds effective rate plus 0.5%, or (iii) the one-month Eurodollar rate plus 1.0%, plus a margin of 1.0%. In order to obtain loans under either of the agreements, PHI must be in compliance with the same covenants and conditions that it is required to satisfy for utilization of its existing $1.5 billion credit facility. The absence of a material adverse change in PHI’s business, property and results of operations or financial condition is not a condition to the availability of credit under either agreement. Neither agreement includes any rating triggers.

The $1.5 billion credit facility and the two bi-lateral credit agreements are referred to herein collectively as PHI’s “primary credit facilities.” As of December 31, 2010, each borrower was in compliance with the covenants of each of the primary credit facilities.

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On November 2, 2010, PHI’s $50 million bi-lateral credit agreement with The Bank of Nova Scotia expired. Both the $400 million PHI facility that expired in October 2010 and this agreement were established to provide additional liquidity and collateral support for Pepco Energy Services’ retail energy supply business and for the operations of Conectiv Energy. Based on the progress toward winding down the retail energy supply business and disposing of the Conectiv Energy segment, the level of liquidity and collateral needed to support these businesses has decreased. As a result, PHI has been able to reduce the total amount of its credit facility needs by $250 million.

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.

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) agreed to supply 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 are being 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, 2010 and 2009, approximately $8 million and $16 million, respectively, of the fees have been amortized and reflected in interest expense. As the retail electric and natural gas supply businesses are wound down, Pepco Energy Services’ collateral requirements will be further reduced.

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In relation to its retail energy supply business being wound down, Pepco Energy Services in the ordinary course of business, had 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 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, 2010, Pepco Energy Services had posted net cash collateral of $117 million and letters of credit of $113 million. At December 31, 2009, Pepco Energy Services had posted net cash collateral of $123 million and letters of credit of $157 million.

At December 31, 2010 and 2009, the amount of cash, plus borrowing capacity under the primary credit facilities available to meet the future liquidity needs of Pepco Energy Services and Conectiv Energy totaled $728 million and $820 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.

Provision for Consolidated Income Taxes – Continuing Operations

	For the Year Ended December 31,
	2010			2009			2008
	(millions of dollars)
Current Tax Benefit
Federal	$	(270	)	$	(160	)	$	(78	)
State and local		(50	)		(32	)		(21	)
Total Current Tax Benefit		(320	)		(192	)		(99	)
Deferred Tax Expense (Benefit)
Federal		300			261			147
State and local		34			39			46
Investment tax credits		(3	)		(4	)		(4	)
Total Deferred Tax Expense		331			296			189
Total Consolidated Income Tax Expense Related to Continuing Operations	$	11		$	104		$	90

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Reconciliation of Consolidated Income Tax Expense – Continuing Operations

	For the Year Ended December 31,
	2010					2009					2008
	(millions of dollars)
Income tax at Federal statutory rate	$	52		35.0	%	$	114		35.0	%	$	96		35.0	%
Increases (decreases) resulting from
Depreciation		(3	)	(2.0	)%		6		1.8	%		5		1.8	%
State income taxes, net of Federal effect		—		—			19		5.7	%		22		8.0	%
State tax benefits related to prior years’ asset dispositions		—		—			(13	)	(4.0	)%		(3	)	(1.0	)%
Cross-border energy lease investments		(5	)	(3.3	)%		(6	)	(1.7	)%		(1	)	(0.2	)%
Change in estimates and interest related to uncertain and effectively settled tax positions		(6	)	(4.0	)%		(1	)	(0.4	)%		(10	)	(3.6	)%
Tax credits		(4	)	(2.7	)%		(4	)	(1.2	)%		(4	)	(1.5	)%
Deferred tax basis adjustments		(3	)	(2.0	)%		(4	)	(1.2	)%		(6	)	(2.2	)%
Reversal of valuation allowances		(8	)	(5.3	)%		—		—			—		—
Change in state deferred tax balances as a result of restructuring		(6	)	(4.0	)%		—		—			—		—
Other, net		(6	)	(4.4	)%		(7	)	(2.2	)%		(9	)	(3.3	)%
Consolidated Income Tax Expense Related to Continuing Operations	$	11		7.3	%	$	104		31.8	%	$	90		33.0	%

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 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 has recalculated the estimated interest due for the tax years 1996 to 2002. The revised estimate has resulted in the reversal of $15 million (after-tax) of estimated interest due to the IRS. This reversal has been recorded as an income tax benefit in the fourth quarter of 2010 and is subject to adjustment when the IRS finalizes its calculation of the amount due. Offsetting this 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.

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 (RAR) 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 RAR. 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.

During 2008, Pepco Holdings completed an analysis of its current and deferred income tax accounts and, as a result, recorded an $8 million net credit to income tax expense in 2008, which is primarily included in “Other, net” in the reconciliation provided above. In conjunction with the analysis, Pepco Holdings also identified a $1 million adjustment of its current and deferred income tax accounts that related to pre-acquisition tax contingencies associated with the Conectiv acquisition in 2002, which was recorded as an increase in goodwill. Also identified as part of the analysis were new uncertain tax positions under FASB guidance on income taxes (ASC 740) (primarily representing overpayments of income taxes in previously filed tax returns) that resulted in the recording of after-tax net interest income of $4 million, which is included as a reduction of income tax expense.

During 2008, Pepco Holdings recorded after-tax net interest income of $13 million under FASB guidance on income taxes (ASC 740) primarily related to the reversal of previously accrued interest payable resulting from a tentative settlement on the capitalization of certain overhead costs with the IRS, and a claim made with the IRS related to the tax reporting for fuel over- and under-recoveries. This amount was offset by $7 million in after-tax interest expense related to the change in assumptions regarding the estimated timing of the tax benefits on cross-border energy lease investments.

Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits

	2010			2009			2008
	(millions of dollars)
Beginning balance as of January 1,	$	246		$	255		$	275
Tax positions related to current year:
Additions		150			(1	)		2
Reductions		—			(2	)		—
Tax positions related to prior years:
Additions		35			77			196
Reductions		(36	)		(83	)		(209	)
Settlements		—			—			(9	)
Ending balance as of December 31,	$	395		$	246		$	255

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, 2010 included $21 million that, if recognized, would lower the effective tax rate.

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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, 2010, 2009 and 2008, PHI recognized $2 million of pre-tax interest income ($1 million after-tax), $5 million of pre-tax interest income ($3 million after-tax), and $17 million of pre-tax interest income ($10 million after-tax), respectively, as a component of income tax expense related to continuing operations. As of December 31, 2010, 2009 and 2008, PHI had $12 million, $13 million and $16 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, 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. As a result of the final determination of these years, PHI has filed amended state returns requesting $18 million in refunds which are subject to review by the various states. If accepted by the states, PHI could reduce its state tax expense by an estimated $3 million.

Components of Consolidated Deferred Tax Liabilities (Assets)

	At December 31,
	2010			2009
	(millions of dollars)
Deferred Tax Liabilities (Assets)
Depreciation and other basis differences related to plant and equipment	$	1,680		$	1,813
Goodwill and fair value adjustments		(30	)		(100	)
Deferred electric service and electric restructuring liabilities		154			173
Finance and operating leases		816			748
Federal and state net operating losses		(46	)		(148	)
Valuation allowances on state net operating losses		21			36
Pension and other postretirement benefits		70			133
Deferred taxes on amounts to be collected through future rates		43			42
Other		(83	)		(229	)
Total Deferred Tax Liabilities, Net		2,625			2,468
Deferred tax assets included in Current Assets		90			126
Deferred tax liabilities included in Other Current Liabilities		(1	)		6
Total Consolidated Deferred Tax Liabilities, Net Non-Current	$	2,714		$	2,600

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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 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 (ITC) for property placed in service after December 31, 1985, except for certain transition property. ITC 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.

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 $427 million, $358 million and $347 million for the years ended December 31, 2010, 2009 and 2008, respectively, related to the Power Delivery business, which are recoverable through rates.

	2010		2009		2008
	(millions of dollars)
Gross Receipts/Delivery	$	145	$	142	$	146
Property		70		68		64
County Fuel and Energy		154		94		90
Environmental, Use and Other		65		64		55
Total	$	434	$	368	$	355

(13) NONCONTROLLING INTEREST

The outstanding preferred stock issued by subsidiaries of PHI as of December 31, 2010 and 2009 consisted of the following series of serial preferred stock issued by ACE. The shares of each of the series are redeemable solely at the option of the issuer. On January 26, 2011, ACE issued notes of redemption for all of its outstanding cumulative preferred stock at the redemption prices indicated in the table below. The redemptions will occur on February 25, 2011.

	Redemption Price		Shares Outstanding				December 31,
			2010		2009		2010		2009
							(millions of dollars)
4.0% Series of 1944, $100 per share par value	$	105.50		24,268		24,268	$	2	$	2
4.35% Series of 1949, $100 per share par value	$	101.00		2,942		2,942		—		—
4.35% Series of 1953, $100 per share par value	$	101.00		1,680		1,680		—		—
4.10% Series of 1954, $100 per share par value	$	101.00		20,504		20,504		2		2
4.75% Series of 1958, $100 per share par value	$	101.00		8,631		8,631		1		1
5.0% Series of 1960, $100 per share par value	$	100.00		4,120		4,120		1		1
Total Preferred Stock of Subsidiaries				62,145		62,145	$	6	$	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, key employees and directors 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, stock options, performance units, stock appreciation rights 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, 2010, 2009, and 2008 was as follows:

	2010		2009		2008
	(millions of dollars)
Stock options	$	—	$	—	$	—
Restricted stock awards		5		5		16
Total stock compensation expense	$	5	$	5	$	16

During 2008, PHI identified an error in the accounting for certain of its restricted stock awards granted under the LTIP that resulted in an understatement of stock-based compensation expense in 2006 and 2007. This error was corrected in 2008, resulting in an increase in stock-based compensation expense for the year ended December 31, 2008 of $9 million.

No material amount of stock compensation expense was capitalized for the years ended December 31, 2010, 2009 and 2008.

Restricted Stock Awards

Description of awards

A number of programs have been established under the LTIP involving the issuance of restricted stock awards, including awards of performance-based restricted stock units, time-based restricted stock, retention stock and the Conectiv performance accelerated restricted stock (Conectiv PARS). A summary of each of these programs is as follows:

• Under the performance-based restricted stock program, performance criteria are selected and measured over a three-year period. Depending on the extent to which the performance criteria are satisfied, the participants are eligible to earn shares of common stock over the performance period, ranging from 0% to 200% of the target award, and dividends accrued thereon.

• Time-based restricted stock award opportunities have a requisite service period of three years and participants have the right to receive dividends on the shares during the vesting period.

• In connection with the acquisition of Conectiv by Pepco in 2002, Conectiv 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 shares 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 2010 activity for non-vested restricted stock and performance-based restricted stock unit awards is summarized below:

	Number of Shares			Total Number  of Shares			Weighted Average Grant Date Fair Value
Balance at January 1, 2010
Time-based restricted stock		233,058					$	20.72
Performance-based restricted stock units		499,893						22.21
Other (a)		3,606						27.73
Total					736,557
Granted during 2010
Time-based restricted stock		161,166						16.55
Performance-based restricted stock units		322,156						20.11
Total					483,322
Vested during 2010
Time-based restricted stock		(49,642	)					25.56
Performance-based restricted stock units		(141,023	)					25.55
Other (a)		(3,606	)					27.73
Total					(194,271	)
Forfeited during 2010
Time-based restricted stock		(28,388	)					17.18
Performance-based restricted stock units		(94,143	)					19.16
Total					(122,531	)
Balance at December 31, 2010
Time-based restricted stock		316,194						18.15
Performance-based restricted stock units		586,883						20.75
Other (a)		—						—
Total					903,077

(a) Includes share activity under the Conectiv PARS and retention awards.

Grants included in the table above reflect 2010 grants of performance-based restricted stock units and time-based restricted stock. PHI recognizes compensation expense related to performance-based restricted stock awards and time-based restricted stock 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 for each of the years ended December 31, 2010, 2009 and 2008:

	2010		2009		2008
Weighted average grant-date fair value of each performance-based restricted stock unit granted during the year	$	20.11	$	17.51	$	25.36
Weighted average grant-date fair value of each award of time-based restricted stock granted during the year	$	16.55	$	17.18	$	25.36

As of December 31, 2010, there was approximately $7 million of unrecognized compensation cost (net of estimated forfeitures) related to non-vested restricted stock awards and restricted stock unit awards granted under the LTIP. PHI expects to recognize the costs 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 ten years from the date of grant. No options have been granted 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, 2010 is summarized below:

	Number of Options			Weighted Average Exercise Price			Weighted Average Remaining Contractual Term (Years)		Aggregate Intrinsic Value
Outstanding at January 1, 2010		346,504		$	22.09			1.51
Options granted		—			—			—
Options exercised		(11,538	)		13.08			—
Options forfeited or expired		(54,700	)		22.90			—
Outstanding at December 31, 2010		280,266			22.30			0.70		—
Exercisable at December 31, 2010		280,266			22.30	(a)		0.70		—

(a) The range of exercise prices is $19.03 to $24.59

Total intrinsic value and tax benefits recognized for stock options exercised in 2010, 2009 and 2008 were immaterial.

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. All deferrals are settled in cash. The amount deferred by directors for each of the years ended December 31, 2010, 2009 and 2008 was not material.

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Compensation expense recognized in respect of dividends and the increase in fair value for each of the years ended December 31, 2010, 2009 and 2008 was not material. The deferred compensation balance under this program was approximately $1 million at December 31, 2010 and 2009.

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 existing and future preferred stock, 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 and DPL have no 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 $1,059 million and $1,268 million of retained earnings free of restrictions at December 31, 2010 and 2009, 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	2010		2009		2008
	(millions of dollars)
Pepco	$	115	$	—	$	89
DPL		23		28		52
ACE		35		64		46
Total	$	173	$	92	$	187

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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,
	2010			2009		2008
	(millions of dollars, except per share data)
Income (Numerator):
Net income from continuing operations	$	139		$	223	$	183
Net (loss) income from discontinued operations		(107	)		12		117
Net income	$	32		$	235	$	300
Shares (Denominator) (in millions):
Weighted average shares outstanding for basic computation:
Average shares outstanding		224			221		204
Adjustment to shares outstanding		—			—		—
Weighted Average Shares Outstanding for Computation of Basic Earnings Per Share of Common Stock		224			221		204
Net effect of potentially dilutive shares (a)		—			—		—
Weighted Average Shares Outstanding for Computation of Diluted Earnings Per Share of Common Stock		224			221		204
Basic and diluted earnings per share of common stock from continuing operations	$	0.62		$	1.01	$	0.90
Basic and diluted (loss) earnings per share of common stock from discontinued operations		(0.48	)		0.05		0.57
Basic and diluted earnings per share	$	0.14		$	1.06	$	1.47

(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 280,266, 334,966 and 171,000 for the years ended December 31, 2010, 2009 and 2008, 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, 2 million and 1 million new shares were issued and sold under the DRP in 2010, 2009 and 2008, respectively.

Pepco Holdings Common Stock Reserved and Unissued

The following table presents Pepco Holdings’ common stock reserved and unissued at December 31, 2010:

Name of Plan	Number of Shares
DRP		5,011,862
Conectiv Incentive Compensation Plan (a)		1,175,619
Potomac Electric Power Company Long-Term Incentive Plan (a)		327,059
Pepco Holdings Long-Term Incentive Plan		7,927,210
Pepco Holdings Non-Management Directors Compensation Plan		471,562
Pepco Holdings Retirement Savings Plan		1,956,107
Total		16,869,419

(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 the Power Delivery business to hedge commodity price risk, as well as by PHI, from time to time, to hedge interest rate risk.

Pepco Energy Services employs 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 delivery 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 accounts for some of its futures and swap contracts as cash flow hedges of forecasted transactions. 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. Forward contracts that meet the requirements for normal purchase and normal sale accounting are accounted for using accrual accounting.

In the Power Delivery business, DPL uses derivative instruments in the form of forward contracts, futures, swaps, and exchange-traded and over-the-counter options primarily to reduce gas commodity price volatility and limit its customers’ exposure to increases in the market price of gas. DPL also manages commodity risk with physical natural gas and capacity contracts that 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 based on the fuel adjustment clause approved by the DPSC.

PHI and its subsidiaries also use derivative instruments from time to time to mitigate the effects of fluctuating interest rates on debt incurred 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 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. In connection with the July 2010 debt tender offers described in Note (11), “Debt,” $15 million of these pre-tax losses ($9 million after-tax) was reclassified to income as a loss on extinguishment of debt during the third quarter of 2010.

The tables below identify the balance sheet location and fair values of derivative instruments as of December 31, 2010 and 2009:

	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	)

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	As of December 31, 2009
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)	$	100		$	54		$	154		$	(132	)	$	22
Derivative Assets (non-current assets)		44			21			65			(49	)		16
Total Derivative Assets		144			75			219			(181	)		38
Derivative Liabilities (current liabilities)		(234	)		(70	)		(304	)		237			(67	)
Derivative Liabilities (non-current liabilities)		(88	)		(35	)		(123	)		69			(54	)
Total Derivative Liabilities		(322	)		(105	)		(427	)		306			(121	)
Net Derivative (Liability) Asset	$	(178	)	$	(30	)	$	(208	)	$	125		$	(83	)

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, 2010		December 31, 2009
	(millions of dollars)
Cash collateral pledged to counterparties with the right to reclaim (a)	$	122	$	125

(a) Includes cash deposits on commodity brokerage accounts

As of December 31, 2010 and 2009, 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, representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness, are recognized in income. This information for the activity during the years ended December 31, 2010, 2009 and 2008 is provided in the tables below:

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	Years Ended December 31,
	2010			2009			2008
	(millions of dollars)
Amount of net pre-tax loss arising during the period included in accumulated other comprehensive loss	$	(100	)	$	(129	)	$	(210	)
Amount of net pre-tax loss (gain) reclassified into income:
Effective portion:
Fuel and Purchased Energy		135			164			(8	)
Ineffective portion: (a)
Revenue		—			2			—
Total net pre-tax loss (gain) reclassified into income		135			166			(8	)
Net pre-tax gain (loss) on commodity derivatives included in other comprehensive loss	$	35		$	37		$	(218	)

(a) Included in the above table is a loss of $2 million and $1 million for the years ended December 31, 2009 and 2008, respectively, which were reclassified from AOCL to income because the forecasted hedged transactions were deemed probable not to occur. For the year ended December 31, 2010, there were no amounts reclassified from AOCL to income because the forecasted hedged transaction was deemed probable not to occur.

As of December 31, 2010 and 2009, Pepco Energy Services had the following types and volumes of energy commodity contracts employed as cash flow hedges of forecasted purchases and forecasted sales.

	Quantities
Commodity	December 31, 2010		December 31, 2009
Forecasted Purchases Hedges
Natural gas (One Million British Thermal Units (MMBtu))		8,597,106		54,477,500
Electricity (Megawatt hours (MWh))		2,677,640		9,708,919
Electric capacity (MW-Days)		34,730		—
Forecasted Sales Hedges
Electricity (MWh)		2,517,200		7,322,535

Power Delivery

As described above, 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 based on the fuel adjustment clause approved by the DPSC. The following table indicates the amounts deferred as regulatory assets or liabilities and the location in the consolidated statements of income of amounts reclassified to income through the fuel adjustment clause for the years ended December 31, 2010, 2009 and 2008:

	For the Year Ended December 31,
	2010			2009			2008
	(millions of dollars)
Net Gain (Loss) Deferred as a Regulatory Asset or Liability	$	5		$	21		$	(29	)
Net Loss Reclassified from Regulatory Asset or Liability to Fuel and Purchased Energy Expense		(12	)		(39	)		(6	)

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As of December 31, 2010 and 2009, DPL had the following outstanding commodity forward contracts that were entered into to hedge forecasted transactions:

	Quantities
Commodity	December 31, 2010		December 31, 2009
Forecasted Purchases Hedges:
Natural Gas (MMBtu)		1,670,000		5,695,000

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, 2010 and 2009. Cash flow hedges are marked to market on the balance sheet with corresponding adjustments to AOCL. The data in the 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:

	As of December 31, 2010
Contracts	Accumulated Other Comprehensive Loss After-tax (a)		Portion Expected to be Reclassified to Income during the Next 12 Months		Maximum Term
	(millions of dollars)
Energy Commodity (b)	$	78	$	48		41 months
Interest Rate		11		1		260 months
Total	$	89	$	49

(a) AOCL on PHI’s consolidated balance sheet as of December 31, 2010, includes a $17 million balance related to minimum pension liability. This balance is not included in this table as the minimum pension liability is not a cash flow hedge.

(b) The unrealized derivative losses recorded in AOCL are largely offset by forecasted natural gas and electricity physical purchases for delivery to retail customers that are in gain positions and subject to accrual accounting. These forward purchase contracts are exempted from mark-to-market accounting because they either qualify as normal purchases under FASB guidance on derivatives and hedging or they are not derivative contracts. Under accrual accounting, no asset is recorded on the balance sheet for these contracts, and the purchase cost is not recognized until the period of delivery.

Contracts	As of December 31, 2009				Maximum Term
	Accumulated Other Comprehensive Loss After-tax (a)		Portion Expected to be Reclassified to Income during the Next 12 Months
	(millions of dollars)
Energy Commodity (b)	$	99	$	58		53 months
Interest Rate		22		3		272 months
Total	$	121	$	61

(a) AOCL on PHI’s consolidated balance sheet as of December 31, 2009, includes a $17 million balance related to minimum pension liability and a $103 million balance related to Conectiv Energy. These balances are not included in this table as the minimum pension liability is not a cash flow hedge and Conectiv Energy is reported as a discontinued operation.

(b) The unrealized derivative losses recorded in AOCL are largely offset by forecasted natural gas and electricity physical purchases for delivery to retail customers that are in gain positions and subject to accrual accounting. These forward purchase contracts are exempted from mark-to-market accounting because they either qualify as normal purchases under FASB guidance on derivatives and hedging or they are not derivative contracts. Under accrual accounting, no asset is recorded on the balance sheet for these contracts, and the purchase cost is not recognized until the period of delivery.

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Other Derivative Activity

Pepco Energy Services

Pepco Energy Services holds certain derivatives that do not qualify as hedges. Under FASB guidance on derivatives and hedging, 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, 2010, 2009 and 2008, the amount of the derivative gain (loss) for Pepco Energy Services recognized in income is provided in the table below:

	For the Year Ended December 31, 2010								For the Year Ended December 31, 2009								For the Year Ended December 31, 2008
	Revenue			Fuel and Purchased Energy Expense		Total			Revenue			Fuel and Purchased Energy Expense		Total			Revenue			Fuel and Purchased Energy Expense		Total
	(millions of dollars)
Realized mark-to-market gains (losses)	$	2		$	—	$	2		$	(2	)	$	—	$	(2	)	$	1		$	—	$	1
Unrealized mark-to-market (losses) gains		(3	)		—		(3	)		(2	)		—		(2	)		(2	)		—		(2	)
Total net mark-to-market (losses) gains	$	(1	)	$	—	$	(1	)	$	(4	)	$	—	$	(4	)	$	(1	)	$	—	$	(1	)

As of December 31, 2010 and 2009, Pepco Energy Services had the following net outstanding commodity forward contract volumes and net position on derivatives that did not qualify for hedge accounting:

	December 31, 2010				December 31, 2009
Commodity	Quantity		Net Position		Quantity		Net Position
Financial transmission rights (MWh)		381,215		Long		532,556		Long
Electric Capacity (MW-Days)		2,265		Short		—		—
Electricity (MWh)		1,455,800		Short		—		—
Natural gas (MMBtu)		45,889,486		Short		—		—

Power Delivery

DPL holds certain derivatives that do not qualify as hedges. These derivatives are recorded at fair value on the balance sheet with the gain or loss for the change in fair value recorded in income. In accordance with FASB guidance on regulated operations, offsetting regulatory assets or regulatory liabilities are recorded on the balance sheet and the recognition of the gain or recovery of the loss is deferred because of the DPSC fuel adjustment clause. For the years ended December 31, 2010, 2009 and 2008, the amount of the derivative gain (loss) recognized in the consolidated statements of income is provided in the table below by line item:

	For the Year Ended December 31,
	2010			2009			2008
	(millions of dollars)
Gain (Loss) Deferred as a Regulatory Asset or Liability	$	6		$	(8	)	$	(13	)
Loss Reclassified from Regulatory Asset or Liability to Fuel and Purchased Energy Expense		(26	)		(11	)		(1	)

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As of December 31, 2010 and 2009, DPL had the following net outstanding natural gas commodity forward contracts that did not qualify for hedge accounting:

	December 31, 2010				December 31, 2009
Commodity	Quantity		Net Position		Quantity		Net Position
Natural Gas (MMBtu)		7,827,635		Long		10,442,546		Long

Contingent Credit Risk Features

The primary contracts used by Pepco Energy Services and Power Delivery 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 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, 2010, and 2009 was $156 million and $303 million, respectively. As of those dates, PHI had posted cash collateral of zero and $6 million, respectively, in the normal course of business against the gross derivative liability resulting in a net liability of $156 million and $297 million, respectively, before giving effect to offsetting transactions that are encompassed within master netting agreements that would reduce this amount. PHI’s net settlement amount in the event of a downgrade of PHI and DPL below “investment grade” as of December 31, 2010 and 2009, would have been approximately $176 million and $183 million, respectively, after taking into consideration the master netting agreements. The offsetting transactions or collateral that would reduce PHI’s obligation to the net settlement amount include derivatives and normal purchase and normal sale contracts in a gain position as well as letters of credit already posted as collateral.

PHI’s primary sources for posting cash collateral or letters of credit are its credit facilities. At December 31, 2010 and 2009, 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 $1.2 billion and $1.4 billion, respectively, of which $728 million and $820 million, respectively, was available to Pepco Energy Services.

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(16) FAIR VALUE DISCLOSURES

Fair Value of Assets and Liabilities Excluding Issued Debt and Equity Instruments

PHI has adopted FASB guidance on fair value measurement and disclosures (ASC 820) which 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 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 derivative instruments primarily consist of electricity derivatives at December 31, 2010. Level 2 power swaps are priced at liquid trading hub prices or valued using the liquid hub prices plus a congestion adder that is calculated using historical regression analysis.

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. The underlying assets of these life insurance policies consist of short-term cash equivalents and fixed income securities that are priced using observable market data. 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. Some non-standard assumptions are used in their forward valuation to adjust for the pricing; otherwise, most of the options follow NYMEX valuation. A few of the options have no significant NYMEX components and have to be priced using internal volatility assumptions.

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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, 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 assets and liabilities held for sale) that were accounted for at fair value on a recurring basis as of December 31, 2010 and 2009. 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, 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 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 Service’s retail energy supply business.

(d) Level 1 instruments represent wholesale gas futures and swaps that are used mainly as part of Pepco Energy Service’s 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, 2009
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Derivative instruments (a)
Electricity (b)	$	21	$	—	$	21	$	—
Cash equivalents
Treasury Fund		36		36		—		—
Other		1		1		—		—
Executive deferred compensation plan assets
Money Market Funds		13		13		—		—
Life Insurance Contracts		62		—		43		19
	$	133	$	50	$	64	$	19
LIABILITIES
Derivative instruments (a)
Electricity (b)	$	116	$	—	$	116	$	—
Natural Gas (c)		113		84		—		29
Executive deferred compensation plan liabilities
Life Insurance Contracts		32		—		32		—
	$	261	$	84	$	148	$	29

(a) The fair value of derivative assets and liabilities reflect netting by counterparty before the impact of collateral.

(b) Represents wholesale electricity futures and swaps that are used mainly as part of Pepco Energy Service’s retail energy supply business.

(c) Level 1 instruments represent wholesale gas futures and swaps that are used mainly as part of Pepco Energy Service’s 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, 2010 and 2009 are shown below:

	Year Ended December 31, 2010
	Natural Gas			Life Insurance Contracts
	(millions of dollars)
Beginning balance as of January 1, 2010	$	(29	)	$	19
Total gains or (losses) (realized and unrealized):
Included in income		—			3
Included in accumulated other comprehensive loss		—			—
Included in regulatory liabilities		(16	)		—
Purchases and issuances		—			(3	)
Settlements		22			—
Transfers in (out) of Level 3		—			—
Ending balance as of December 31, 2010	$	(23	)	$	19

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	Year Ended December 31, 2009
	Natural Gas			Life Insurance Contracts
	(millions of dollars)
Beginning balance as of January 1, 2009	$	(24	)	$	18
Total gains or (losses) (realized and unrealized):
Included in income		—			4
Included in accumulated other comprehensive loss		—			—
Included in regulatory liabilities		(18	)		—
Purchases and issuances		—			(3	)
Settlements		13			—
Transfers in (out) of Level 3		—			—
Ending balance as of December 31, 2009	$	(29	)	$	19

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,
	2010		2009
	(millions of dollars)
Total gains included in income for the period	$	3	$	4
Change in unrealized gains relating to assets still held at reporting date	$	3	$	4

Fair Value of Debt and Equity Instruments

The estimated fair values of PHI’s issued debt and equity instruments at December 31, 2010 and 2009 are shown below:

	December 31, 2010				December 31, 2009
	(millions of dollars)
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	3,665	$	4,045	$	4,969	$	5,350
Transition Bonds issued by ACE Funding		367		406		402		427
Long-Term Project Funding		19		19		20		20
Redeemable Serial Preferred Stock		6		5		6		4

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The fair value of Long-Term Debt issued by PHI and its utility subsidiaries was based on actual trade prices as of December 31, 2010 and 2009. Where trade prices were not available, bid prices obtained from brokers or a discounted cash flow model were used to estimate fair value. The fair values of Transition Bonds issued by ACE Funding, including amounts due within one year, were derived based on bid prices obtained from brokers 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

Regulatory and Other Matters

Proceeds from Settlement of Mirant Bankruptcy Claims

In 2007, Pepco received proceeds from the settlement of its Mirant Corporation (Mirant) bankruptcy claims relating to the Panda PPA. In September 2008, Pepco transferred the Panda PPA to an unaffiliated third party, along with a payment to the third party of a portion of the settlement proceeds. 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 Panda PPA. 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 remaining after the transfer of the Panda PPA. 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.

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.

On May 18, 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, increases the aggregate amount Pepco is required to distribute to customers, pursuant to the sharing formula, by approximately $11 million. On June 17, 2010, Pepco filed an application for reconsideration of the DCPSC’s order, contesting (i) approximately $5 million of the total of $6 million in disallowances and (ii) approximately $4 million of the $5 million in interest to be credited to customers (reflecting a difference in the period of time over which interest was calculated as well as the balance to

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which interest would be applied). On July 16, 2010, the DCPSC denied Pepco’s application for reconsideration. On September 7, 2010, Pepco filed an appeal of the DCPSC’s decision with the District of Columbia Court of Appeals. PHI recognized an expense of $11 million for the year ended December 31, 2010 corresponding to the disallowed items. The appeal is still pending.

Maryland Public Service Commission Reliability Investigation

In August 2010, following the major storm events that occurred in July and August 2010, the MPSC initiated a proceeding for the purpose of investigating the reliability of the Pepco distribution system and the quality of distribution service Pepco is providing its customers. On February 10, 2011, the MPSC issued a notice expanding the scope of issues on which it requested testimony to include suggested remedies for the MPSC to consider imposing if the MPSC finds that Pepco has failed to meet its public service obligations. The possible remedies identified in the notice were the imposition of civil penalties, changes in the manner of Pepco’s operations, modification of Pepco’s service territory and revocation of Pepco’s authority to exercise its public utility franchise. The MPSC has retained an independent consultant to review and make recommendations regarding the reliability of Pepco’s distribution system and the quality of its service. The independent consultant’s report is due March 4, 2011. The MPSC has scheduled hearings on this matter to occur in mid-June 2011. While Pepco intends to cooperate fully with the MPSC in its efforts to ensure that the electric service provided by Pepco to its Maryland customers is reliable, it intends to oppose vigorously any effort of the MPSC to impose any sanctions of the types specified in the February 10, 2011 notice. Although Pepco believes that it has a strong factual and legal basis to oppose such sanctions, it cannot predict the outcome of this proceeding.

Rate Proceedings

Over the last several years, PHI’s utility subsidiaries have proposed the adoption of mechanisms to decouple retail distribution revenue from the amount of power delivered to retail customers. To date:

• A BSA has been approved and implemented for both Pepco and DPL electric service in Maryland and for Pepco electric service in the District of Columbia. The MPSC has initiated a proceeding to review how the BSA operates in Maryland to recover revenues lost as a result of major storm outages (as discussed below).

• A modified fixed variable rate design (MFVRD) has been approved in concept for DPL electric service in Delaware, but has been deferred by the DPSC as described below.

• A MFVRD has been approved in concept for DPL natural gas service in Delaware, but DPL anticipates that it will be deferred by the DPSC consistent with its treatment in the electric base rate case.

• A BSA is pending for ACE 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 BSA increases rates if actual distribution revenues fall below the approved level and decreases rates if actual distribution revenues are above the approved level. The result is that, over time, the utility collects its authorized revenues for distribution service. As a consequence, a BSA “decouples” distribution revenue from unit sales consumption and ties the growth in distribution revenues to the growth in the number of customers. Some advantages of the BSA are that it (i) eliminates revenue fluctuations due to weather and changes in customer usage patterns and, therefore, provides for more predictable distribution revenues that are better aligned with costs, (ii) provides for more reliable fixed-cost recovery, (iii) tends to stabilize customers’ delivery bills, and (iv) removes any disincentives for the regulated utilities to promote energy efficiency

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programs for their customers, because it breaks the link between overall sales volumes and distribution revenues. 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

DPL makes an annual GCR filing with the DPSC for the purpose of allowing DPL to recover 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 gas costs. In October 2010, the DPSC issued an order placing 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. If the DPSC does not accept DPL’s proposal, the full adjustment would result in an increase of 6.9% in the GCR.

In September 2009, DPL submitted an application to the DPSC to increase its electric distribution base rates. The filing, as revised in March 2010, sought approval of an annual rate increase of approximately $26.2 million, assuming approval of the implementation of the MFVRD, based on a requested return on equity (ROE) of 10.75%. As permitted by Delaware law, DPL placed an increase of approximately $2.5 million annually into effect, on a temporary basis, in November 2009, and the remainder of approximately $23.7 million of requested increase went into effect on April 19, 2010, in each case subject to refund and pending final DPSC approval. In June 2010, DPL lowered the requested annual rate increase to approximately $24.2 million. On January 18, 2011, the DPSC approved a rate increase of approximately $16.4 million, based on an ROE of 10.00%. In early 2011, DPL will refund to customers the excess of the billed amounts over the DPSC approved increase. Consideration of the MFVRD has been deferred pending the development of an education plan for customers and workshops that are open to parties and the public for the purpose of developing a proposed implementation plan for the MFVRD.

On July 2, 2010, DPL submitted an application with the DPSC to increase its natural gas distribution base rates. As subsequently amended on September 10, 2010 (to replace test year data for the twelve months ended June 2010 with the actual data) and on October 11, 2010 (based on an update to DPL’s natural gas advanced metering infrastructure implementation schedule), the filing seeks approval of an annual rate increase of approximately $10.2 million, assuming the implementation of the MFVRD, based on a requested ROE of 11.00%. As permitted by Delaware law, DPL placed an annual increase of approximately $2.5 million annually into effect, on a temporary basis, on August 31, 2010, and the remainder of approximately $7.7 million of the requested increase went into effect on February 2, 2011, in each case subject to refund and pending final DPSC approval. Previously, in June 2009, DPL filed an application requesting approval for the implementation of the MFVRD for gas distribution rates. DPL anticipates that the DPSC will follow the same implementation approach it is following with respect to DPL’s MFVRD proposal for electric service, discussed above. The DPSC decision is still pending.

Maryland

In December 2009, Pepco filed an electric distribution base rate case in Maryland. The filing sought approval of an annual rate increase of approximately $40 million, based on a requested ROE of 10.75%. During the course of the proceeding, Pepco reduced its request to approximately $28.2 million. On August 6, 2010, the MPSC issued an order approving a rate increase of approximately $7.8 million, based on an ROE of 9.83%. On September 2, 2010, Pepco filed with the MPSC a motion for reconsideration of the following issues, which in the aggregate would increase annual revenue by approximately $8.5 million: (1) denial of inclusion in rate base of certain reliability plant investments, which occurred subsequent to the test period but before the rate effective period; (2) denial of Pepco’s request to increase depreciation rates to reflect a corrected formula relating to the cost of removal expenses; and (3) imposition of imputed cost savings to partially offset the costs of Pepco’s enhanced vegetation management program. Maryland law and regulation do not mandate a response time from the MPSC regarding Pepco’s motion and, therefore, it is not known when the MPSC will issue a ruling on the motion.

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On December 21, 2010, DPL filed an application with the MPSC to increase its electric distribution base rates by $17.8 million annually, based on an ROE of 10.75%. On December 28, 2010, the MPSC, consistent with its typical practice, issued an order suspending the proposed rate increase request for an initial period of 150 days from January 20, 2011 pending investigation by the MPSC.

On February 1, 2011, the MPSC initiated proceedings for Pepco and DPL, as well as unaffiliated utilities such as Baltimore Gas & Electric Company and Southern Maryland Electric Cooperative, for the purpose of reviewing how the BSA operates to recover revenues lost as a result of major storm outages. In its orders initiating the proceedings, the MPSC expressed concern that the utilities’ respective BSAs may be allowing them to recover revenues lost during extended outages, therefore unintentionally eliminating an incentive to restore service quickly. The MPSC will consider whether the BSA, as currently in effect, is appropriate, whether the calculations or determinant factors for calculating the BSA should be modified, and if so, what modifications should be made. A similar adjustment was included in the BSA for Pepco in the District of Columbia when the BSA was approved by the DCPSC.

Retained Environmental Exposures from the Sale of the Conectiv Energy Wholesale Power Generation Business

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 Purchase Agreement dated April 20, 2010, between PHI and Calpine (the Purchase Agreement), 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. PHI has accrued approximately $4 million as of December 31, 2010 for the ISRA-required remediation activities at the nine generating facility sites.

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. As of December 31, 2010, PHI had accrued approximately $4 million for landfill closure and monitoring.

In orders issued in 2007, the New Jersey Department of Environmental Protection (NJDEP) assessed penalties against Conectiv Energy in an aggregate amount of approximately $2 million, based on NJDEP’s contention that Conectiv Energy’s Deepwater generating facility exceeded the maximum allowable hourly heat input limits during certain periods in calendar years 2004, 2005 and 2006. Conectiv Energy has appealed the NJDEP orders imposing these penalties to the New Jersey Office of Administrative Law. PHI is continuing to prosecute this appeal and, under the Purchase Agreement, has agreed to indemnify Calpine for any monetary penalties, fines or assessments arising out of the NJDEP orders.

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

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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.

Since the initial filings in 1993, additional individual suits have been filed against Pepco, and significant numbers of cases have been dismissed. As a result of two motions to dismiss, numerous hearings and meetings and one motion for summary judgment, Pepco has had approximately 400 of these cases successfully dismissed with prejudice, either voluntarily by the plaintiff or by the court. As of December 31, 2010, there are approximately 180 cases still pending against Pepco in the State Courts of Maryland, of which approximately 90 cases were filed after December 19, 2000, and were tendered to 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; however, based on information and relevant circumstances known at this time, neither PHI nor Pepco believes these suits will have a material adverse effect on its financial condition, results of operations or cash flows. However, 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 Litigation

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. 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. 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 would be included by each company in its respective cost of service for ratemaking purposes.

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 with respect to the site. If liable, ACE would be responsible for reimbursing EPA for clean-up costs incurred and to be incurred by the agency 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 cost for future response measures will be approximately $6 million. ACE understands 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

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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.

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, 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 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 are entitled to the recyclable material exemption from CERCLA liability. At this time Pepco cannot predict how EPA will proceed regarding this matter, or what portion, if any, of the Peck Iron and Metal site response costs EPA would seek to recover from Pepco. In a 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.

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. With the court’s permission, the plaintiffs filed amended complaints in September 2009. ACE, DPL and Pepco, as part of a group of defendants, filed a motion to dismiss in October 2009. In a March 24, 2010 order, the court denied the defendants’ motion to dismiss. Although it is too early in the process to characterize the magnitude of the potential liability at this site, PHI does not believe that any of its three utility subsidiaries had extensive business transactions, if any, with the Ward Transformer site.

Benning Road Site. On September 21, 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 (PCBs) 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 as a result of the study, to clean up the facility) is not reached. In a letter dated October 8, 2010, the Office of the Attorney General of the District of Columbia notified PHI of the District’s intent to sue Pepco Energy Services and Pepco under the Resource Conservation and Recovery Act for abatement of conditions related to their historical activities, including the discharge of PCBs at the Benning Road site. The District’s letter also stated that EPA will list the Benning Road site on the NPL if contamination at the facility is not addressed in a timely manner and that if Pepco fails to meet the District’s deadline, the District intends to sue Pepco and Pepco Energy Services in federal court to seek a scientific study to identify the nature of conditions at the Benning Road site, abatement of conditions, compensation for natural resource damages and reimbursement of DDOE’s related costs. Pepco and Pepco Energy Services entered into a consent decree with DDOE, filed in the federal District Court on February 1, 2011, which will require the PHI entities to conduct a remedial investigation and feasibility study (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

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action for the Benning Road site and for the Anacostia River sediment associated with the site. The consent decree will not be final until the DDOE files a motion requesting the Court to enter the consent decree, after a public comment period ends on March 7, 2011, and the Court enters it. In light of the consent decree, Pepco and Pepco Energy Services anticipate that EPA will refrain from listing the Benning Road facility on the NPL. PHI preliminarily estimates that costs for performing the RI/FS will be approximately $600,000 and the remediation costs will be approximately $13 million. PHI recognized expense of $14 million in the fourth quarter of 2010 with respect to this matter and, as of December 31, 2010, has $14 million accrued for this matter.

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 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 at the site as the owner of a facility on which a hazardous substance has been deposited. ACE currently is engaged in settlement negotiations with NJDEP and EPA to resolve its alleged liability at the site by donating property to NJDEP and by making a payment in an amount to be determined. Costs incurred by ACE to resolve this matter are not expected to be material.

Appeal of New Jersey Flood Hazard Regulations. In November 2007, NJDEP adopted amendments to the agency’s regulations under the Flood Hazard Area Control Act (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. In November 2008, ACE filed an appeal of these regulations with the Appellate Division of the Superior Court of New Jersey. The grounds for ACE’s appeal include the lack of administrative record justification for the FHACA regulations and conflict between the FHACA regulations and other state and federal regulations and standards for maintenance of electric power transmission and distribution facilities. The matter was argued before the Appellate Division on January 3, 2011 and the decision of the court is pending.

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. Based on updated engineering estimates obtained in the second quarter of 2010, DPL accrued an additional liability in the amount of approximately $4 million in 2010. As of December 31, 2010, DPL’s accrual for expected future costs to fulfill its obligations under the consent agreement was approximately $5 million, of which approximately $1 million is expected to be incurred in 2011.

PHI’s Cross-Border Energy Lease Investments

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. PHI’s current annual tax benefits from these eight cross-border energy lease investments are approximately $59 million. As of December 31, 2010, PHI’s equity investment in its cross-border energy leases was approximately $1.4 billion. From January 1, 2001, the earliest year that remains open to audit, to December 31, 2010, PHI has derived approximately $575 million in federal and state income tax benefits from the depreciation and interest deductions in excess of rental income with respect to these cross-border energy lease investments.

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In 2005, the Treasury Department and IRS issued Notice 2005-13 identifying sale-leaseback transactions with certain attributes entered into with tax-indifferent parties as tax avoidance transactions, and the IRS announced its intention to disallow the associated tax benefits claimed by the investors in these transactions. 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 RARs issued in June 2006 and in March 2009 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 filed tax protests in August 2006 and May 2009, respectively, in connection with the audit of the 2001-2002 and the 2003-2005 income tax returns. Both of these protests were forwarded to the IRS Appeals Office. On August 9, 2010, PHI signed an IRS settlement statement with respect to the 2001-2002 income tax returns agreeing to the IRS’s disallowance of depreciation and interest deductions in excess of rental income with respect to the cross-border energy lease investments, but reserving its right to file timely refund claims in which it would contest the disallowances. The Joint Tax Committee approved the settlement on November 10, 2010. In January 2011, PHI paid $74 million of additional tax associated with the disallowed deductions from the cross-border energy lease investment for 2001 and 2002, plus penalties of $1 million and any interest associated with the disallowed deductions once the IRS assesses the amount due. PHI currently intends to file a refund claim for the additional taxes and related interest and penalties incurred by reason of the disallowed deductions, which it expects the IRS to deny, and if so, PHI intends to pursue litigation in the U.S. Court of Federal Claims against the IRS to defend its tax position and recover the tax payment, interest, and penalties. Absent a settlement, litigation against the IRS may take several years to resolve. The 2003-2005 case continues to be in process with the IRS Appeals Office.

At December 31, 2010 and 2009, PHI modified its tax cash flow assumptions under its cross-border energy lease investments for the periods 2010-2013 and 2010-2012, respectively, to reflect the anticipated timing of potential litigation with the IRS concerning the investments. As a result of the 2009 recalculation, PHI recorded a $2 million after-tax non-cash charge to earnings at December 31 2009, and recorded an additional $3 million in after-tax non-cash earnings during 2010 (as compared to the earnings that it would have recorded absent the 2009 recalculation). As a result of the 2010 recalculation, PHI recorded a $1 million after-tax non-cash charge to earnings at December 31, 2010.

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, 2010, it would be obligated to pay approximately $692 million in additional federal and state taxes and $133 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 mitigate the taxes due in the event of a total disallowance of tax benefits, PHI could, were it to so elect, choose to liquidate all or a portion of its cross-border energy lease portfolio, 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 entire portfolio would generate sufficient cash proceeds to cover the estimated $825 million in federal and state taxes and interest due as of December 31, 2010 (or an estimated $751 million after giving effect to the $74 million payment made in January 2011), in the event of a total disallowance of tax benefits and a recharacterization of the transactions 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.

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To the extent that PHI does not to 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 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

In December 2009, the Mayor of the District of Columbia approved legislation adopted by the City Council that imposes mandatory combined unitary business reporting beginning with tax year 2011, and revises the District’s related party expense disallowance beginning with tax year 2009. Because the City Council must still enact further legislation providing guidance on how to implement combined unitary business reporting before this provision is effective, PHI believes that the legislative process was not complete as of December 31, 2010, and, therefore, the effect of the legislation for combined unitary business tax reporting has not been accounted for as of December 31, 2010. However, because the City Council is not required to enact any further legislation in order for the provisions for the disallowance of related party transactions to become effective, PHI accrued approximately $500,000 of additional income tax expense during the first quarter of 2010.

The legislation does not define the term “unitary business” and does not specify how combined tax reporting would differ from PHI’s current consolidated tax reporting in the District of Columbia. However, based upon PHI’s interpretation of combined unitary business tax reporting in other taxing jurisdictions, the legislation would likely result in a change in PHI’s overall state income tax rate and, therefore, would likely require an adjustment to PHI’s net deferred income tax liabilities. Further, to the extent that the change in rate increases net deferred income tax liabilities, PHI must determine if these increased tax liabilities are probable of recovery in future rates. No timetable has been established by the City Council to enact the required further legislation and, therefore, it is uncertain as to when combined unitary reporting will be effective for PHI’s District of Columbia tax returns.

Management continues to analyze the impact that the unitary business tax reporting aspect of this legislation, if completed, may have on the financial position, results of operations and cash flows of PHI and its subsidiaries.

Third Party Guarantees, Indemnifications, and Off-Balance Sheet Arrangements

Pepco Holdings 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, 2010, Pepco Holdings and its subsidiaries were parties to a variety of agreements pursuant to which they were guarantors for standby letters of credit, performance residual value, and other commitments and obligations. The commitments and obligations, in millions of dollars, were as follows:

	Guarantor
	PHI		Pepco		DPL		ACE		Total
Energy marketing obligations of Conectiv Energy (a)	$	139	$	—	$	—	$	—	$	139
Energy procurement obligations of Pepco Energy Services (a)		243		—		—		—		243
Guarantees associated with disposal of Conectiv Energy assets (b)		25		—		—		—		25
Guaranteed lease residual values (c)		1		2		5		3		11
Total	$	408	$	2	$	5	$	3	$	418

(a) Pepco Holdings has contractual commitments for performance and related payments of Conectiv Energy and Pepco Energy Services to counterparties under routine energy sales and procurement obligations, including retail customer load obligations of Pepco Energy Services and requirements under ACE’s BGS contracts entered into by Conectiv Energy.

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(b) Represents a guarantee by Pepco Holdings in connection with a Conectiv Energy tolling agreement that remains in effect following the assignment of the tolling agreement to a third party. Pepco Holdings’ obligation declines each month through the second quarter of 2012.

(c) Subsidiaries of Pepco Holdings have guaranteed residual values in excess of fair value of certain equipment and fleet vehicles held through lease agreements. As of December 31, 2010, obligations under the guarantees were approximately $11 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, Pepco Holdings believes the likelihood of payments being required under the guarantees is remote.

Pepco Energy Services has entered into various energy savings guaranty contracts 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 will generate a specified amount of energy savings on an annual basis based on contractually established performance measures. The longest remaining term of the guarantees currently in effect is 15 years. On an annual basis, Pepco Energy Services undertakes a measurement and verification process to determine the amount of energy savings for the year and whether there is any shortfall in the annual energy savings compared to the guaranteed amount. 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. The liability for energy savings guaranty contracts has not changed significantly during the year ended December 31, 2010 and currently is less than $1 million. Pepco Energy Services did not make any significant payouts under the guarantees, and there was no significant change in guarantees issued or expired for the year ended December 31, 2010.

Pepco Holdings 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.

Dividends

On January 27, 2011, Pepco Holdings’ Board of Directors declared a dividend on common stock of 27 cents per share payable March 31, 2011, to shareholders of record on March 10, 2011.

Contractual Obligations

As of December 31, 2010, Pepco Holdings’ contractual obligations under non-derivative fuel and purchase power contracts were $922 million in 2011, $1,064 million in 2012 to 2013, $711 million in 2014 to 2015, and $2,916 million in 2016 and thereafter.

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(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, 2007	$	11		$	(29	)	$	(8	)	$	(26	)
Current year change		(131	)		4			(2	)		(129	)
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	)

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.

As of:	Commodity Derivatives			Treasury Lock		Other			Accumulated Other Comprehensive Loss
	(millions of dollars)
December 31, 2008	$	(87	)	$	1	$	(1	)(a)	$	(87	)
December 31, 2009	$	15		$	2	$	(5	)(a)	$	12
December 31, 2010	$	14		$	7	$	—	(a)	$	21

(a) Represents income tax expense on amortization of gains and losses for prior service costs.

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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.

	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.

	2009
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(millions, except per share amounts)
Total Operating Revenue	$	2,037		$	1,666		$	2,050		$	1,649		$	7,402
Total Operating Expenses (e)		1,896			1,522			1,815			1,521			6,754
Operating Income		141			144			235			128			648
Other Expenses		(78	)		(81	)		(80	)		(82	)		(321	)
Income From Continuing Operations Before Income Tax Expense		63			63			155			46			327
Income Tax Expense Related to Continuing Operations		22			24			51			7	(g)		104
Net Income From Continuing Operations		41			39			104	(f)		39			223
Income (Loss) From Discontinued Operations, net of taxes		4			(14	)		20			2			12
Net Income	$	45		$	25		$	124		$	41		$	235
Basic and Diluted Earnings Per Share of Common Stock
Earnings Per Share of Common Stock from Continuing Operations		0.19			0.18			0.47			0.17			1.01
Earnings (Loss) Per Share of Common Stock from Discontinued Operations		0.02			(0.07	)		0.09			0.01			0.05
Basic and Diluted Earnings Per Share of Common Stock		0.21			0.11			0.56			0.18			1.06
Cash Dividends Per Common Share		0.27			0.27			0.27			0.27			1.08

(e) Includes gains of $14 million ($8 million after-tax) and $26 million ($16 million after-tax) during the first and third quarters, respectively, related to settlement of Mirant bankruptcy claims.

(f) Includes benefit of $11 million net of fees related to a change in the Maryland state income tax reporting for the disposition of certain assets in prior years.

(g) Includes a $6 million benefit related to additional analysis of current and deferred income tax balances completed during the fourth quarter and a $2 million benefit related to the resolution of an uncertain state income tax position.

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(20) DISCONTINUED OPERATIONS

On April 20, 2010, the Board of Directors of PHI 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. In accordance with the plan, PHI on the same date entered into the Purchase Agreement with Calpine, under the terms of which, Calpine agreed to purchase Conectiv Energy’s wholesale power generation business.

On July 1, 2010, PHI completed the sale of its wholesale power generation business to Calpine. Under the terms of the Purchase Agreement, dated April 20, 2010, the $1.65 billion sales price was subject to several adjustments, including a $49 million payment for the value of the fuel inventory at the time of the closing and a $60 million reduction in the closing payment attributable to lower capital expenditures incurred by PHI than were anticipated at the time of execution of the Purchase Agreement for Conectiv Energy’s 565 megawatt combined cycle generating facility that is under construction (known as the Delta project) during the period from January 1, 2010 through the date of the closing. After giving effect to these and other adjustments, PHI received proceeds at the closing in the amount of approximately $1.64 billion.

As a result of the adoption of the plan of disposition, PHI commenced 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.

Operating Results

The operating results of Conectiv Energy for the years ended December 31, 2010, 2009 and 2008 are as follows:

	2010			2009		2008
	(millions of dollars)
Income from operations of discontinued operations, net of income tax expense	$	6		$	12	$	117
Net losses from dispositions of assets and businesses of discontinued operations, net of income taxes		(113	)		—		—
(Loss) income from discontinued operations, net of income taxes	$	(107	)	$	12	$	117

Income from operations of discontinued operations, net of income taxes, for the year ended December 31, 2010, 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 of $113 million 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 (which is 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 of $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.

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The estimated after-tax proceeds from the sale of the wholesale power generation business to Calpine and the liquidation of all of Conectiv Energy’s remaining assets and businesses, combined with the return of cash collateral posted under the contracts, total approximately $1.7 billion, with a related current income tax obligation of approximately $218 million.

Balance Sheet Information

Details of the assets and liabilities of Conectiv Energy held for sale at December 31, 2010 and 2009 are as follows:

	December 31, 2010			December 31, 2009
	(millions of dollars)
Current Assets
Cash and cash equivalents	$	1		$	2
Accounts receivable, less allowance for uncollectible accounts		81			194
Inventories		20			128
Derivative assets		3			21
Prepaid expenses and other		6			1
Total Current Assets		111			346
Investments And Other Assets
Derivative assets		4			27
Other		2			2
Total Investments and Other Assets		6			29
Property, Plant And Equipment
Property, plant and equipment		2			2,286
Accumulated depreciation		(2	)		(664	)
Net Property, Plant and Equipment		—			1,622
Current Liabilities
Accounts payable and accrued liabilities		40			138
Derivative liabilities		15			37
Other		7			16
Total Current Liabilities		62			191
Deferred Credits
Derivative liabilities		10			8
Other		—			11
Total Deferred Credits		10			19
Net Assets	$	45		$	1,787

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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 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.

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. Through June 30, 2010, Conectiv Energy sold electricity swaps, options and forward contracts to hedge price risk in connection with electric output from its generating facilities. Conectiv Energy accounts for most of its futures, swaps and certain forward contracts as cash flow hedges of forecasted transactions. Derivative contracts purchased or sold in excess of probable amounts of forecasted hedge transactions are marked-to-market through current earnings. All option contracts are marked-to-market through current earnings. Certain natural gas and oil futures and swaps have been used as fair value hedges to protect the value of natural gas transportation contracts and physical fuel inventory. Some forward contracts are accounted for using standard accrual accounting since these contracts meet the requirements for normal purchase and normal sale accounting.

The tables below identify the balance sheet location and fair values of Conectiv Energy’s derivative instruments as of December 31, 2010 and 2009:

	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 held for sale)	$	—	$	395		$	395		$	(392	)	$	3
Derivative Assets (non-current assets held for sale)		—		31			31			(27	)		4
Total Derivative Assets		—		426			426			(419	)		7
Derivative Liabilities (current liabilities associated with assets held for sale)		—		(472	)		(472	)		457			(15	)
Derivative Liabilities (non-current liabilities associated with assets held for sale)		—		(37	)		(37	)		27			(10	)
Total Derivative Liabilities		—		(509	)		(509	)		484			(25	)
Net Derivative (Liability) Asset	$	—	$	(83	)	$	(83	)	$	65		$	(18	)

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	As of December 31, 2009
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 held for sale)	$	52		$	574		$	626		$	(605	)	$	21
Derivative Assets (non-current assets held for sale)		23			44			67			(40	)		27
Total Derivative Assets		75			618			693			(645	)		48
Derivative Liabilities (current liabilities associated with assets held for sale)		(236	)		(575	)		(811	)		774			(37	)
Derivative Liabilities (non-current liabilities associated with assets held for sale)		(14	)		(27	)		(41	)		33			(8	)
Total Derivative Liabilities		(250	)		(602	)		(852	)		807			(45	)
Net Derivative (Liability) Asset	$	(175	)	$	16		$	(159	)	$	162		$	3

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, 2010		December 31, 2009
	(millions of dollars)
Cash collateral pledged to counterparties with the right to reclaim	$	65	$	168
Cash collateral received from counterparties with the obligation to return		—		(6	)

As of December 31, 2010 and 2009, all cash collateral pledged or received related to Conectiv Energy’s derivative instruments accounted for at fair value was entitled to offset under master netting agreements.

Derivatives Designated as Hedging Instruments

Cash Flow Hedges

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 representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current income. This information for the activity of Conectiv Energy during the years ended December 31, 2010, 2009 and 2008 is provided in the table below:

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	Years Ended December 31,
	2010			2009			2008
	(millions of dollars)
Amount of net pre-tax loss arising during the period included in other comprehensive loss	$	(73	)	$	(216	)	$	(105	)
Amount of net pre-tax (loss) gain reclassified into income:
Effective portion:
Loss from discontinued operations, net of income taxes		(164	)		(224	)		45
Ineffective portion:
Loss from discontinued operations net of income taxes (a)		(82	)		—			(3	)
Total net pre-tax (loss) gain reclassified into income		(246	)		(224	)		42
Net pre-tax gain (loss) on commodity derivatives included in other comprehensive loss	$	173		$	8		$	(147	)

(a) For the years ended December 31, 2010, 2009 and 2008, amounts of $86 million, $3 million and zero, respectively, were reclassified from AOCL to income because the forecasted transactions were deemed probable not to occur.

As of December 31, 2010, Conectiv Energy had no energy commodity contracts employed as cash flow hedges. As of December 31, 2009, Conectiv Energy had the following types and volumes of energy commodity contracts employed as cash flow hedges of forecasted purchases and forecasted sales.

	Quantities
Commodity	December 31, 2010		December 31, 2009
Forecasted Purchases Hedges
Coal (Tons)		—		325,000
Natural gas (MMBtu)		—		43,032,500
Electricity (MWh))		—		10,758,844
Heating oil (Barrels)		—		89,000
Forecasted Sales Hedges
Coal (Tons)		—		255,000
Natural gas (MMBtu)		—		3,859,643
Electricity (MWh)		—		5,701,472
Electric capacity (MW-Days)		—		203,640
Financial transmission rights (MWh)		—		48,014

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Cash Flow Hedges Included in Accumulated Other Comprehensive Loss

As of December 31, 2010, Conectiv Energy had no remaining AOCL. The tables below provide details regarding effective cash flow hedges of Conectiv Energy included in PHI’s consolidated balance sheet as of December 31, 2009. Cash flow hedges are marked to market on the balance sheet with corresponding adjustments to AOCL to the extent the hedges are effective. The data in the 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:

	Accumulated Other Comprehensive Loss After-tax (a)		Portion Expected to be Reclassified to Income during the Next 12 Months		Maximum Term
	(millions of dollars)
Energy Commodity Contracts as of December 31, 2010	$	—	$	—		—
Energy Commodity Contracts as of December 31, 2009 (a)	$	103	$	154		48 months

(a) The unrealized derivative losses recorded in AOCL were largely offset by forecasted natural gas and electricity physical purchases in gain positions that are subject to accrual accounting. These forward purchase contracts are exempted from mark-to-market accounting because they either qualify as normal purchases under FASB guidance on derivatives and hedging or they are not derivative contracts. Under accrual accounting, no asset is recorded on the balance sheet for these contracts, and the purchase cost is not recognized until the period of delivery.

Fair Value Hedges

In connection with its energy commodity activities, Conectiv Energy designates certain derivatives as fair value hedges. For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative as well as the offsetting gain or loss on the hedged item attributable to the hedged risk is recognized in current income. For the years ended December 31, 2010 and 2008, there was no such gain or loss recognized. For the year ended December 31, 2009, the net gains recognized in (Loss) income from discontinued operations, net of income taxes, was $1 million. As of December 31, 2010, Conectiv Energy had no outstanding commodity forward contract derivatives that were accounted for as fair value hedges of fuel inventory and natural gas transportation.

Other Derivative Activity

In connection with its energy commodity activities, Conectiv Energy holds certain derivatives that do not qualify as hedges. Under FASB guidance on derivatives and hedging, these derivatives are recorded at fair value on the balance sheet with changes in fair value recognized in income.

The amount 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, 2010, 2009 and 2008, is provided in the table below:

	For the Year Ended December 31,
	2010			2009			2008
	(millions of dollars)
Realized mark-to-market gains	$	26		$	47		$	57
Unrealized mark-to-market (losses) gains		(16	)		(57	)		24
Total net mark-to-market gains (losses)	$	10		$	(10	)	$	81

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As of December 31, 2010 and 2009, Conectiv Energy had the following net outstanding commodity forward contract volumes and net positions on derivatives that did not qualify for hedge accounting:

	December 31, 2010			December 31, 2009
Commodity	Quantity		Net Position	Quantity		Net Position
Coal (Tons)		—	—		60,000	Long
Natural gas (MMBtu)		450,000	Long		2,268,024	Long
Natural gas basis (MMBtu)		—	—		12,445,000	Long
Heating oil (Barrels)		64,000	Short		139,000	Short
Electricity (MWh)		1,200	Long		76,324	Long
Financial transmission rights (MWh)		702,358	Short		1,241,237	Short

Contingent Credit Risk Features

The primary contracts used by Conectiv Energy for derivative transactions are generally the same as those described in Note (15), “Derivative Instruments and Hedging Activities,” and include comparable provisions for mutual posting and administration of collateral security. 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 Conectiv Energy are usually guaranteed by PHI. If PHI’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 Conectiv Energy’s derivative liabilities, excluding the impact of offsetting transactions or collateral under master netting agreements, with credit risk-related contingent features on December 31, 2010 and 2009, was $117 million and $179 million, respectively. As of those dates, Conectiv Energy had posted cash collateral of $12 million and $17 million, respectively, in the normal course of business against the gross derivative liability resulting in a net liability of $105 million and $162 million, respectively, before giving effect to offsetting transactions that are encompassed within master netting agreements that would reduce this amount. Conectiv Energy’s net settlement amount in the event of a downgrade of PHI below “investment grade” as of December 31, 2010 and 2009, would have been an additional $58 million and $63 million, respectively, after taking into consideration the master netting agreements.

Depending on the contract terms, the collateral required to be posted by Conectiv Energy was of varying forms, including cash and letters of credit. As of December 31, 2010, Conectiv Energy had posted net cash collateral of $104 million and there were no outstanding letters of credit. At December 31, 2009, Conectiv Energy had posted net cash collateral of $240 million and letters of credit of $22 million. Of the approximately $104 million of net cash collateral outstanding at December 31, 2010, approximately $39 million represented deposits on commodity brokerage accounts and $65 million represented collateral pledged to counterparties with the right to reclaim. Of the approximately $240 million of net cash collateral outstanding at December 31, 2009, approximately $78 million represented deposits on commodity brokerage accounts and $162 million represented collateral pledged to counterparties with the right to reclaim.

On January 6, 2011, as part of its ongoing divestiture efforts, Conectiv Energy entered into a financial transaction with a third party under which Conectiv Energy transferred 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 derivative instruments at February 1, 2011 and an administrative fee of approximately $2 million that will be expensed in the first quarter of 2011. No additional material gain or loss will be recognized as a result of this transaction as the

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derivatives were previously marked to fair value through earnings in 2010. Approximately $68 million of collateral was returned to Conectiv Energy upon the closing of the transaction in January 2011. Approximately $11 million of the remaining $36 million in outstanding collateral will be returned to Conectiv Energy in connection with this transaction upon the novation of several over-the-counter transactions.

All of the remaining posted cash collateral, other than the $11 million referred to above, is held by the PJM and ISO New England Inc. regional transmission organizations and will be returned within the next several months upon completion of a reconciliation process.

PHI’s primary sources for posting cash collateral or letters of credit are its credit facilities. At December 31, 2010 and 2009, the amount of cash plus borrowing capacity under the primary credit facilities available to meet the future liquidity needs of Conectiv Energy and Pepco Energy Services, totaled $728 million and $820 million, respectively.

Fair Value Disclosures

Conectiv Energy has adopted FASB guidance on fair value measurement and disclosures (ASC 820) that established a framework for measuring fair value and expanded disclosures about fair value measurement that is further described in Note (16), “Fair Value Disclosures.”

As of December 31, 2010 level 2 instruments primarily consist of electricity derivatives. Power swaps are priced at liquid trading hub prices or valued using the liquid hub prices plus a congestion adder that is calculated using historical regression analysis. Natural gas futures and swaps are valued using broker quotes in liquid markets and other observable pricing data.

The level 3 instruments with the most significant amount of fair value at December 31, 2010 are electricity derivatives. The majority of Conectiv Energy’s pricing information for these level 3 valuations was obtained from a third party pricing system used widely throughout the energy industry.

The following tables set forth, by level within the fair value hierarchy, Conectiv Energy’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2010 and 2009:

	Fair Value Measurements at December 31, 2010
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Derivative instruments (a)
Electricity (c)	$	7	$	—	$	4	$	3
	$	7	$	—	$	4	$	3
LIABILITIES
Derivative instruments (a)
Natural Gas (b)	$	35	$	10	$	25	$	—
Electricity (c)		55		—		55		—
	$	90	$	10	$	80	$	—

(a) The fair value of derivative assets and liabilities reflect netting by counterparty before the impact of collateral.

(b) Represents wholesale gas futures and swaps that were used mainly as part of Conectiv Energy’s generation strategy.

(c) Represents power swaps (Level 2) and long-dated power swaps (Level 3) that were part of Conectiv Energy’s power output generation strategy and PJM Load service strategy.

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	Fair Value Measurements at December 31, 2009
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Derivative instruments (a)
Coal (b)	$	8	$	—	$	8	$	—
Natural Gas (c)		4		—		4		—
Electricity (d)		34		—		4		30
Capacity (e)		8		8		—		—
	$	54	$	8	$	16	$	30
LIABILITIES
Derivative instruments (a)
Coal (b)	$	6	$	—	$	6	$	—
Natural Gas (c)		74		52		22		—
Electricity (d)		126		—		123		3
Oil (f)		5		4		1		—
Capacity (e)		2		2		—		—
	$	213	$	58	$	152	$	3

(a) The fair value of derivative assets and liabilities reflect netting by counterparty before the impact of collateral.

(b) Assets represent forward coal transactions and liabilities represent over-the-counter swaps that were part of fuel input for Conectiv Energy’s generation strategy.

(c) Represents wholesale gas futures and swaps that were used mainly as part of Conectiv Energy’s generation strategy.

(d) Represents power swaps (Level 2) and long-dated power swaps (Level 3) that were mainly part of Conectiv Energy’s power output generation strategy and PJM Load service strategy.

(e) Assets represent capacity swaps which were used in Conectiv Energy’s power output generation strategy and PJM Load service strategy.

(f) Represents oil futures that were mainly part of Conectiv Energy’s fuel input generation strategy.

Reconciliations of the beginning and ending balances of Conectiv Energy’s fair value measurements using significant unobservable inputs (Level 3) for the years ended December 31, 2010 and 2009 are shown below:

	For the Year  Ended December 31,
	2010			2009
	(millions of dollars)
Beginning balance as of January 1	$	27		$	2
Total gains or (losses) (realized and unrealized)
Included in loss from discontinued operations, net of taxes (a)		81			18
Included in accumulated other comprehensive loss		(13	)		25
Purchases and issuances		—			—
Settlements		(92	)		(11	)
Transfers in (out) of Level 3		—			(7	)
Ending balance as of December 31	$	3		$	27

(a) As of December 31, 2010, $3 million of the $81 million gain is unrealized. As of December 31, 2009, $12 million of the $18 million gain is unrealized.

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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 is repositioning itself as a regulated transmission and distribution company. In connection with this repositioning, 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 that are allocated to its operating segments. This review has resulted in the adoption of a restructuring plan. PHI began implementing the plan during the third quarter, identifying 164 employee positions that were to be eliminated during the fourth quarter of 2010. The plan also focuses on identifying additional cost reduction opportunities through process improvements and operational efficiencies.

In connection with the restructuring plan, PHI recorded a pre-tax restructuring charge of $30 million for the year ended December 31, 2010 related to severance, pension, and health and welfare benefits for employee terminations. 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 has been allocated to PHI’s operating segments and has been reflected as a separate line item in the consolidated statements of income. The amount of restructuring charge recorded by segment is as follows:

	For The Year Ended December 31, 2010
	(millions of dollars)
	Power Delivery			Pepco Energy Services		Other Non- Regulated		Corporate and Other		PHI Consolidated
Employee severance, pension, and health and welfare benefits	$	29		$	—	$	—	$	1	$	30
Total restructuring charge	$	29		$	—	$	—	$	1	$	30
Reconciliations of PHI’s accrued restructuring charges for the year ended December 31, 2010 are as follows:
	Year Ended December 31, 2010
	(millions of dollars)
	Power Delivery (a)			Pepco Energy Services		Other Non- Regulated		Corporate and Other		PHI Consolidated
Beginning balance as of January 1, 2010	$	—		$	—	$	—	$	—	$	—
Restructuring charge		29			—		—		1		30
Cash payments		(1	)		—		—		—		(1	)
Ending balance as of December 31, 2010	$	28		$	—	$	—	$	1	$	29

(a) Excludes restructuring accrual recorded in 1999 related to the expense of the excess of the net present value of water-supply capacity leased from Merrill Creek reservoir over the electric generating facility’s requirements. The remaining accrual of $16 million as of December 31, 2010 is being amortized over the remaining term of the lease, which expires in 2032.

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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) under the Securities Exchange Act of 1934, as amended. 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 assessed its internal control over financial reporting as of December 31, 2010 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, 2010.

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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, 2010 and December 31, 2009, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2010 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 24, 2011

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POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF INCOME

For the Year Ended December 31,	2010			2009			2008
	(millions of dollars)
Operating Revenue	$	2,288		$	2,231		$	2,322
Operating Expenses
Purchased energy		1,152			1,223			1,335
Other operation and maintenance		354			328			302
Restructuring charge		15			—			—
Depreciation and amortization		162			145			141
Other taxes		364			302			288
Effect of divestiture-related claims		11			(40	)		—
Total Operating Expenses		2,058			1,958			2,066
Operating Income		230			273			256
Other Income (Expenses)
Interest and dividend income		1			1			9
Interest expense		(98	)		(100	)		(93	)
Other income		12			9			10
Other expenses		—			(1	)		(2	)
Total Other Expenses		(85	)		(91	)		(76	)
Income Before Income Tax Expense		145			182			180
Income Tax Expense		37			76			64
Net Income	$	108		$	106		$	116

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

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POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

ASSETS	December 31, 2010			December 31, 2009
	(millions of dollars)
CURRENT ASSETS
Cash and cash equivalents	$	88		$	213
Restricted cash equivalents		—			1
Accounts receivable, less allowance for uncollectible accounts of $20 million and $17 million, respectively		373			354
Inventories		44			43
Prepayments of income taxes		95			79
Income taxes receivable		37			—
Prepaid expenses and other		34			48
Total Current Assets		671			738
INVESTMENTS AND OTHER ASSETS
Regulatory assets		191			166
Prepaid pension expense		274			295
Investment in trust		25			25
Income taxes receivable		34			64
Other		57			70
Total Investments and Other Assets		581			620
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		6,185			5,865
Accumulated depreciation		(2,609	)		(2,481	)
Net Property, Plant and Equipment		3,576			3,384
TOTAL ASSETS	$	4,828		$	4,742

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

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POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

LIABILITIES AND EQUITY	December 31, 2010		December 31, 2009
	(millions of dollars, except shares)
CURRENT LIABILITIES
Current portion of long-term debt	$	—	$	16
Accounts payable and accrued liabilities		194		154
Accounts payable due to associated companies		75		111
Capital lease obligations due within one year		8		7
Taxes accrued		62		37
Interest accrued		18		18
Other		119		124
Total Current Liabilities		476		467
DEFERRED CREDITS
Regulatory liabilities		147		145
Deferred income taxes, net		958		893
Investment tax credits		7		8
Other postretirement benefit obligations		67		71
Income taxes payable		3		5
Liabilities and accrued interest related to uncertain tax positions		52		29
Other		64		58
Total Deferred Credits		1,298		1,209
LONG-TERM LIABILITIES
Long-term debt		1,540		1,539
Capital lease obligations		86		92
Total Long-Term Liabilities		1,626		1,631
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		723		730
Total Equity		1,428		1,435
TOTAL LIABILITIES AND EQUITY	$	4,828	$	4,742

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,	2010			2009			2008
	(millions of dollars)
OPERATING ACTIVITIES
Net Income	$	108		$	106		$	116
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		162			145			141
Effect of divestiture-related claims		11			(40	)		—
Changes in restricted cash equivalents related to Mirant settlement		—			102			315
Deferred income taxes		74			122			185
Investment tax credit adjustments		(2	)		(2	)		(2	)
Changes in:
Accounts receivable		(15	)		23			(33	)
Inventories		(1	)		2			—
Prepaid expenses		3			(9	)		(2	)
Regulatory assets and liabilities, net		(34	)		(66	)		(309	)
Accounts payable and accrued liabilities		15			4			(8	)
Pension contributions		—			(170	)		—
Prepaid pension expense, excluding contributions		22			17			10
Taxes accrued		6			77			(174	)
Interest accrued		(1	)		(1	)		2
Other assets and liabilities		11			21			(18	)
Net Cash From Operating Activities		359			331			223
INVESTING ACTIVITIES
Investment in property, plant and equipment		(359	)		(288	)		(275	)
DOE capital reimbursement awards received		11			—			—
Changes in restricted cash equivalents		1			(1	)		1
Net other investing activities		3			(1	)		1
Net Cash Used By Investing Activities		(344	)		(290	)		(273	)
FINANCING ACTIVITIES
Dividends paid to Parent		(115	)		—			(89	)
Capital contribution from Parent		—			94			78
Issuances of long-term debt		—			110			500
Reacquisition of long-term debt		(16	)		(50	)		(238	)
(Repayments) issuances of short-term debt, net		—			(125	)		(55	)
Net other financing activities		(9	)		(3	)		(19	)
Net Cash (Used by) From Financing Activities		(140	)		26			177
Net (Decrease) Increase in Cash and Cash Equivalents		(125	)		67			127
Cash and Cash Equivalents at Beginning of Year		213			146			19
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	88		$	213		$	146
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for interest (net of capitalized interest of $4 million, $4 million and $2 million, respectively)	$	94		$	97		$	87
Cash (received) paid for income taxes		(20	)		(126	)		60

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 on Stock		Retained Earnings			Total
(millions of dollars, except shares)	Shares		Par Value
BALANCE, DECEMBER 31, 2007		100	$	—	$	533	$	597		$	1,130
Net Income		—		—		—		116			116
Dividends on common stock		—		—		—		(89	)		(89	)
Capital contribution from Parent		—		—		78		—			78
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

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, 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 the loss is determined to be probable and is reasonably estimable.

Restructuring Charges

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.

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. In the first half of 2010, Pepco recorded an increase in transmission service revenue of $6 million that was then estimated to be collected over the 2010-2011 service year for costs incurred in the 2009 service year. In the fourth quarter of 2010, Pepco recorded an immaterial decrease in transmission service revenue that it

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estimates will be reflected as a reduction in transmission service rates for the 2011-2012 service year based on costs incurred during the first seven months of the 2010 service year. Pepco will update its estimate of the reduction in transmission service revenue for the 2011-2012 service year in the first and second quarters of 2011 as it progresses toward the completion of the 2010-2011 service year and final cost information from the 2010-2011 service year becomes available. In the second quarter of 2011, Pepco expects to record a true-up as part of its updated transmission service rates that are submitted to FERC.

Revenue Recognition

Pepco recognizes revenue upon distribution of electricity to its customers, including amounts for services rendered, but not yet billed (unbilled revenue). Pepco recorded amounts for unbilled revenue of $95 million and $89 million as of December 31, 2010 and 2009, respectively. 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 judgements 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 revenues. Accruals for 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 $333 million, $254 million and $241 million for the years ended December 31, 2010, 2009 and 2008, 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.

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.

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Deferred income tax assets and liabilities represent the tax effects of temporary differences between the financial statement basis and tax basis of existing assets and liabilities and they are measured using presently enacted tax rates. The portion of Pepco’s deferred tax liability applicable to its utility operations that has not been recovered from utility customers represents income taxes recoverable in the future and is included in Regulatory assets on the balance sheets. See Note (6), “Regulatory Assets and Regulatory Liabilities,” 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 under or over payments 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

Due to a variable element in the pricing structure of Pepco’s power purchase agreement with Panda-Brandywine, L.P. (Panda) entered into in 1991, pursuant to which Pepco was obligated to purchase from Panda 230 megawatts of capacity and energy annually through 2021 (the Panda PPA), Pepco potentially assumed the variability in the operations of the plants related to the Panda PPA and therefore had a variable interest in the entity.

During the third quarter of 2008, Pepco transferred the Panda PPA to Sempra Energy Trading LLP. Net purchase activities under the Panda PPA for the year ended December 31, 2008 were approximately $59 million.

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).

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

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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 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, 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 (13) “Commitments and Contingencies – Regulatory and Other Matters – Rate 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.

Investment in Trust

Represents assets held in a trust for the benefit of participants in the Pepco Owned Life Insurance plan.

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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 2010, 2009, and 2008 for Pepco’s transmission and distribution system property were approximately 2.6%, 2.7%, and 2.7%, respectively.

In 2010, Pepco received an award from the U.S. Department of Energy (DOE) 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 $4 million, $4 million, and $2 million for the years ended December 31, 2010, 2009, and 2008, respectively.

Pepco recorded amounts for the equity component of AFUDC of $6 million, $3 million, and $3 million for the years ended December 31, 2010, 2009 and 2008, respectively.

Leasing Activities

Pepco’s lease transactions include office space, equipment, software and vehicles. In accordance with FASB guidance on leases (ASC 840), these leases are classified as either operating leases or capital leases.

Operating Leases

An operating lease in which Pepco is the lessee generally results in a level income statement charge over the term of the lease, reflecting the rental payments required by the lease agreement. If rental payments are not made on a straight-line basis, Pepco’s policy is to recognize rent expense on a straight-line basis over the lease term unless another systematic and rational allocation basis is more representative of the time pattern in which the leased property is physically employed.

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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, 2010 and 2009, $122 million and $113 million of asset removal costs, respectively, are included in regulatory liabilities in the accompanying balance sheets.

Pension and Postretirement Benefit Plans

Pepco Holdings sponsors a non-contributory retirement plan that covers substantially all employees of Pepco (the PHI Retirement Plan) 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 $723 million and $730 million of retained earnings available for payment of common stock dividends at December 31, 2010 and 2009, 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:

Operating Expense

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).

During 2008, Pepco recorded adjustments to correct errors in Other operation and maintenance expenses for prior periods dating back to February 2005 during which (i) customer late payment fees were incorrectly recognized and (ii) stock-based compensation expense related to certain restricted stock awards granted under the Long-Term Incentive Plan was understated. These adjustments resulted in a total increase in Other operation and maintenance expenses of $6 million for the year ended December 31, 2008, all of which related to prior periods.

(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Transfers and Servicing (ASC 860)

The FASB issued new guidance that removes the concept of a qualifying special-purpose entity (QSPE) from the guidance on transfers and servicing and the QSPE scope exception in the guidance on consolidation. The new guidance also changes the requirements for derecognizing financial assets and requires additional disclosures about a transferor’s continuing involvement in transferred financial assets. The guidance was effective for transfers of financial assets occurring in fiscal periods beginning on January 1, 2010 for Pepco. The guidance did not have a material impact on PHI’s overall financial condition, results of operations, or cash flows.

Fair Value Measurement and Disclosures (ASC 820)

The FASB issued new disclosure requirements for recurring and non-recurring fair value measurements. The guidance, effective beginning with Pepco’s March 31, 2010 financial statements, requires the disaggregation of balance sheet items measured at fair value into subsets of balance sheet items based on the nature and risks of the items. The standard requires descriptions of pricing inputs and valuation methodologies for instruments with Level 2 or 3 valuation inputs. In addition, the standard requires information about any significant transfers of instruments between Level 1 and 2 valuation categories. These additional disclosures are included in Note (12), “Fair Value Disclosures.”

Consolidation of Variable Interest Entities (ASC 810)

The FASB issued new consolidation guidance regarding variable interest entities effective January 1, 2010 that eliminates the quantitative analysis requirement and adds new qualitative factors to determine whether consolidation is required. The new qualitative factors are applied on a quarterly basis to interests in variable interest entities. Under the new guidance, the holder of the interest with the power to direct the most significant activities of the entity and the right to receive benefits or absorb losses significant to the entity would consolidate. The new guidance retains the provision that allows entities created before December 31, 2003 to be scoped out from a consolidation assessment if exhaustive efforts are taken and there is insufficient information to determine whether there is a relationship with a variable interest entity or the primary beneficiary of a variable interest entity. This guidance did not have a material impact on Pepco’s overall financial condition, results of operations, or cash flows.

Subsequent Events (ASC 855)

The FASB issued new guidance that eliminates the requirement for Pepco to disclose the date through which it has evaluated subsequent events beginning with its March 31, 2010 financial statements.

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(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Fair Value Measurement and Disclosures (ASC 820)

The FASB issued new disclosure requirements that require the disaggregation of the Level 3 fair value measurement reconciliations into separate categories for significant purchases, sales, issuances, and settlements. This requirement is effective beginning with Pepco’s March 31, 2011 financial statements. Pepco is evaluating the impact of this new guidance on its financial statement footnote disclosures.

(5) SEGMENT INFORMATION

The company operates its business as one regulated utility segment, which includes all of its services as described above.

(6) REGULATORY ASSETS AND REGULATORY LIABILITIES

The components of Pepco’s regulatory asset and liability balances at December 31, 2010 and 2009 are as follows:

	2010		2009
	(millions of dollars)
Regulatory Assets
Deferred income taxes	$	45	$	40
Deferred energy supply costs		8		6
Deferred debt extinguishment costs (a)		33		36
Recoverable meter related costs (a)		15		—
Recoverable workers’ compensation and long-term disability costs		28		32
Other		62		52
Total Regulatory Assets	$	191	$	166
Regulatory Liabilities
Asset removal costs	$	122	$	113
Deferred income taxes due to customers		12		15
Deferred energy supply costs		12		16
Other		1		1
Total Regulatory Liabilities	$	147	$	145

(a) A return is generally earned on these deferrals.

A description for each category of regulatory assets and regulatory liabilities follows:

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.

Deferred Energy Supply Costs: The regulatory asset represents primarily deferred energy costs associated with a net under-recovery of Default Electricity Supply costs in the District of Columbia that are probable of recovery in rates. The regulatory liability represents deferred transmission and energy costs associated with a net over-recovery of Default Electricity Supply costs incurred in the District of Columbia and Maryland that will be refunded to customers.

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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.

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 (AMI) project.

Recoverable Workers’ Compensation and Long-Term Disability costs: Represents future recovery of pay as you go reserves. Quarterly adjustments are made to reflect the difference between claims paid and claims accrued during the quarter to bring the account back to a pay as you go basis. There is a monthly amortization of the transition obligation.

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.

Deferred Income Taxes Due to Customers: Represents the portions of deferred income tax liabilities applicable to Pepco’s utility operations that have not been reflected in current customer rates for which future payment to customers is probable. As temporary differences between the financial statement basis and tax basis of assets reverse, deferred recoverable income taxes are amortized.

Other: Represents miscellaneous regulatory liabilities.

(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.

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Capital lease assets recorded within Property, Plant and Equipment at December 31, 2010 and 2009 are comprised of the following:

	Original Cost		Accumulated Amortization		Net Book Value
	(millions of dollars)
At December 31, 2010
Transmission	$	76	$	29	$	47
Distribution		76		29		47
Other		3		3		—
Total	$	155	$	61	$	94
At December 31, 2009
Transmission	$	76	$	27	$	49
Distribution		76		26		50
Other		3		3		—
Total	$	155	$	56	$	99

The approximate annual commitments under capital leases are $15 million for each year 2011 through 2015, and $61 million thereafter.

Rental expense for operating leases was $4 million, $3 million and $4 million for the years ended December 31, 2010, 2009 and 2008, respectively.

Total future minimum operating lease payments for Pepco as of December 31, 2010 are $4 million in 2011, $4 million in 2012, $4 million in 2013, $3 million in 2014, $4 million in 2015, 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, 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
At December 31, 2009
Distribution	$	4,386	$	1,808	$	2,578
Transmission		858		358		500
Construction work in progress		175		—		175
Non-operating and other property		446		315		131
Total	$	5,865	$	2,481	$	3,384

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.

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(9) PENSION AND OTHER POSTRETIREMENT BENEFITS

Pepco accounts for its participation in the Pepco Holdings benefit plans as participation in a multi-employer plan. For 2010, 2009, and 2008, Pepco was responsible for $40 million, $38 million and $24 million, respectively, of the pension and other postretirement net periodic benefit cost incurred by Pepco Holdings. Pepco made discretionary, tax-deductible contributions of $170 million to the PHI Retirement Plan for the year ended December 31, 2009. No contributions were made for the years ended December 31, 2010 and 2008. In addition, Pepco made contributions of $10 million, $8 million, and $9 million, respectively, to the other postretirement benefit plans for the years ended December 31, 2010, 2009 and 2008. At December 31, 2010 and 2009, Pepco’s Prepaid pension expense of $274 million and $295 million, and Other postretirement benefit obligations of $67 million and $71 million, effectively represent assets and benefit obligations resulting from Pepco’s participation in the Pepco Holdings benefit plans.

(10) DEBT

Long-Term Debt

Long-term debt outstanding as of December 31, 2010 and 2009 is presented below.

Type of Debt	Interest Rate	Maturity		2010			2009
				(millions of dollars)
First Mortgage Bonds
	5.75%(a)		2010	$	—		$	16
	4.95%(a)(b)(c)		2013		200			200
	4.65%(a)(b)(c)		2014		175			175
	6.20%(a)(b)(c)		2022		110			110
	5.375%(a)		2024		38			38
	5.75%(a)(b)(c)		2034		100			100
	5.40%(a)(b)(c)		2035		175			175
	6.50%(a)(b)(c)		2037		500			500
	7.90%		2038		250			250
Total First Mortgage Bonds					1,548			1,564
Total long-term debt					1,548			1,564
Other long-term debt					1			—
Net unamortized discount					(9	)		(9	)
Current portion of long-term debt					—			(16	)
Total net long-term debt				$	1,540		$	1,539

(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.

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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, 2010, that will mature in each of 2011 through 2015 and thereafter is as follows: zero in 2011 and 2012, $200 million in 2013, $175 million in 2014, zero in 2015 and $1,173 million thereafter.

Pepco’s long-term debt is subject to certain covenants. As of December 31, 2010, 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. Pepco had no short-term debt outstanding at December 31, 2010 and 2009.

Commercial Paper

Pepco maintains an ongoing commercial paper program of up to $500 million. The commercial paper notes can be issued with maturities up to 270 days from the date of issue. The commercial paper program is backed by Pepco’s borrowing capacity under PHI’s $1.5 billion credit facility described below under the heading “Credit Facility.”

Pepco had no commercial paper outstanding at December 31, 2010 and 2009. Pepco did not issue commercial paper during 2010 and 2009.

Credit Facility

PHI, Pepco, Delmarva Power & Light Company (DPL) and Atlantic City Electric Company (ACE) maintain an unsecured credit facility to provide for their respective short-term liquidity needs. The aggregate borrowing limit under the facility is $1.5 billion, all or any portion of which may be used to obtain loans or to issue letters of credit. PHI’s credit limit under the facility is $875 million. The credit limit of each of Pepco, DPL and ACE is the lesser of $500 million and the maximum amount of debt the company is permitted to have outstanding by its regulatory authorities, except that the aggregate amount of credit used by Pepco, DPL and ACE at any given time collectively may not exceed $625 million. 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 and the federal funds effective rate plus 0.5%, or (ii) the prevailing Eurodollar rate, plus a margin that varies according to the credit rating of the borrower. 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 $150 million. Any swingline loan must be repaid by the borrower within seven days of receipt thereof.

The facility commitment expiration date is May 5, 2012, with each company having the right to elect to have 100% of the principal balance of the loans outstanding on the expiration date continued as non-revolving term loans for a period of one year from such expiration date.

The facility is intended to serve primarily as a source of liquidity to support the commercial paper programs of the respective companies. The companies are also permitted to use the facility to borrow funds for general corporate purposes and issue letters of credit. 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 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 excludes from the definition of total indebtedness certain trust preferred

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securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) a restriction on sales or other dispositions of assets, other than certain sales and dispositions, 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 absence of a material adverse change in the borrower’s business, property and results of operations or financial condition is not a condition to the availability of credit under the facility. The facility does not include any rating triggers. As of December 31, 2010, each borrower was in compliance with the covenants of the credit facility.

At December 31, 2010 and 2009, the amount of cash plus borrowing capacity under the PHI credit facilities available to meet the liquidity needs of PHI’s utility subsidiaries was $462 million and $582 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,
	2010			2009			2008
	(millions of dollars)
Current Tax Benefit
Federal	$	(28	)	$	(33	)	$	(94	)
State and local		(7	)		(11	)		(25	)
Total Current Tax Benefit		(35	)		(44	)		(119	)
Deferred Tax Expense (Benefit)
Federal		52			95			147
State and local		22			27			38
Investment tax credits		(2	)		(2	)		(2	)
Total Deferred Tax Expense		72			120			183
Total Income Tax Expense	$	37		$	76		$	64

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Reconciliation of Income Tax Expense

	For the Year Ended December 31,
	2010					2009					2008
	(millions of dollars)
Income tax at Federal statutory rate	$	51		35.0	%	$	64		35.0	%	$	63		35.0	%
Increases (decreases) resulting from
Depreciation		4		2.8	%		5		2.7	%		5		2.8	%
Asset removal costs		(3	)	(2.1	)%		(3	)	(1.6	)%		(4	)	(2.2	)%
State income taxes, net of federal effect		8		5.5	%		10		5.5	%		11		6.1	%
Software amortization		(4	)	(2.8	)%		2		1.1	%		2		1.1	%
Tax credits		(2	)	(1.4	)%		(2	)	(1.1	)%		(2	)	(1.1	)%
Change in estimates and interest related to uncertain and effectively settled tax positions		(11	)	(7.6	)%		4		2.2	%		(6	)	(3.3	)%
Interest on Maryland state income tax refund, net of Federal effect		—		—			—		—			(3	)	(1.7	)%
Other, net		(6	)	(3.9	)%		(4	)	(2.0	)%		(2	)	(1.1	)%
Income Tax Expense	$	37		25.5	%	$	76		41.8	%	$	64		35.6	%

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. 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 has recalculated the estimated interest due for the tax years 1996 to 2002. The revised estimate has 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, and is subject to adjustment when the IRS finalizes its calculation of the amount due. 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.

In March 2009, the IRS issued a Revenue Agent’s Report (RAR) 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 RAR.

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.

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During 2008, Pepco completed an analysis of its current and deferred income tax accounts and, as a result, recorded a $3 million net credit to income tax expense in 2008, which is primarily included in “Other” in the reconciliation provided above. In addition, during 2008, Pepco recorded after-tax net interest income of $5 million under FASB guidance on income taxes (ASC 740) primarily related to the reversal of previously accrued interest payable resulting from a favorable tentative settlement of the mixed service cost issue with the IRS, and after-tax interest income of $2 million for interest received in 2008 on the Maryland state tax refund.

Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits

	2010			2009			2008
	(millions of dollars)
Beginning balance as of January 1,	$	71		$	62		$	60
Tax positions related to current year:
Additions		110			—			1
Reductions		—			(2	)		—
Tax positions related to prior years:
Additions		24			45			38
Reductions		(15	)		(34	)		(37	)
Settlements		—			—			—
Ending balance as of December 31,	$	190		$	71		$	62

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, 2010, Pepco had $3 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, 2010, 2009 and 2008, Pepco recognized $27 million of pre-tax interest income ($16 million after-tax), $7 million of pre-tax interest expense ($4 million after-tax), and $8 million of pre-tax interest income ($5 million after-tax), respectively, as a component of income tax expense. As of December 31, 2010, 2009 and 2008, Pepco had accrued interest receivable of $8 million, accrued interest payable of $8 million and accrued interest payable of $4 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 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.

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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. If accepted by the states, Pepco could reduce its state tax expense by an estimated $3 million.

Components of Deferred Income Tax Liabilities (Assets)

	At December 31,
	2010		2009
	(millions of dollars)
Deferred Tax Liabilities (Assets)
Depreciation and other basis differences related to plant and equipment	$	803	$	765
Pension and other postretirement benefits		100		111
Deferred taxes on amounts to be collected through future rates		15		16
Federal and state net operating losses		—		(18	)
Other		27		(7	)
Total Deferred Tax Liabilities, Net		945		867
Deferred tax assets included in Other Current Assets		13		22
Deferred tax assets included in Other Current Liabilities		—		4
Total Deferred Tax Liabilities, Net - Non-Current	$	958	$	893

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, 2010 and 2009.

The Tax Reform Act of 1986 repealed the investment tax credit (ITC) for property placed in service after December 31, 1985, except for certain transition property. ITC previously earned on Pepco’s property continues to be amortized to income over the useful lives of the related property.

Other Taxes

Taxes other than income taxes for each year are shown below. These amounts are recoverable through rates.

	2010		2009		2008
	(millions of dollars)
Gross Receipts/Delivery	$	108	$	104	$	106
Property		42		41		38
County Fuel and Energy		154		94		90
Environmental, Use and Other		60		63		54
Total	$	364	$	302	$	288

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(12) FAIR VALUE DISCLOSURES

Fair Value of Assets and Liabilities Excluding Issued Debt and Equity Instruments

Pepco has adopted FASB guidance on fair value measurement and disclosures (ASC 820) which 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 their fair value is based on the fair value of the assets underlying the policies. The underlying assets of these life insurance policies consist of short-term cash equivalents and fixed income securities that are priced using observable market data. 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.

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, 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, 2010 and 2009. 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.

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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
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.
	Fair Value Measurements at December 31, 2009
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Executive deferred compensation plan assets
Money Market Funds	$	9	$	9	$	—	$	—
Life Insurance Contracts		55		—		37		18
	$	64	$	9	$	37	$	18
LIABILITIES
Executive deferred compensation plan liabilities
Life Insurance Contracts	$	13	$	—	$	13	$	—
	$	13	$	—	$	13	$	—

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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, 2010 and 2009 are shown below.

	Life Insurance Contracts
	Year Ended December 31,
	2010			2009
	(millions of dollars)
Beginning balance as of January 1,	$	18		$	17
Total gains or (losses) (realized and unrealized):
Included in income		3			4
Included in accumulated other comprehensive loss		—			—
Purchases and issuances		(3	)		(3	)
Settlements		—			—
Transfers in (out) of Level 3		—			—
Ending balance as of December 31,	$	18		$	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,
	2010		2009
	(millions of dollars)
Total gains included in income for the period	$	3	$	4
Change in unrealized gains relating to assets still held at reporting date	$	3	$	4

Fair Value of Debt and Equity Instruments

The estimated fair values of Pepco’s issued debt and equity instruments at December 31, 2010 and 2009 are shown below:

	December 31, 2010				December 31, 2009
	(millions of dollars)
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	1,540	$	1,722	$	1,555	$	1,707

The fair value of long-term debt issued by Pepco was based on actual trade prices as of December 31, 2010 and 2009.

The carrying amounts of all other financial instruments in the accompanying financial statements approximate fair value.

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(13) COMMITMENTS AND CONTINGENCIES

Regulatory and Other Matters

Proceeds from Settlement of Mirant Bankruptcy Claims

In 2007, Pepco received proceeds from the settlement of its Mirant Corporation (Mirant) bankruptcy claims relating to the Panda PPA. In September 2008, Pepco transferred the Panda PPA to an unaffiliated third party, along with a payment to the third party of a portion of the settlement proceeds. 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 Panda PPA. 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 remaining after the transfer of the Panda PPA. 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.

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.

On May 18, 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, increases the aggregate amount Pepco is required to distribute to customers, pursuant to the sharing formula, by approximately $11 million. On June 17, 2010, Pepco filed an application for reconsideration of the DCPSC’s order, contesting (i) approximately $5 million of the total of $6 million in disallowances and (ii) approximately $4 million of the $5 million in interest to be credited to customers (reflecting a difference in the period of time over which interest was calculated as well as the balance to which interest would be applied). On July 16, 2010, the DCPSC denied Pepco’s application for reconsideration. On September 7, 2010, Pepco filed an appeal of the DCPSC’s decision with the District of Columbia Court of Appeals. PHI recognized an expense of $11 million for the year ended December 31, 2010 corresponding to the disallowed items. The appeal is still pending.

Maryland Public Service Commission Reliability Investigation

In August 2010, following the major storm events that occurred in July and August 2010, the MPSC initiated a proceeding for the purpose of investigating the reliability of the Pepco distribution system and the quality of distribution service Pepco is providing its customers. On February 10, 2011, the MPSC issued a notice expanding the scope of issues on which it requested testimony to include suggested remedies for the MPSC to consider imposing if the MPSC finds that Pepco has failed to meet its public service obligations. The possible remedies identified in the notice were the imposition of civil penalties, changes in the manner of Pepco’s operations, modification of Pepco’s service territory and revocation of Pepco’s authority to exercise its public utility franchise. The MPSC has retained an independent consultant to review and make recommendations regarding the reliability of Pepco’s distribution system and the quality of its service. The independent consultant’s report is due March 4, 2011. The MPSC has scheduled hearings on this matter to occur in mid-June 2011. While Pepco intends to cooperate fully with

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the MPSC in its efforts to ensure that the electric service provided by Pepco to its Maryland customers is reliable, it intends to oppose vigorously any effort of the MPSC to impose any sanctions of the types specified in the February 10, 2011 notice. Although Pepco believes that it has a strong factual and legal basis to oppose such sanctions, it cannot predict the outcome of this proceeding.

Rate Proceedings

Over the last several years, Pepco has proposed the adoption of mechanisms 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 and the District of Columbia; however, the MPSC has initiated a proceeding to review how the BSA operates in Maryland to recover revenues lost as a result of major storm outages (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. The BSA increases rates if actual distribution revenues fall below the approved level and decreases rates if actual distribution revenues are above the approved level. The result is that, over time, Pepco collects its authorized revenues for distribution service. As a consequence, a BSA “decouples” distribution revenue from unit sales consumption and ties the growth in distribution revenues to the growth in the number of customers. Some advantages of the BSA are that it (i) eliminates revenue fluctuations due to weather and changes in customer usage patterns and, therefore, provides for more predictable distribution revenues that are better aligned with costs, (ii) provides for more reliable fixed-cost recovery, (iii) tends to stabilize customers’ delivery bills, and (iv) removes any disincentives for Pepco to promote energy efficiency programs for their customers, because it breaks the link between overall sales volumes and distribution revenues.

Maryland

In December 2009, Pepco filed an electric distribution base rate case in Maryland. The filing sought approval of an annual rate increase of approximately $40 million, based on a requested return on equity (ROE) of 10.75%. During the course of the proceeding, Pepco reduced its request to approximately $28.2 million. On August 6, 2010, the MPSC issued an order approving a rate increase of approximately $7.8 million, based on an ROE of 9.83%. On September 2, 2010, Pepco filed with the MPSC a motion for reconsideration of the following issues, which in the aggregate would increase annual revenue by approximately $8.5 million: (1) denial of inclusion in rate base of certain reliability plant investments, which occurred subsequent to the test period but before the rate effective period; (2) denial of Pepco’s request to increase depreciation rates to reflect a corrected formula relating to the cost of removal expenses; and (3) imposition of imputed cost savings to partially offset the costs of Pepco’s enhanced vegetation management program. Maryland law and regulation do not mandate a response time from the MPSC regarding Pepco’s motion and, therefore, it is not known when the MPSC will issue a ruling on the motion.

On February 1, 2011, the MPSC initiated proceedings for Pepco and DPL, as well as unaffiliated utilities such as Baltimore Gas & Electric Company and Southern Maryland Electric Cooperative, for the purpose of reviewing how the BSA operates to recover revenues lost as a result of major storm outages. In its orders initiating the proceedings, the MPSC expressed concern that the utilities’ respective BSAs may be allowing them to recover revenues lost during extended outages, therefore unintentionally eliminating an incentive to restore service quickly. The MPSC will consider whether the BSA, as currently in effect, is appropriate, whether the calculations or determinant factors for calculating the BSA should be modified, and if so, what modifications should be made. A similar adjustment was included in the BSA in the District of Columbia when the BSA was approved by the DCPSC.

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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.

Since the initial filings in 1993, additional individual suits have been filed against Pepco, and significant numbers of cases have been dismissed. As a result of two motions to dismiss, numerous hearings and meetings and one motion for summary judgment, Pepco has had approximately 400 of these cases successfully dismissed with prejudice, either voluntarily by the plaintiff or by the court. As of December 31, 2010, there are approximately 180 cases still pending against Pepco in the State Courts of Maryland, of which approximately 90 cases were filed after December 19, 2000, and were tendered to 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; however, based on information and relevant circumstances known at this time, neither PHI nor Pepco believes these suits will have a material adverse effect on its financial condition, results of operations or cash flows. However, 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 Litigation

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. In addition, federal and state statutes authorize governmental agencies to compel responsible parties to clean up certain abandoned or unremediated hazardous waste sites. Pepco 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. Although penalties assessed for violations of environmental laws and regulations are not recoverable from Pepco’s customers, environmental clean-up costs incurred by Pepco would be included in its cost of service for ratemaking purposes.

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, 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 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 are entitled to the recyclable material exemption from CERCLA liability. At this time Pepco cannot predict how EPA will proceed regarding this matter, or what portion, if any, of the Peck Iron and Metal site

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response costs EPA would seek to recover from Pepco. In a 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.

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. With the court’s permission, the plaintiffs filed amended complaints in September 2009. Pepco, as part of a group of defendants, filed a motion to dismiss in October 2009. In a March 24, 2010 order, the court denied the defendants’ motion to dismiss. Although it is too early in the process to characterize the magnitude of the potential liability at this site, Pepco does not believe that it had extensive business transactions, if any, with the Ward Transformer site.

Benning Road Site. On September 21, 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 (PCBs) 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 as a result of the study, to clean up the facility) is not reached. In a letter dated October 8, 2010, the Office of the Attorney General of the District of Columbia notified PHI of the District’s intent to sue Pepco Energy Services and Pepco under the Resource Conservation and Recovery Act for abatement of conditions related to their historical activities, including the discharge of PCBs at the Benning Road site. The District’s letter also stated that EPA will list the Benning Road site on the NPL if contamination at the facility is not addressed in a timely manner and that if Pepco fails to meet the District’s deadline, the District intends to sue Pepco and Pepco Energy Services in federal court to seek a scientific study to identify the nature of conditions at the Benning Road site, abatement of conditions, compensation for natural resource damages and reimbursement of DDOE’s related costs. Pepco and Pepco Energy Services entered into a consent decree with DDOE, filed in the federal District Court on February 1, 2011, which will require the PHI entities to conduct a remedial investigation and feasibility study (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. The consent decree will not be final until the DDOE files a motion requesting the Court to enter the consent decree, after a public comment period ends on March 7, 2011, and the Court enters it. In light of the consent decree, Pepco and Pepco Energy Services anticipate that EPA will refrain from listing the Benning Road facility on the NPL. PHI preliminarily estimates that costs for performing the RI/FS will be approximately $600,000 and the remediation costs will be approximately $13 million. PHI recognized expense of $14 million in the fourth quarter of 2010 with respect to this matter and, as of December 31, 2010, has $14 million accrued for this matter.

District of Columbia Tax Legislation

In December 2009, the Mayor of the District of Columbia approved legislation adopted by the City Council that imposes mandatory combined unitary business reporting beginning with tax year 2011, and revises the District’s related party expense disallowance beginning with tax year 2009. Because the City Council must still enact further legislation providing guidance on how to implement combined unitary business reporting before this provision is effective, PHI believes that the legislative process was not complete as of December 31, 2010, and, therefore, the effect of the legislation for combined unitary business tax reporting has not been accounted for as of December 31, 2010.

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The legislation does not define the term “unitary business” and does not specify how combined tax reporting would differ from PHI’s current consolidated tax reporting in the District of Columbia. However, based upon PHI’s interpretation of combined unitary business tax reporting in other taxing jurisdictions, the legislation would likely result in a change in PHI’s overall state income tax rate and, therefore, would likely require an adjustment to PHI’s net deferred income tax liabilities. Further, to the extent that the change in rate increases net deferred income tax liabilities, PHI must determine if these increased tax liabilities are probable of recovery in future rates. No timetable has been established by the City Council to enact the required further legislation and, therefore, it is uncertain as to when combined unitary reporting will be effective for PHI’s District of Columbia tax returns.

Management continues to analyze the impact that the unitary business tax reporting aspect of this legislation, if completed, may have on the financial position, results of operations and cash flows of PHI and its subsidiaries.

Contractual Obligations

As of December 31, 2010, 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, 2010, 2009 and 2008 were approximately $186 million, $175 million, and $164 million, respectively.

Certain subsidiaries of 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, 2010, 2009 and 2008 were approximately $10 million, $9 million and $11 million, respectively.

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,
	2010			2009		2008
	(millions of dollars)
Income (Expense)
Purchased power under Default Electricity Supply contracts with Conectiv Energy Supply, Inc. (a)	$	—	(b)	$	1	$	(23	)

(a) Included in purchased energy expense.

(b) During 2010, PHI sold Conectiv Energy’s wholesale power generation business.

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As of December 31, 2010 and 2009, Pepco had the following balances on its balance sheets due to related parties:

	2010			2009
	(millions of dollars)
(Liability) Asset
Payable to Related Party (current) (a)
PHI Parent Company	$	—		$	(8	)
PHI Service Company		(27	)		(3	)
Pepco Energy Services (b)		(48	)		(99	)
Other		—			(1	)
Total	$	(75	)	$	(111	)
Money Pool Balance with Pepco Holdings (included in Cash and cash equivalents)	$	82		$	203

(a) These amounts are included in the “Accounts payable due to associated companies” balances on the balance sheet.

(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.

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(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.

	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
	2009
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(millions of dollars)
Total Operating Revenue	$	577		$	518		$	648		$	488		$	2,231
Total Operating Expenses (c)		522			465			527			444			1,958
Operating Income		55			53			121			44			273
Other Expenses		(22	)		(23	)		(23	)		(23	)		(91	)
Income Before Income Tax Expense		33			30			98			21			182
Income Tax Expense		14			13			40			9			76
Net Income	$	19		$	17		$	58		$	12		$	106

(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.

(c) Includes gains of $14 million ($8 million after-tax) and $26 million ($16 million after-tax) during the first and third quarters, respectively, related to settlement of Mirant bankruptcy 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 is repositioning itself as a regulated transmission and distribution company. In connection with this repositioning, 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 that are allocated to its operating segments. This review has resulted in the adoption of a restructuring plan. PHI began implementing the plan during the third quarter, identifying 164 employee positions that were to be eliminated during the fourth quarter of 2010. The plan also focuses on identifying additional cost reduction opportunities through process improvements and operational efficiencies.

In connection with the restructuring plan, Pepco recorded a pre-tax restructuring charge of $15 million for the year ended December 31, 2010 related to its allocation of severance, pension, and health and welfare benefits for terminations of corporate services employees at PHI. 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 has been reflected as a separate line item in the statements of income.

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A reconciliation of Pepco’s accrued restructuring charges for the year ended December 31, 2010 is as follows:

	Year Ended December 31, 2010
	(millions of dollars)
Beginning balance as of January 1, 2010	$	—
Restructuring charge		15
Cash payments		—
Ending balance as of December 31, 2010	$	15

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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) under the Securities Exchange Act of 1934, as amended. 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 assessed its internal control over financial reporting as of December 31, 2010 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, 2010.

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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, 2010 and December 31, 2009, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2010 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 24, 2011

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DELMARVA POWER & LIGHT COMPANY

STATEMENTS OF INCOME

For the Year Ended December 31,	2010			2009			2008
	(millions of dollars)
Operating Revenue
Electric	$	1,163		$	1,135		$	1,221
Natural gas		237			268			318
Total Operating Revenue		1,400			1,403			1,539
Operating Expenses
Purchased energy		740			751			821
Gas purchased		164			193			245
Other operation and maintenance		255			238			222
Restructuring charge		8			—			—
Depreciation and amortization		83			76			72
Other taxes		37			35			35
Gain on sale of assets		—			—			(4	)
Total Operating Expenses		1,287			1,293			1,391
Operating Income		113			110			148
Other Income (Expenses)
Interest and dividend income		—			1			2
Interest expense		(44	)		(44	)		(40	)
Other income		7			1			3
Total Other Expenses		(37	)		(42	)		(35	)
Income Before Income Tax Expense		76			68			113
Income Tax Expense		31			16			45
Net Income	$	45		$	52		$	68

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

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DELMARVA POWER & LIGHT COMPANY

BALANCE SHEETS

ASSETS	December 31, 2010			December 31, 2009
	(millions of dollars)
CURRENT ASSETS
Cash and cash equivalents	$	69		$	26
Accounts receivable, less allowance for uncollectible accounts of $13 million and $12 million, respectively		212			193
Inventories		41			40
Prepayments of income taxes		62			64
Prepaid expenses and other		22			19
Total Current Assets		406			342
INVESTMENTS AND OTHER ASSETS
Goodwill		8			8
Regulatory assets		242			207
Prepaid pension expense		139			157
Other		21			28
Total Investments and Other Assets		410			400
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		3,000			2,807
Accumulated depreciation		(901	)		(860	)
Net Property, Plant and Equipment		2,099			1,947
TOTAL ASSETS	$	2,915		$	2,689

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, 2010		December 31, 2009
	(millions of dollars, except shares)
CURRENT LIABILITIES
Short-term debt	$	105	$	105
Current portion of long-term debt		35		31
Accounts payable and accrued liabilities		98		106
Accounts payable due to associated companies		34		14
Taxes accrued		6		3
Interest accrued		7		6
Derivative liabilities		15		15
Other		73		64
Total Current Liabilities		373		344
DEFERRED CREDITS
Regulatory liabilities		310		290
Deferred income taxes, net		561		489
Investment tax credits		7		7
Other postretirement benefit obligations		22		23
Above-market purchased energy contracts and other electric restructuring liabilities		14		17
Liabilities and accrued interest related to uncertain tax positions		24		20
Derivative liabilities		8		13
Other		25		23
Total Deferred Credits		971		882
LONG-TERM LIABILITIES
Long-term debt		730		655
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		336
Retained earnings		494		472
Total Equity		841		808
TOTAL LIABILITIES AND EQUITY	$	2,915	$	2,689

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

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DELMARVA POWER & LIGHT COMPANY

STATEMENTS OF CASH FLOWS

For the Year Ended December 31,	2010			2009			2008
	(millions of dollars)
OPERATING ACTIVITIES
Net income	$	45		$	52		$	68
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		83			76			72
Deferred income taxes		74			60			33
Investment tax credit adjustments		(1	)		(1	)		(1	)
Other		—			—			(4	)
Changes in:
Accounts receivable		(21	)		10			(44	)
Inventories		(1	)		12			(7	)
Prepaid expenses		—			1			(7	)
Regulatory assets and liabilities, net		(12	)		29			27
Accounts payable and accrued liabilities		31			(26	)		(19	)
Pension contributions		—			(10	)		—
Prepaid pension expense, excluding contributions		18			37			(6	)
Taxes accrued		11			(37	)		12
Other assets and liabilities		(1	)		10			(1	)
Net Cash From Operating Activities		226			213			123
INVESTING ACTIVITIES
Investment in property, plant and equipment		(250	)		(193	)		(150	)
Proceeds from sale of assets		—			1			54
Changes in restricted cash equivalents		—			—			4
Net other investing activities		2			1			(1	)
Net Cash Used By Investing Activities		(248	)		(191	)		(93	)
FINANCING ACTIVITIES
Dividends paid to Parent		(23	)		(28	)		(52	)
Capital contribution from Parent		11			32			62
Issuances of long-term debt		109			—			400
Reacquisitions of long-term debt		(31	)		—			(116	)
Repayments of short-term debt, net		—			(141	)		(190	)
Net other financing activities		(1	)		3			(7	)
Net Cash From (Used By) Financing Activities		65			(134	)		97
Net Increase (Decrease) In Cash and Cash Equivalents		43			(112	)		127
Cash and Cash Equivalents at Beginning of Year		26			138			11
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	69		$	26		$	138
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for interest (net of capitalized interest of $2 million, $1 million and $1 million, respectively)	$	40		$	41		$	37
Cash (received) paid for income taxes		(49	)		(17	)		1

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, 2007		1,000	$	—	$	242	$	432		$	674
Net Income		—		—		—		68			68
Dividends on common stock		—		—		—		(52	)		(52	)
Capital contribution from Parent		—		—		62		—			62
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

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 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, which is wholly owned by Pepco Holdings, Inc. (Pepco Holdings or PHI).

In January 2008, DPL completed the sale of its retail electric distribution assets and the sale of its wholesale electric transmission assets, both located on Virginia’s Eastern Shore.

(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 impairment evaluations, fair value calculations (based on estimated market pricing) associated with 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, 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 the loss is determined to be probable and is reasonably estimable.

Restructuring Charges

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.

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. In the first half of 2010, DPL recorded an immaterial decrease in transmission service revenue that will be adjusted

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for over the 2010-2011 service year for costs incurred in the 2009 service year. In the fourth quarter of 2010, DPL recorded a decrease in transmission service revenue of $1 million that it estimates will be reflected as a reduction in transmission service rates for the 2011-2012 service year based on costs incurred during the first seven months of the 2010 service year. DPL will update its estimate of the reduction in transmission service revenue for the 2011-2012 service year in the first and second quarters of 2011 as it progresses toward the completion of the 2010-2011 service year and final cost information from the 2010-2011 service year becomes available. In the second quarter of 2011, DPL expects to record a true-up as part of its updated transmission service rates that are submitted to FERC.

Change in Accounting Principle

After the completion of the July 1, 2009 goodwill impairment test, DPL adopted a new accounting policy whereby DPL’s annual impairment review of goodwill will be performed annually as of November 1. Management believes that DPL’s new annual impairment testing date is preferable because it better aligns the timing of the test with management’s annual update of its long-term financial forecast. This change in accounting principle has had no effect on DPL’s financial statements.

Revenue Recognition

DPL recognizes revenues upon distribution of electricity and gas to its customers, including amounts for services rendered, but not yet billed (unbilled revenue). DPL recorded amounts for unbilled revenue of $72 million and $68 million as of December 31, 2010 and 2009, respectively. 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 loss (estimates of electricity and gas expected to be lost in the process of its transmission and distribution to customers). The assumptions and judgements 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 revenues. Accruals for 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.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in DPL’s gross revenues were $17 million, $17 million and $15 million for the years ended December 31, 2010, 2009 and 2008, respectively.

Accounting for Derivatives

DPL uses derivative instruments (forward contracts, futures, swaps, and exchange-traded and over-the-counter options) primarily to reduce gas commodity price volatility while limiting its customers’ exposure to increases in the market price of gas. DPL also manages commodity risk with physical natural gas and capacity contracts that are not classified as derivatives. The primary goal of these activities is to reduce the exposure of its regulated retail gas customers to natural gas price fluctuations. 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 Delaware Public Service Commission (DPSC), and are deferred under Financial Accounting Standards Board (FASB) guidance on regulated operations (Accounting Standards Codification (ASC) 980) until recovered. 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. At December 31, 2009, after the effects of cash collateral and netting, there was a net derivative liability of $28 million, offset by a $42 million regulatory asset.

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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 Assets and Regulatory Liabilities,” for additional information.

Deferred income tax expense generally represents the net change during the reporting period in the net deferred tax liability and deferred recoverable income taxes.

DPL recognizes interest on under or over payments 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

In accordance with FASB guidance on the consolidation of variable interest entities (ASC 810), DPL consolidates those variable interest entities with respect to which DPL is the primary beneficiary. The guidance addresses conditions under which an entity should be consolidated based upon variable interests rather than voting interests.

DPL Renewable Energy Transactions

DPL has entered into four wind power purchase agreements (PPAs) in the aggregate amount of 350 megawatts that include the purchase of renewable energy credits (RECs) and one solar REC purchase agreement with a nine megawatt facility. The DPSC has approved DPL’s entry into each of the agreements and the recovery of DPL’s purchase costs through customer rates. The RECs purchased under all the agreements will help DPL fulfill a portion of its requirements under the State of Delaware’s Renewable Energy Portfolio Standards Act.

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Of the wind PPAs, three of the PPAs are with land-based facilities and one of the PPAs is with an offshore facility. One of the land-based facilities became operational and went into service in December 2009. DPL is obligated to purchase energy and RECs from this facility through 2024 in amounts generated and delivered not to exceed 50.25 megawatts at rates that are primarily fixed. DPL’s purchases under this PPA totaled $12 million for 2010. Purchases under the other wind agreements, which have terms ranging from 20 to 25 years, are currently expected to start in 2011 for the other two land-based contracts and 2016 for the offshore contract, if the projects are ultimately completed and operational. When they become operational, DPL is obligated to purchase energy and RECs in amounts generated and delivered by the sellers at rates that are primarily fixed under these agreements. Under one of the agreements, DPL is also obligated to purchase the capacity associated with the facility at rates that are generally fixed. If the offshore wind facility developer is unable to obtain all necessary permits and financing commitments, this could result in setbacks in the construction schedules and the operational start dates of the offshore wind facility. If the wind facilities are not operational by specified dates, DPL has the right to terminate the PPAs. The term of the agreement with the solar facility is 20 years and DPL is obligated to purchase RECs in an amount up to seventy percent of the energy output from the solar facility at a fixed price once the facility is operational, which is expected to be in the third quarter of 2011.

DPL concluded that consolidation is not required for any of these agreements under FASB guidance on the consolidation of variable interest entities (ASC 810).

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand, cash invested in money market funds and commercial paper held with original maturities of three months or less. Additionally, deposits in PHI’s money pool, which DPL and certain other PHI subsidiaries use to manage short-term cash management requirements, are considered cash equivalents. Deposits in the money pool are guaranteed by PHI. PHI deposits funds in the money pool to the extent that the pool has insufficient funds to meet the needs of its participants, which may require PHI to borrow funds for deposit from external sources.

Accounts Receivable and Allowance for Uncollectible Accounts

DPL’s accounts receivable balance primarily consists of customer accounts receivable, 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 becomes known.

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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. After the completion of its July 1, 2009 annual impairment test, DPL changed the date of its annual impairment test to 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,” no impairment charge has been recorded for the year ended December 31, 2010.

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 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. 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.

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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 2010, 2009 and 2008 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 $2 million, $1 million, and $1 million for the years ended December 31, 2010, 2009, and 2008, respectively.

DPL recorded amounts for the equity component of AFUDC of $4 million, zero and $1 million for the years ended December 31, 2010, 2009 and 2008, 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.

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.

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Asset Removal Costs

In accordance with FASB guidance, asset removal costs are recorded as regulatory liabilities. At both December 31, 2010 and 2009, $239 million of asset removal costs are included in regulatory liabilities in the accompanying balance sheets.

Pension and Postretirement Benefit Plans

Pepco Holdings sponsors a non-contributory retirement plan that covers substantially all employees of DPL (the PHI Retirement Plan) 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 $494 million and $472 million of retained earnings available for payment of common stock dividends at December 31, 2010 and 2009, 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:

Operating Revenue

During 2009, DPL recorded additional revenue of $14 million related to the unbilled portion of the Gas Cost Rate (GCR) revenue, which was not previously recognized. Because the GCR revenue is deferred, an additional expense of $14 million was recorded in 2009. Consequently, there was no impact on net income.

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 for the year ended December 31, 2009.

Operating Expenses

During 2008, DPL recorded adjustments to correct errors in Other operation and maintenance expenses for prior periods dating back to May 2006 during which (i) customer late payment fees were incorrectly recognized and (ii) stock-based compensation expense related to certain restricted stock awards granted under the Long-Term Incentive Plan was understated. These adjustments resulted in a total increase in Other operation and maintenance expenses of $5 million for the year ended December 31, 2008, all of which related to prior periods.

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(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Transfers and Servicing (ASC 860)

The FASB issued new guidance that removes the concept of a qualifying special-purpose entity (QSPE) from the guidance on transfers and servicing and the QSPE scope exception in the guidance on consolidation. The new guidance also changes the requirements for derecognizing financial assets and requires additional disclosures about a transferor’s continuing involvement in transferred financial assets. The guidance was effective for transfers of financial assets occurring in fiscal periods beginning on January 1, 2010 for DPL. This guidance did not have a material impact on DPL’s overall financial condition, results of operations, or cash flows.

Fair Value Measurement and Disclosures (ASC 820)

The FASB issued new disclosure requirements for recurring and non-recurring fair value measurements. The guidance, effective beginning with DPL’s March 31, 2010 financial statements, requires the disaggregation of balance sheet items measured at fair value into subsets of balance sheet items based on the nature and risks of the items. The standard requires descriptions of pricing inputs and valuation methodologies for instruments with Level 2 or 3 valuation inputs. In addition, the standard requires information about any significant transfers of instruments between Level 1 and 2 valuation categories. These additional disclosures are included in Note (14), “Fair Value Disclosures.”

Consolidation of Variable Interest Entities (ASC 810)

The FASB issued new consolidation guidance regarding variable interest entities effective January 1, 2010 that eliminates the quantitative analysis requirement and adds new qualitative factors to determine whether consolidation is required. The new qualitative factors are applied on a quarterly basis to interests in variable interest entities. Under the new guidance, the holder of the interest with the power to direct the most significant activities of the entity and the right to receive benefits or absorb losses significant to the entity would consolidate. The new guidance retains the provision that allows entities created before December 31, 2003 to be scoped out from a consolidation assessment if exhaustive efforts are taken and there is insufficient information to determine whether there is a relationship with a variable interest entity or the primary beneficiary of a variable interest entity. This guidance did not have a material impact on DPL’s overall financial condition, results of operations, or cash flows.

Subsequent Events (ASC 855)

The FASB issued new guidance that eliminates the requirement for DPL to disclose the date through which it has evaluated subsequent events beginning with its March 31, 2010 financial statements.

(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Fair Value Measurement and Disclosures (ASC 820)

The FASB issued new disclosure requirements that require the disaggregation of the Level 3 fair value measurement reconciliations into separate categories for significant purchases, sales, issuances, and settlements. This requirement is effective beginning with DPL’s March 31, 2011 financial statements. DPL is evaluating the impact of this new guidance on its financial statement footnote disclosures.

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Goodwill (ASC 350)

In December 2010, the FASB issued new guidance on performing goodwill impairment tests. The new guidance eliminates the option to exclude liabilities that are part of the capital structure of the reporting unit when calculating the carrying value of the reporting unit. This is effective for DPL beginning January 1, 2011. Under the new guidance, the carrying value of the reporting unit is the net amount of the assets and liabilities allocated to the reporting unit. DPL allocates liabilities to the reporting unit when performing its goodwill impairment test, so the new guidance is not expected to change how DPL currently performs its goodwill impairment test.

(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, 2010. 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, 2010 indicated that goodwill was not impaired. As of December 31, 2010, after review of its significant assumptions in the goodwill impairment analysis, DPL concluded that there were no events requiring it to perform an interim goodwill impairment test. DPL performed its previous annual goodwill impairment test as of November 1, 2009, which 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.

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(7) REGULATORY ASSETS AND REGULATORY LIABILITIES

The components of DPL’s regulatory asset and liability balances at December 31, 2010 and 2009 are as follows:

	2010		2009
	(millions of dollars)
Regulatory Assets
Deferred income taxes	$	65	$	68
Deferred energy supply costs (a)		22		6
Deferred debt extinguishment costs (b)		16		18
Recoverable meter related costs (b)		29		5
COPCO acquisition adjustment (b)		33		35
Gas derivatives		31		42
Other		46		33
Total Regulatory Assets	$	242	$	207
Regulatory Liabilities
Asset removal costs	$	239	$	239
Deferred income taxes due to customers		38		38
Deferred energy supply costs		23		12
Other		10		1
Total Regulatory Liabilities	$	310	$	290

(a) A return is generally earned in Delaware

(b) A return is earned on these deferrals

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.

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.

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.

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 (AMI) project.

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%.

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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: 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.

(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 $97 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, 2010, are $11 million in 2011, $11 million in 2012, $10 million in each of the years 2013 through 2015, and $112 million thereafter.

Rental expense for operating leases, including the Merrill Creek Reservoir lease, was $10 million, $9 million and $9 million for the years ended December 31, 2010, 2009 and 2008, respectively.

(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, 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
At December 31, 2009
Distribution	$	1,430	$	411	$	1,019
Transmission		684		211		473
Gas		398		116		282
Construction work in progress		92		—		92
Non-operating and other property		203		122		81
Total	$	2,807	$	860	$	1,947

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.

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Asset Sales

In January 2008, DPL completed (i) the sale of its retail electric distribution assets located on the Eastern Shore of Virginia for approximately $49 million, and (ii) the sale of its wholesale electric transmission assets located on the Eastern Shore of Virginia for approximately $5 million.

(10) PENSION AND OTHER POSTRETIREMENT BENEFITS

DPL accounts for its participation in the Pepco Holdings benefit plans as participation in a multi-employer plan. For 2010, 2009, and 2008, DPL was responsible for $28 million, $25 million and $3 million, respectively, of the pension and other postretirement net periodic benefit cost incurred by Pepco Holdings. DPL made discretionary, tax-deductible contributions of $10 million to the PHI Retirement Plan for the year ended December 31, 2009. No contributions were made for the years ended December 31, 2010 and 2008. In addition, DPL made contributions of $9 million, $10 million and $9 million, respectively, to the other postretirement benefit plans for the years ended December 31, 2010, 2009 and 2008. At December 31, 2010 and 2009, DPL’s Prepaid pension expense of $139 million and $157 million, and Other postretirement benefit obligations of $22 million and $23 million, effectively represent assets and benefit obligations resulting from DPL’s participation in the Pepco Holdings benefit plans.

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(11) DEBT

Long-Term Debt

Long-term debt outstanding as of December 31, 2010 and 2009 is presented below:

Type of Debt	Interest Rate		Maturity			2010		2009
						(millions of dollars)
First Mortgage Bonds
		6.40%		2013		$	250	$	250
		5.20%		2019	(c)		31		31
		4.90%		2026	(b)(c)		35		35
		5.22%		2016	(c)		100		100
							416		416
Unsecured Tax-Exempt Bonds
		5.50%		2025	(a)		—		15
		5.65%		2028	(a)		—		16
		1.80%		2025	(d)		15		—
		2.30%		2028	(d)		16		—
		5.40%		2031			78		—
							109		31
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		687
Other long-term debt							1		—
Unamortized discount							(1)		(1)
Current portion of long-term debt							(35)		(31)
Total net long-term debt						$	730	$	655

(a) The bonds were subject to mandatory tender on July 1, 2010.

(b) The bonds are subject to mandatory tender on May 1, 2011.

(c) 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.

(d) The bonds are subject to mandatory tender on June 1, 2012

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 and sinking fund requirements during the next five years are as follows: $35 million in 2011, $31 million in 2012, $250 million in 2013, $100 million in 2014, $100 million in 2015, and $249 million thereafter.

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DPL’s long-term debt is subject to certain covenants. As of December 31, 2010, DPL is in compliance with all such covenants.

Tax-Exempt Bonds

In April 2010, DEDA issued $78 million of 5.40% Gas Facilities Refunding Revenue Bonds due 2031 for the benefit of DPL. DPL used the proceeds to effect the redemption of the outstanding amounts of five series of tax-exempt bonds in an aggregate principal amount of $78 million that were purchased by DPL in 2008.

In December 2010, DPL resold (i) $15 million of 1.80% Pollution Control Refunding Revenue Bonds (Delmarva Power & Light Company Project) Series 2000C due 2025, and (ii) $16 million of 2.30% Pollution Control Refunding Revenue Bonds (Delmarva Power & Light Company Project) Series 2000D due 2028. The bonds were originally issued for the benefit of DPL in 2000 and had been purchased by DPL in July 2010 pursuant to a mandatory repurchase provision in the respective indentures for the bonds that was triggered by the expiration of the original interest period for the bonds. The bonds are subject to mandatory purchase by DPL on June 1, 2012.

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, 2010 and 2009 is as follows:

	2010		2009
	(millions of dollars)
Variable Rate Demand Bonds	$	105	$	105

Commercial Paper

DPL maintains an ongoing commercial paper program of up to $500 million. The commercial paper notes can be issued with maturities up to 270 days from the date of issue. The commercial paper program is backed by DPL’s borrowing capacity under PHI’s $1.5 billion credit facility described below under the heading “Credit Facility.”

DPL had no commercial paper outstanding at December 31, 2010 and 2009. The weighted average interest rates for commercial paper issued during 2010 and 2009 were 0.34% and 0.56%, respectively. The weighted average maturity of all commercial paper issued by DPL during 2010 and 2009 was two and five days, respectively.

Variable Rate Demand Bonds

Variable Rate Demand Bonds (VRDBs) are subject to repayment on the demand of the holders and, for this reason, are accounted for as short-term debt in accordance with GAAP. However, bonds submitted for purchase are remarketed by a remarketing agent on a best efforts basis. DPL expects the 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 2010 mature as follows: 2017 ($26 million), 2024 ($33 million), 2028 ($16 million), and 2029 ($30 million). The weighted average interest rate for VRDBs was 0.52% during 2010 and 1.78% during 2009. 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.

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Credit Facility

PHI, Potomac Electric Power Company (Pepco), DPL and Atlantic City Electric Company (ACE) maintain an unsecured credit facility to provide for their respective short-term liquidity needs. The aggregate borrowing limit under the facility is $1.5 billion, all or any portion of which may be used to obtain loans or to issue letters of credit. PHI’s credit limit under the facility is $875 million. The credit limit of each of Pepco, DPL and ACE is the lesser of $500 million and the maximum amount of debt the company is permitted to have outstanding by its regulatory authorities, except that the aggregate amount of credit used by Pepco, DPL and ACE at any given time collectively may not exceed $625 million. 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 and the federal funds effective rate plus 0.5%, or (ii) the prevailing Eurodollar rate, plus a margin that varies according to the credit rating of the borrower. 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 $150 million. Any swingline loan must be repaid by the borrower within seven days of receipt thereof.

The facility commitment expiration date is May 5, 2012, with each company having the right to elect to have 100% of the principal balance of the loans outstanding on the expiration date continued as non-revolving term loans for a period of one year from such expiration date.

The facility is intended to serve primarily as a source of liquidity to support the commercial paper programs of the respective companies. The companies are also permitted to use the facility to borrow funds for general corporate purposes and issue letters of credit. 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 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 excludes from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) a restriction on sales or other dispositions of assets, other than certain sales and dispositions, 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 absence of a material adverse change in the borrower’s business, property and results of operations or financial condition is not a condition to the availability of credit under the facility. The facility does not include any rating triggers. As of December 31, 2010, each borrower was in compliance with the covenants of the credit facility.

At December 31, 2010 and 2009, the amount of cash, plus borrowing capacity under the PHI credit facilities available to meet the liquidity needs of PHI’s utility subsidiaries was $462 million and $582 million, respectively.

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DPL

(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,
	2010			2009			2008
	(millions of dollars)
Current Tax (Benefit) Expense
Federal	$	(37	)	$	(26	)	$	11
State and local		(5	)		(17	)		2
Total Current Tax (Benefit) Expense		(42	)		(43	)		13
Deferred Tax Expense (Benefit)
Federal		61			58			25
State and local		13			2			8
Investment tax credit amortization		(1	)		(1	)		(1	)
Total Deferred Tax Expense		73			59			32
Total Income Tax Expense	$	31		$	16		$	45

Reconciliation of Income Tax Expense

	For the Year Ended December 31,
	2010					2009					2008
	(millions of dollars)
Income tax at Federal statutory rate	$	27		35.0	%	$	24		35.0	%	$	40		35.0	%
Increases (decreases) resulting from
Depreciation		1		1.3	%		2		2.9	%		1		0.9	%
State income taxes, net of Federal effect		4		5.3	%		4		5.9	%		6		5.3	%
State tax benefit related to prior years’ asset dispositions		—		—			(13	)	(19.1	)%		—		—
Tax credits		(1	)	(1.3	)%		(1	)	(1.5	)%		(1	)	(0.9	)%
Change in estimates and interest related to uncertain and effectively settled tax positions		1		1.3	%		(1	)	(1.5	)%		(3	)	(2.7	)%
Adjustments to prior years’ taxes		—		—			2		2.9	%		(1	)	(0.9	)%
Deferred tax basis adjustments		—		—			—		—			2		1.8	%
Other, net		(1	)	(0.8	)%		(1	)	(1.1	)%		1		1.3	%
Income Tax Expense	$	31		40.8	%	$	16		23.5	%	$	45		39.8	%

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DPL

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. 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 has recalculated the estimated interest due for the tax years 1996 to 2002. The revised estimate has resulted in an additional $3 million (after-tax) of estimated interest due to the IRS. This additional estimated interest expense has been recorded in the fourth quarter of 2010 and is subject to adjustment when the IRS finalizes its calculation of the amount due. This expense is partially offset by the reversal of $2 million of previously recorded tax liabilities.

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 carryforward of $7 million (after-tax), related to a change in tax reporting for certain asset dispositions occurring in prior years.

In March 2009, the IRS issued a Revenue Agent’s Report (RAR) 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 RAR.

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.

During 2008, DPL completed an analysis of its current and deferred income tax accounts and, as a result, recorded a $2 million charge to income tax expense in 2008, which is primarily included in “Deferred tax basis adjustments” in the reconciliation provided above. In addition, during 2008, DPL recorded after-tax net interest income of $3 million under FASB guidance on income taxes (ASC 740) primarily related to the reversal of previously accrued interest payable resulting from a favorable tentative settlement of the mixed service cost issue with the IRS.

Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits

	2010			2009			2008
	(millions of dollars)
Beginning balance as of January 1,	$	39		$	54		$	41
Tax positions related to current year:
Additions		3			—			—
Tax positions related to prior years:
Additions		5			10			35
Reductions		(7	)		(25	)		(22	)
Settlements		—			—			—
Ending balance as of December 31,	$	40		$	39		$	54

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, 2010, DPL had no unrecognized tax benefits that, if recognized, would lower the effective tax rate.

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Interest and Penalties

DPL recognizes interest and penalties relating to its uncertain tax positions as an element of income tax expense. For the years ended December 31, 2010, 2009 and 2008, DPL recognized $6 million of pre-tax interest expense ($4 million after-tax), $3 million of pre-tax interest income ($2 million after-tax), and $5 million of pre-tax interest expense ($3 million after-tax), respectively, as a component of income tax expense. As of December 31, 2010, 2009 and 2008, DPL had $5 million, $1 million and $3 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 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 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, Delaware, and Virginia) are the same as for the Federal returns. As a result of the final determination of these years, DPL has filed amended state returns paying an additional $3 million in tax.

Components of Deferred Income Tax Liabilities (Assets)

	As of December 31,
	2010			2009
	(millions of dollars)
Deferred Tax Liabilities (Assets)
Depreciation and other basis differences related to plant and equipment	$	475		$	408
Deferred taxes on amounts to be collected through future rates		14			14
State net operating losses		(9	)		(7	)
Pension and other postretirement benefits		53			52
Other		16			11
Total Deferred Tax Liabilities, net		549			478
Deferred tax assets included in Other Current Assets		13			9
Deferred tax liabilities included in Other Current Liabilities		(1	)		2
Total Deferred Tax Liabilities, net - non-current	$	561		$	489

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, 2010 and 2009.

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The Tax Reform Act of 1986 repealed the investment tax credit (ITC) for property placed in service after December 31, 1985, except for certain transition property. ITC previously earned on DPL’s property continues to be amortized to income over the useful lives of the related property.

Other Taxes

Taxes other than income taxes for each year are shown below. These amounts are recoverable through rates.

	2010		2009		2008
	(millions of dollars)
Gross Receipts/Delivery	$	16	$	17	$	17
Property		19		18		18
Environmental, Use and Other		2		—		—
Total	$	37	$	35	$	35

(13) DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

DPL uses derivative instruments in the form of forward contracts, futures, swaps, and exchange-traded and over-the-counter options primarily to reduce gas commodity price volatility and limit its customers’ exposure to increases in the market price of gas. DPL also manages commodity risk with physical natural gas and capacity contracts that 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 based on the 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, 2010 and 2009:

	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	)

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	As of December 31, 2009
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)		(10	)		(15	)		(25	)		10		(15	)
Derivative Liabilities (non-current liabilities)		—			(14	)		(14	)		1		(13	)
Total Derivative Liabilities		(10	)		(29	)		(39	)		11		(28	)
Net Derivative (Liability) Asset	$	(10	)	$	(29	)	$	(39	)	$	11	$	(28	)

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 a master netting agreements. The amount of cash collateral that was offset against these derivative positions is as follows:

	December 31, 2010		December 31, 2009
	(millions of dollars)
Cash collateral pledged to counterparties with the right to reclaim	$	6	$	11

As of December 31, 2010 and 2009, 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

As described above, 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 based on the fuel adjustment clause approved by the DPSC. The following table indicates the amounts deferred as regulatory assets or liabilities and the location in the statements of income of amounts reclassified to income through the fuel adjustment clause for the years ended December 31, 2010, 2009 and 2008:

	For the Year Ended December 31,
	2010			2009			2008
	(millions of dollars)
Net Gain (Loss) Deferred as a Regulatory Asset or Liability	$	5		$	21		$	(29	)
Net Loss Reclassified from Regulatory Asset or Liability to Purchased Energy or Gas Purchased		(12	)		(39	)		(6	)

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DPL

As of December 31, 2010 and 2009, DPL had the following outstanding commodity forward contracts that were entered into to hedge forecasted transactions:

	Quantities
Commodity	December 31, 2010		December 31, 2009
Forecasted Purchases Hedges:
Natural Gas (One Million British Thermal Units (MMBtu))		1,670,000		5,695,000

Other Derivative Activity

DPL holds certain derivatives that do not qualify as hedges. These derivatives are recorded at fair value on the balance sheet with changes in the fair value recorded in income. In accordance with FASB guidance on regulatory operations, offsetting regulatory assets or regulatory liabilities are recorded on the balance sheet and the recognition of the gain or recovery of the loss is deferred. For the years ended December 31, 2010, 2009 and 2008, the amount of the derivative gain (loss) recognized in the statements of income is provided in the table below by line item:

	For the Year Ended December 31,
	2010			2009			2008
	(millions of dollars)
Net Gain (Loss) Deferred as a Regulatory Asset or Liability	$	6		$	(8	)	$	(13	)
Net Loss Reclassified from Regulatory Asset or Liability to Purchased Energy or Gas Purchased		(26	)		(11	)		(1	)

As of December 31, 2010 and 2009, DPL had the following net outstanding natural gas commodity forward contracts that did not qualify for hedge accounting:

	December 31, 2010				December 31, 2009
Commodity	Quantity		Net Position		Quantity		Net Position
Natural Gas (MMBtu)		7,827,635		Long		10,442,546		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.

279

DPL

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.

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, 2010 and 2009, was $23 million and $28 million, respectively. As of those dates, DPL had posted cash collateral of zero and less than one million dollars, respectively, in the normal course of business against the gross derivative liability resulting in a net liability of $23 million and $28 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, 2010 and 2009, would have been approximately $31 million and $24 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, 2010 and 2009, the aggregate amount of cash plus borrowing capacity under the credit facilities available to meet the liquidity needs of PHI’s utility subsidiaries was $462 million and $582 million, respectively.

(14) FAIR VALUE DISCLOSURES

Fair Value of Assets and Liabilities Excluding Issued Debt and Equity Instruments

DPL has adopted FASB guidance on fair value measurement and disclosures (ASC 820) which 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).

280

DPL

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 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. Some non-standard assumptions are used in their forward valuation to adjust for the pricing; otherwise, most of the options follow NYMEX valuation. A few of the options have no significant NYMEX components, and have to be priced using internal volatility assumptions.

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, 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, 2010 and 2009. 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.

281

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.

	Fair Value Measurements at December 31, 2009
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Cash equivalents
Treasury Fund	$	19	$	19	$	—	$	—
Executive deferred compensation plan assets
Money Market Funds		3		3		—		—
Life Insurance Contracts		1		—		—		1
	$	23	$	22	$	—	$	1
LIABILITIES
Derivative instruments (a)
Natural Gas (b)	$	39	$	10	$	—	$	29
Executive deferred compensation plan liabilities
Life Insurance Contracts		1		—		1		—
	$	40	$	10	$	1	$	29

(a) The fair value of derivative liabilities reflect netting by counterparty before the impact of collateral.

(b) Represents natural gas options purchased by DPL as part of a natural gas hedging program approved by the DPSC.

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DPL

Reconciliations of the beginning and ending balances of DPL’s fair value measurements using significant unobservable inputs (Level 3) for the year ended December 31, 2010 and 2009 are shown below:

	Year Ended December 31, 2010
	Natural Gas			Life Insurance Contracts
	(millions of dollars)
Beginning balance as of January 1, 2010	$	(29	)	$	1
Total gains or (losses) (realized and unrealized):
Included in income		—			—
Included in accumulated other comprehensive loss		—			—
Included in regulatory liabilities		(16	)		—
Purchases and issuances		—			—
Settlements		22			—
Transfers in (out) of Level 3		—			—
Ending balance as of December 31, 2010	$	(23	)	$	1

	Year Ended December 31, 2009
	Natural Gas			Life Insurance Contracts
	(millions of dollars)
Beginning balance as of January 1, 2009	$	(24	)	$	1
Total gains or (losses) (realized and unrealized):
Included in income		—			—
Included in accumulated other comprehensive loss		—			—
Included in regulatory liabilities		(18	)		—
Purchases and issuances		—			—
Settlements		13			—
Transfers in (out) of Level 3		—			—
Ending balance as of December 31, 2009	$	(29	)	$	1

Fair Value of Debt and Equity Instruments

The estimated fair values of DPL’s issued debt and equity instruments as of December 31, 2010 and 2009 are shown below:

	December 31, 2010				December 31, 2009
	(millions of dollars)
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	765	$	822	$	686	$	733

The fair value of long-term debt issued by DPL was based on actual trade prices as of December 31, 2010 and 2009, bid prices obtained from brokers or a discounted cash flow model where actual trade prices were not available.

The carrying amounts of all other financial instruments in the accompanying financial statements approximate fair value.

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DPL

(15) COMMITMENTS AND CONTINGENCIES

Regulatory and Other Matters

Rate Proceedings

Over the last several years, DPL has proposed the adoption of mechanisms 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; however, the MPSC has initiated a proceeding to review how the BSA operates in Maryland to recover revenues lost as a result of major storm outages (as discussed below).

• A modified fixed variable rate design (MFVRD) has been approved in concept for electric service in Delaware, but has been deferred by the DPSC as described below.

• A MFVRD has been approved in concept for natural gas service in Delaware, but DPL anticipates that it will be deferred by the DPSC consistent with its treatment in the electric base rate case.

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 BSA increases rates if actual distribution revenues fall below the approved level and decreases rates if actual distribution revenues are above the approved level. The result is that, over time, DPL collects its authorized revenues for distribution service. As a consequence, a BSA “decouples” distribution revenue from unit sales consumption and ties the growth in distribution revenues to the growth in the number of customers. Some advantages of the BSA are that it (i) eliminates revenue fluctuations due to weather and changes in customer usage patterns and, therefore, provides for more predictable distribution revenues that are better aligned with costs, (ii) provides for more reliable fixed-cost recovery, (iii) tends to stabilize customers’ delivery bills, and (iv) removes any disincentives for DPL to promote energy efficiency programs for their customers, because it breaks the link between overall sales volumes and distribution revenues. 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.

Delaware

DPL makes an annual GCR filing with the DPSC for the purpose of allowing DPL to recover 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 gas costs. In October 2010, the DPSC issued an order placing 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. If the DPSC does not accept DPL’s proposal, the full adjustment would result in an increase of 6.9% in the GCR.

In September 2009, DPL submitted an application to the DPSC to increase its electric distribution base rates. The filing, as revised in March 2010, sought approval of an annual rate increase of approximately $26.2 million, assuming approval of the implementation of the MFVRD, based on a requested return on equity (ROE) of 10.75%. As permitted by Delaware law, DPL placed an increase of approximately $2.5 million annually into effect, on a temporary basis, in November 2009, and the remainder of approximately $23.7 million of requested increase went into effect on April 19, 2010, in each case subject to refund and pending final DPSC approval. In June 2010, DPL lowered the requested annual rate increase to approximately $24.2 million. On January 18, 2011, the DPSC approved a rate increase of approximately $16.4 million, based on an ROE of 10.00%. In early 2011, DPL will refund to customers

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DPL

the excess of the billed amounts over the DPSC approved increase. Consideration of the MFVRD has been deferred pending the development of an education plan for customers and workshops that are open to parties and the public for the purpose of developing a proposed implementation plan for the MFVRD.

On July 2, 2010, DPL submitted an application with the DPSC to increase its natural gas distribution base rates. As subsequently amended on September 10, 2010 (to replace test year data for the twelve months ended June 2010 with the actual data) and on October 11, 2010 (based on an update to DPL’s natural gas advanced metering infrastructure implementation schedule), the filing seeks approval of an annual rate increase of approximately $10.2 million, assuming the implementation of the MFVRD, based on a requested ROE of 11.00%. As permitted by Delaware law, DPL placed an annual increase of approximately $2.5 million annually into effect, on a temporary basis, on August 31, 2010, and the remainder of approximately $7.7 million of the requested increase went into effect on February 2, 2011, in each case subject to refund and pending final DPSC approval. Previously, in June 2009, DPL filed an application requesting approval for the implementation of the MFVRD for gas distribution rates. DPL anticipates that the DPSC will follow the same implementation approach it is following with respect to DPL’s MFVRD proposal for electric service, discussed above. The DPSC decision is still pending.

Maryland

On December 21, 2010, DPL filed an application with the MPSC to increase its electric distribution base rates by $17.8 million annually, based on an ROE of 10.75%. On December 28, 2010, the MPSC, consistent with its typical practice, issued an order suspending the proposed rate increase request for an initial period of 150 days from January 20, 2011 pending investigation by the MPSC.

On February 1, 2011, the MPSC initiated proceedings for DPL and Pepco, as well as unaffiliated utilities such as Baltimore Gas & Electric Company and Southern Maryland Electric Cooperative, for the purpose of reviewing how the BSA operates to recover revenues lost as a result of major storm outages. In its orders initiating the proceedings, the MPSC expressed concern that the utilities’ respective BSAs may be allowing them to recover revenues lost during extended outages, therefore unintentionally eliminating an incentive to restore service quickly. The MPSC will consider whether the BSA, as currently in effect, is appropriate, whether the calculations or determinant factors for calculating the BSA should be modified, and if so, what modifications should be made. A similar adjustment was included in the BSA for Pepco in the District of Columbia when the BSA was approved by the District of Columbia Public Service Commission.

Environmental Litigation

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. In addition, federal and state statutes authorize governmental agencies to compel responsible parties to clean up certain abandoned or unremediated hazardous waste sites. DPL 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. Although penalties assessed for violations of environmental laws and regulations are not recoverable from DPL’s customers, environmental clean-up costs incurred by DPL would be included in its cost of service for ratemaking purposes.

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. With the court’s permission, the plaintiffs filed amended complaints in September 2009. DPL, as part of a group of defendants, filed a motion to dismiss in October 2009. In a March 24, 2010 order, the court denied the defendants’ motion to dismiss. Although it is too early in the process to characterize the magnitude of the potential liability at this site, DPL does not believe that it had extensive business transactions, if any, with the Ward Transformer site.

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DPL

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. Based on updated engineering estimates obtained in the second quarter of 2010, DPL accrued an additional liability in the amount of approximately $4 million in 2010. As of December 31, 2010, DPL’s accrual for expected future costs to fulfill its obligations under the consent agreement was approximately $5 million, of which approximately $1 million is expected to be incurred in 2011.

Contractual Obligations

As of December 31, 2010, DPL’s contractual obligations under non-derivative fuel and power purchase contracts were $65 million in 2011, $129 million in 2012 to 2013, $130 million in 2014 to 2015, and $771 million in 2016 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, 2010, 2009 and 2008 were $139 million, $130 million, and $121 million, respectively.

In addition to the PHI Service Company charges described above, DPL’s financial statements include the following related party transactions in its statements of income:

	For the Year Ended December 31,
	2010			2009			2008
	(millions of dollars)
(Expense) Income
Purchased power under Default Electricity Supply contracts with Conectiv Energy Supply, Inc. (a)(e)	$	(103	)	$	(88	)	$	(180	)
Intercompany lease transactions (b)		7			7			7
Transcompany pipeline gas sales with Conectiv Energy Supply, Inc. (c)(e)		—			—			1
Transcompany pipeline gas purchases with Conectiv Energy Supply, Inc. (d)(e)		(1	)		(1	)		(3	)

(a) Included in purchased energy expense.

(b) Included in electric revenue.

(c) Included in gas revenue.

(d) Included in gas purchased expense.

(e) During 2010, PHI sold Conectiv Energy’s wholesale power generation business.

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DPL

As of December 31, 2010 and 2009, DPL had the following balances on its balance sheets due (to) from related parties:

	2010			2009
	(millions of dollars)
(Liability) Asset
(Payable to) Receivable from Related Party (current) (a)
PHI Service Company	$	(19	)	$	22
PHI Parent Company		—			(27	)
Conectiv Energy Supply, Inc.		(13	)		(7	)
Pepco Energy Services, Inc. and its subsidiaries (Pepco Energy Services) (b)		(2	)		(3	)
Other		—			1
Total	$	(34	)	$	(14	)
Money Pool Balance with Pepco Holdings (included in Cash and cash equivalents)	$	63		$	—

(a) These amounts are included in the “Accounts payable due to associated companies” balances on the balance sheets.

(b) DPL bills customers on behalf of Pepco Energy Services where customers have selected Pepco Energy Services as their alternative energy supplier.

(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.

	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
	2009
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(millions of dollars)
Total Operating Revenue	$	452		$	291		$	339		$	321		$	1,403
Total Operating Expenses		408			274			321			290			1,293
Operating Income		44			17			18			31			110
Other Expenses		(11	)		(10	)		(11	)		(10	)		(42	)
Income Before Income Tax Expense		33			7			7			21			68
Income Tax Expense (Benefit)		12			2			(7	)(b)		9			16
Net Income	$	21		$	5		$	14		$	12		$	52

(a) Includes restructuring charges of $4 million and $4 million in the third and fourth quarters, respectively.

(b) Includes benefit of $11 million net of fees related to a change in the Maryland state income tax reporting for the disposition of certain assets in prior years.

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DPL

(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 is repositioning itself as a regulated transmission and distribution company. In connection with this repositioning, 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 that are allocated to its operating segments. This review has resulted in the adoption of a restructuring plan. PHI began implementing the plan during the third quarter, identifying 164 employee positions that were to be eliminated during the fourth quarter of 2010. The plan also focuses on identifying additional cost reduction opportunities through process improvements and operational efficiencies.

In connection with the restructuring plan, DPL recorded a pre-tax restructuring charge of $8 million for the year ended December 31, 2010 related to its allocation of severance, pension, and health and welfare benefits for terminations of corporate services employees at PHI. 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 has been reflected as a separate line item in the statements of income.

A reconciliation of DPL’s accrued restructuring charges for the year ended December 31, 2010 is as follows:

	Year Ended December 31, 2010 (a)
	(millions of dollars)
Beginning balance as of January 1, 2010	$	—
Restructuring charge		8
Cash payments		(1	)
Ending balance as of December 31, 2010	$	7

(a) Excludes restructuring accrual recorded in 1999 related to the expense of the excess of the net present value of water-supply capacity leased from Merrill Creek reservoir over the electric generating facility’s requirements. The remaining accrual of $16 million as of December, 31 2010 is being amortized over the remaining term of the lease, which expires in 2032.

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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) under the Securities Exchange Act of 1934, as amended. 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 assessed its internal control over financial reporting as of December 31, 2010 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, 2010.

289

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, 2010 and December 31, 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the consolidated 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 24, 2011

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ACE

ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME

For the Year Ended December 31,	2010			2009			2008
	(millions of dollars)
Operating Revenue	$	1,430		$	1,351		$	1,633
Operating Expenses
Purchased energy		1,030			1,076			1,178
Other operation and maintenance		204			190			183
Restructuring charge		6			—			—
Depreciation and amortization		112			102			104
Other taxes		26			21			24
Deferred electric service costs		(108	)		(161	)		(9	)
Total Operating Expenses		1,270			1,228			1,480
Operating Income		160			123			153
Other Income (Expenses)
Interest and dividend income		—			—			1
Interest expense		(65	)		(67	)		(62	)
Other income		1			2			3
Other expenses		—			—			(1	)
Total Other Expenses		(64	)		(65	)		(59	)
Income Before Income Tax Expense		96			58			94
Income Tax Expense		43			17			30
Net Income	$	53		$	41		$	64

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

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ACE

ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

ASSETS	December 31, 2010			December 31, 2009
	(millions of dollars)
CURRENT ASSETS
Cash and cash equivalents	$	4		$	7
Restricted cash equivalents		11			10
Accounts receivable, less allowance for uncollectible accounts of $11 million and $7 million, respectively		212			176
Inventories		17			15
Prepayments of income taxes		55			38
Income taxes receivable		25			1
Prepaid expenses and other		9			11
Total Current Assets		333			258
INVESTMENTS AND OTHER ASSETS
Regulatory assets		667			712
Prepaid pension expense		51			63
Income taxes receivable		59			76
Restricted cash equivalents		5			4
Assets and accrued interest related to uncertain tax positions		38			57
Other		11			9
Total Investments and Other Assets		831			921
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		2,443			2,328
Accumulated depreciation		(729	)		(699	)
Net Property, Plant and Equipment		1,714			1,629
TOTAL ASSETS	$	2,878		$	2,808

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

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ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

LIABILITIES AND EQUITY	December 31, 2010		December 31, 2009
	(millions of dollars, except shares)
CURRENT LIABILITIES
Short-term debt	$	181	$	83
Current portion of long-term debt		35		35
Accounts payable and accrued liabilities		120		120
Accounts payable due to associated companies		29		58
Taxes accrued		7		5
Interest accrued		13		13
Other		41		42
Total Current Liabilities		426		356
DEFERRED CREDITS
Regulatory liabilities		71		178
Deferred income taxes, net		659		604
Investment tax credits		8		9
Other postretirement benefit obligations		27		25
Other		13		11
Total Deferred Credits		778		827
LONG-TERM LIABILITIES
Long-term debt		633		609
Transition Bonds issued by ACE Funding		332		368
Total Long-Term Liabilities		965		977
COMMITMENTS AND CONTINGENCIES (NOTE 14 )
REDEEMABLE SERIAL PREFERRED STOCK		6		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		516		473
Retained earnings		161		143
Total Equity		703		642
TOTAL LIABILITIES AND EQUITY	$	2,878	$	2,808

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

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ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Year Ended December 31,	2010			2009			2008
	(millions of dollars)
OPERATING ACTIVITIES
Net income	$	53		$	41		$	64
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		112			102			104
Deferred income taxes		49			53			166
Investment tax credit adjustments		(1	)		(1	)		(1	)
Changes in:
Accounts receivable		(35	)		19			3
Inventories		(2	)		—			(1	)
Prepaid expenses		5			(5	)		1
Regulatory assets and liabilities, net		(107	)		(183	)		(43	)
Accounts payable and accrued liabilities		(24	)		43			10
Pension contributions		—			(60	)		—
Prepaid pension expense, excluding contributions		12			3			2
Taxes accrued		(10	)		(6	)		(159	)
Interest accrued		—			(1	)		1
Other assets and liabilities		7			(13	)		6
Net Cash From (Used By) Operating Activities		59			(8	)		153
INVESTING ACTIVITIES
Investment in property, plant and equipment		(156	)		(141	)		(162	)
DOE capital reimbursement awards received		2			—			—
Proceeds from sale of assets		—			—			1
Changes in restricted cash equivalents		(3	)		1			(1	)
Net other investing activities		—			(1	)		1
Net Cash Used By Investing Activities		(157	)		(141	)		(161	)
FINANCING ACTIVITIES
Dividends paid to Parent		(35	)		(64	)		(46	)
Capital contribution from Parent		43			129			35
Issuances of long-term debt		23			—			250
Reacquisitions of long-term debt		(35	)		(32	)		(136	)
Issuances (repayments) of short-term debt, net		98			60			(29	)
Net other financing activities		1			(2	)		(8	)
Net Cash From Financing Activities		95			91			66
Net (Decrease) Increase In Cash and Cash Equivalents		(3	)		(58	)		58
Cash and Cash Equivalents at Beginning of Year		7			65			7
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	4		$	7		$	65
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for interest (net of capitalized interest of $2 million for each year presented)	$	61		$	65		$	58
Cash paid (received) for income taxes		10			(42	)		21

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

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ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF EQUITY

					Premium on Stock		Retained Earnings			Total
(millions of dollars, except shares)	Common Stock
	Shares		Par Value
BALANCE, DECEMBER 31, 2007		8,546,017	$	26	$	309	$	142		$	477
Net Income		—		—		—		64			64
Dividends:
Common stock		—		—		—		(46	)		(46	)
Transfer of deferred income tax liabilities to Parent		—		—		—		6			6
Capital contribution from Parent		—		—		35		—			35
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

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

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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, 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 ACE Transition 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 a 20% to 50% voting interest and cannot exercise control over the operations and policies of the investee. 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, 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 the loss is determined to be probable and is reasonably estimable.

Restructuring Charges

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.

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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. In the first half of 2010, ACE recorded an increase in transmission service revenue of $6 million that was then estimated to be collected over the 2010-2011 service year for costs incurred in the 2009 service year. In the fourth quarter of 2010, ACE recorded a decrease in transmission service revenue of $1 million that it estimates will be reflected as a reduction in transmission service rates for the 2011-2012 service year based on costs incurred during the first seven months of the 2010 service year. ACE will update its estimate of the reduction in transmission service revenue for the 2011-2012 service year in the first and second quarters of 2011 as it progresses toward the completion of the 2010-2011 service year and final cost information from the 2010-2011 service year becomes available. In the second quarter of 2011, ACE expects to record a true-up as part of its updated transmission service rates that are submitted to FERC.

Revenue Recognition

ACE recognizes revenue upon distribution of electricity to its customers, including amounts for electricity delivered but not yet billed (unbilled revenue). ACE recorded amounts for unbilled revenue of $51 million and $42 million as of December 31, 2010 and 2009, respectively. 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 judgements 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 revenues. Accruals for 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.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in ACE’s gross revenues were $23 million, $22 million and $22 million for the years ended December 31, 2010, 2009 and 2008, 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.

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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 Assets and Regulatory Liabilities,” 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 under or over payments 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

In accordance with FASB guidance on the consolidation of variable interest entities (Accounting Standards Codification (ASC) 810), ACE consolidates those variable interest entities with respect to which ACE is the primary beneficiary. The guidance addresses conditions under which an entity should be consolidated based upon variable interests rather than voting interests.

ACE Power Purchase Agreements (PPAs)

ACE is party to three PPAs with unaffiliated, non-utility generators (NUGs). Due to a variable element in the pricing structure of the PPAs, ACE potentially assumes the variability in the operations of the generating facilities related to the NUGs and, therefore, has a variable interest in the entities. Despite exhaustive efforts to obtain information from these entities during 2010, ACE continues to be unable to obtain sufficient information to conduct the analysis required under FASB guidance to determine whether these three entities were variable interest entities or if ACE was the primary beneficiary. As a result, ACE has applied the scope exemption from the guidance for enterprises that have conducted exhaustive efforts to obtain the necessary information, but have not been able to obtain such information.

Net purchase activities with the NUGs for the years ended December 31, 2010, 2009 and 2008, were approximately $292 million, $282 million and $349 million, respectively, of which approximately $270 million, $262 million and $305 million, respectively, consisted of power purchases under the PPAs. The power purchase costs are recoverable from ACE’s customers through regulated rates.

ACE Transition Funding, LLC

ACE 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 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

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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 has consolidated ACE Funding in its financial statements. An amendment to the variable interest entity consolidation guidance effective January 1, 2010 resulted in ACE Funding meeting the definition of a variable interest entity. ACE continued to consolidate ACE Funding in its financial statements upon the effective date of the amended variable interest entity consolidation guidance as ACE is the primary beneficiary of ACE Funding under the amended variable interest entity consolidation guidance.

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 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.

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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 rate for 2010, 2009 and 2008 for ACE’s transmission and distribution system property was approximately 2.8%.

In 2010, ACE received an award from the U.S. Department of Energy (DOE) 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 for each of the years ended December 31, 2010, 2009 and 2008.

ACE recorded amounts for the equity component of AFUDC of zero, $1 million, and $1 million for the years ended December 31, 2010, 2009 and 2008, respectively.

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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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 a non-contributory retirement plan that covers substantially all employees of ACE (the PHI Retirement Plan) 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 $161 million and $143 million of retained earnings available for payment of common stock dividends at December 31, 2010 and 2009, 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 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 for the year ended December 31, 2010.

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 for the year ended December 31, 2009.

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Operating Expenses

During 2008, PHI identified an error in the accounting for certain of its restricted stock awards under the Long-Term Incentive Plan which resulted in an understatement of ACE’s stock-based compensation expense in 2006 and 2007. This error was corrected in 2008, resulting in an increase in ACE’s Other operation and maintenance expenses for the year ended December 31, 2008 of $1 million.

(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Transfers and Servicing (ASC 860)

The FASB issued new guidance that removes the concept of a qualifying special-purpose entity (QSPE) from the guidance on transfers and servicing and the QSPE scope exception in the guidance on consolidation. The new guidance also changes the requirements for derecognizing financial assets and requires additional disclosures about a transferor’s continuing involvement in transferred financial assets. The guidance was effective for transfers of financial assets occurring in fiscal periods beginning on January 1, 2010 for ACE. This guidance did not have a material impact on ACE’s overall financial condition, results of operations, or cash flows.

Fair Value Measurement and Disclosures (ASC 820)

The FASB issued new disclosure requirements for recurring and non-recurring fair value measurements. The guidance, effective beginning with ACE’s March 31, 2010 financial statements, requires the disaggregation of balance sheet items measured at fair value into subsets of balance sheet items based on the nature and risks of the items. The standard requires descriptions of pricing inputs and valuation methodologies for instruments with Level 2 or 3 valuation inputs. In addition, the standard requires information about any significant transfers of instruments between Level 1 and 2 valuation categories. These additional disclosures are included in Note (13), “Fair Value Disclosures.”

Consolidation of Variable Interest Entities (ASC 810)

The FASB issued new consolidation guidance regarding variable interest entities effective January 1, 2010 that eliminates the quantitative analysis requirement and adds new qualitative factors to determine whether consolidation is required. The new qualitative factors are applied on a quarterly basis to interests in variable interest entities. Under the new guidance, the holder of the interest with the power to direct the most significant activities of the entity and the right to receive benefits or absorb losses significant to the entity would consolidate. The new guidance retains the provision that allows entities created before December 31, 2003 to be scoped out from a consolidation assessment if exhaustive efforts are taken and there is insufficient information to determine whether there is a relationship with a variable interest entity or the primary beneficiary of a variable interest entity. This guidance did not have a material impact on ACE’s overall financial condition, results of operations, or cash flows.

Subsequent Events (ASC 855)

The FASB issued new guidance that eliminates the requirement for ACE to disclose the date through which it has evaluated subsequent events beginning with its March 31, 2010 financial statements.

(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Fair Value Measurement and Disclosures (ASC 820)

The FASB issued new disclosure requirements that require the disaggregation of the Level 3 fair value measurement reconciliations into separate categories for significant purchases, sales, issuances, and settlements. This requirement is effective beginning with ACE’s March 31, 2011 financial statements. ACE is evaluating the impact of this new guidance on its financial statement footnote disclosures.

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(5) SEGMENT INFORMATION

The company operates its business as one regulated utility segment, which includes all of its services as described above.

(6) REGULATORY ASSETS AND REGULATORY LIABILITIES

The components of ACE’s regulatory asset and liability balances at December 31, 2010 and 2009 are as follows:

	2010		2009
	(millions of dollars)
Regulatory Assets
Securitized stranded costs (a)	$	559	$	620
Deferred income taxes		29		27
Deferred energy supply costs (a)		31		12
Deferred debt extinguishment costs (a)		12		13
Other		36		40
Total Regulatory Assets	$	667	$	712
Regulatory Liabilities
Excess depreciation reserve	$	42	$	58
Federal and New Jersey tax benefits, related to securitized stranded costs		22		25
Deferred energy supply costs		—		89
Other		7		6
Total Regulatory Liabilities	$	71	$	178

(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 non-utility generator 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, by ACE Funding, Transition Bonds. 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 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.

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 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.

Other: Represents miscellaneous regulatory assets that generally are being amortized over 1 to 20 years.

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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.

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 issues its final regulations with respect to normalization of these federal excess deferred taxes.

Other: Includes miscellaneous regulatory liabilities.

(7) LEASING ACTIVITIES

ACE leases certain types of property and equipment for use in its operations. Rental expense for operating leases was $9 million for each of the years ended December 31, 2010, 2009 and 2008.

Total future minimum operating lease payments for ACE as of December 31, 2010 are $4 million in 2011, $4 million in 2012, $3 million in each of the years 2013 through 2015, 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, 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
At December 31, 2009
Generation	$	10	$	9	$	1
Distribution		1,413		420		993
Transmission		651		182		469
Construction work in progress		94		—		94
Non-operating and other property		160		88		72
Total	$	2,328	$	699	$	1,629

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.

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Jointly Owned Plant

ACE’s consolidated balance sheets include its proportionate share of assets and liabilities related to jointly owned plant. At December 31, 2010 and 2009, ACE’s subsidiaries had a $9 million net book value ownership interest 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 the Pepco Holdings benefit plans as participation in a multi-employer plan. For 2010, 2009, and 2008, ACE was responsible for $23 million, $20 million and $12 million, respectively, of the pension and other postretirement net periodic benefit cost incurred by Pepco Holdings. ACE made discretionary tax-deductible contributions of $60 million to the PHI Retirement Plan for the year ended December 31, 2009. No contributions were made for the years ended December 31, 2010 and 2008. In addition, ACE made contributions of $8 million, $6 million and $7 million, respectively, to the other postretirement benefit plans for the years ended December 31, 2010, 2009 and 2008. At December 31, 2010 and 2009, ACE’s Prepaid pension expense of $51 million and $63 million, and Other postretirement benefit obligations of $27 million and $25 million, respectively, effectively represent assets and benefit obligations resulting from ACE’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, 2010 and 2009 is presented below.

Type of Debt	Interest Rate	Maturity		2010			2009
				(millions of dollars)
First Mortgage Bonds
	7.25% - 7.63%		2010-2014	$	7		$	8
	6.63%		2013		69			69
	7.68%		2015-2016		17			17
	7.75%		2018		250			250
	6.80% (a)		2021		39			39
	5.60% (a)		2025		4			4
	4.875% (a)(b)		2029		23			—
	5.80% (a)(b)		2034		120			120
	5.80% (a)(b)		2036		105			105
Total long-term debt					634			612
Net unamortized discount					(1	)		(2	)
Current portion of long-term debt					—			(1	)
Total net long-term debt				$	633		$	609
Transition Bonds Issued by ACE Funding
	4.21%		2013	$	9		$	34
	4.46%		2016		39			49
	4.91%		2017		118			118
	5.05%		2020		54			54
	5.55%		2023		147			147
					367			402
Net unamortized discount					—			—
Current portion of long-term debt					(35	)		(34	)
Total net long-term Transition Bonds Issued by ACE Funding				$	332		$	368

(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.

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, 2010, that will mature in each of 2011 through 2015 and thereafter is as follows: $35 million in 2011, $37 million in 2012, $108 million in 2013, $48 million in 2014, $59 million in 2015, and $714 million thereafter.

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ACE’s long-term debt is subject to certain covenants. As of December 31, 2010, ACE is in compliance with all such covenants.

Tax-Exempt Bonds

In 2010, ACE resold $23 million of 4.875% Pollution Control Revenue Refunding Bonds due 2029, issued by The Pollution Control Financing Authority of Salem County for the benefit of ACE. The bonds had been repurchased by ACE in 2008 in response to the disruption in the tax-exempt bond market.

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, 2010 and 2009 is as follows:

	2010		2009
	(millions of dollars)
Commercial paper	$	158	$	60
Variable rate demand bonds		23		23
Total	$	181	$	83

Commercial Paper

ACE maintains an ongoing commercial paper program of up to $250 million. The commercial paper notes can be issued with maturities up to 270 days from the date of issue. The commercial paper program is backed by ACE’s borrowing capacity under PHI’s $1.5 billion credit facility described below under the heading “Credit Facility.”

ACE had $158 million and $60 million of commercial paper outstanding at December 31, 2010 and 2009, respectively. The weighted average interest rates for commercial paper issued during 2010 and 2009 were 0.36% and 0.63%, respectively. The weighted average maturity of all commercial paper issued by ACE during 2010 and 2009 was seven days and eight 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 the 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 2010 mature as follows: 2014 ($19 million) and 2017 ($4 million). The weighted average interest rate for VRDBs was 0.27% and 0.81% during 2010 and 2009, respectively.

The Pollution Control Financing Authority of Salem County has issued for the benefit of ACE tax-exempt VRDBs in the aggregate principal of $23 million. In June 2009, ACE completed the remarketing of these VRDBs supported by letters of credit issued by The Bank of New York Mellon. In June 2010, ACE (i) replaced the letter of credit associated with $18.2 million of Pollution Control Revenue Refunding Bonds, 1997 Series A (Atlantic City Electric Company Project) due 2014 with a new irrevocable direct pay letter of credit expiring in April 2014, and (ii) replaced the letter of credit associated with $4.4 million of Pollution Control Revenue Refunding Bonds, 1997 Series B (Atlantic City Electric Company Project) due 2017 with a new irrevocable direct pay letter of credit expiring in June 2014.

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Credit Facility

PHI, Potomac Electric Power Company (Pepco), Delmarva Power & Light Company (DPL) and ACE maintain an unsecured credit facility to provide for their respective short-term liquidity needs. The aggregate borrowing limit under the facility is $1.5 billion, all or any portion of which may be used to obtain loans or to issue letters of credit. PHI’s credit limit under the facility is $875 million. The credit limit of each of Pepco, DPL and ACE is the lesser of $500 million and the maximum amount of debt the company is permitted to have outstanding by its regulatory authorities, except that the aggregate amount of credit used by Pepco, DPL and ACE at any given time collectively may not exceed $625 million. 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 and the federal funds effective rate plus 0.5%, or (ii) the prevailing Eurodollar rate, plus a margin that varies according to the credit rating of the borrower. 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 $150 million. Any swingline loan must be repaid by the borrower within seven days of receipt thereof.

The facility commitment expiration date is May 5, 2012, with each company having the right to elect to have 100% of the principal balance of the loans outstanding on the expiration date continued as non-revolving term loans for a period of one year from such expiration date.

The facility is intended to serve primarily as a source of liquidity to support the commercial paper programs of the respective companies. The companies are also permitted to use the facility to borrow funds for general corporate purposes and issue letters of credit. 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 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 excludes from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) a restriction on sales or other dispositions of assets, other than certain sales and dispositions, 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 absence of a material adverse change in the borrower’s business, property and results of operations or financial condition is not a condition to the availability of credit under the facility. The facility does not include any rating triggers. As of December 31, 2010, each borrower was in compliance with the covenants of the credit facility.

At December 31, 2010 and 2009, the amount of cash, plus borrowing capacity under the PHI credit facilities available to meet the liquidity needs of PHI’s utility subsidiaries was $462 million and $582 million, respectively.

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(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.

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,
	2010			2009			2008
	(millions of dollars)
Current Tax Benefit
Federal	$	(5	)	$	(32	)	$	(98	)
State and local		—			(3	)		(37	)
Total Current Tax Benefit		(5	)		(35	)		(135	)
Deferred Tax Expense (Benefit)
Federal		33			42			121
State and local		16			11			45
Investment tax credit amortization		(1	)		(1	)		(1	)
Total Deferred Tax Expense		48			52			165
Total Consolidated Income Tax Expense	$	43		$	17		$	30

Reconciliation of Consolidated Income Tax Expense

	For the Year Ended December 31,
	2010					2009					2008
	(millions of dollars)
Income tax at Federal statutory rate	$	33		35.0	%	$	20		35.0	%	$	33		35.0	%
Increases (decreases) resulting from
State income taxes, net of Federal effect		7		7.3	%		5		8.6	%		7		7.4	%
Tax credits		(1	)	(1.0	)%		(1	)	(1.7	)%		(1	)	(1.1	)%
Change in estimates and interest related to uncertain and effectively settled tax positions		5		5.2	%		(5	)	(8.6	)%		(13	)	(13.8	)%
Deferred tax adjustments		—		—			—		—			7		7.4	%
Adjustments to prior year’s taxes		—		—			(1	)	(1.7	)%		(2	)	(2.1	)%
Other, net		(1	)	(1.7	)%		(1	)	(2.3	)%		(1	)	(0.9	)%
Consolidated Income Tax Expense	$	43		44.8	%	$	17		29.3	%	$	30		31.9	%

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ACE

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. 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, ACE has recalculated the estimated interest due for the tax years 1996 to 2002. The revised estimate has 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 has been recorded in the fourth quarter of 2010 and is subject to adjustment when the IRS finalizes its calculation of the amount due. In addition to this adjustment, 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.

In March 2009, the IRS issued a Revenue Agent’s Report (RAR) 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 RAR.

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.

During 2008, ACE completed an analysis of its current and deferred income tax accounts and, as a result, recorded a $7 million charge to income tax expense in 2008, which is included in “Deferred tax adjustments” in the reconciliation provided above. Also identified as part of the analysis were new uncertain tax positions for ACE under FASB guidance on income taxes (ASC 740) (primarily representing overpayments of income taxes in previously filed tax returns) that resulted in the recording of after-tax net interest income of $4 million, which is included as a reduction of income tax expense.

In addition, during 2008, ACE recorded additional after-tax net interest income of $10 million under FASB guidance on income taxes (ASC 740) primarily related to the reversal of previously accrued interest payable resulting from a favorable tentative settlement of the mixed service cost issue with the IRS, and a claim made with the IRS related to the tax reporting of fuel over- and under-recoveries.

Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits

	2010			2009			2008
	(millions of dollars)
Beginning balance as of January 1,	$	39		$	49		$	152
Tax positions related to current year:
Additions		50			1			1
Reductions		(1	)		—			—
Tax positions related to prior years:
Additions		—			10			40
Reductions		(5	)		(21	)		(144	)
Settlements		—			—			—
Ending balance as of December 31,	$	83		$	39		$	49

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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, 2010, ACE had $2 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, 2010, 2009 and 2008, ACE recognized $8 million of pre-tax interest expense ($5 million after-tax), $9 million of pre-tax interest income ($6 million after-tax), and $24 million of pre-tax interest income ($14 million after-tax), respectively, as a component of income tax expense. As of December 31, 2010, 2009 and 2008, ACE had $14 million, $19 million and $13 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 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.

Components of Consolidated Deferred Income Tax Liabilities (Assets)

	As of December 31,
	2010		2009
	(millions of dollars)
Deferred Tax Liabilities (Assets)
Depreciation and other basis differences related to plant and equipment	$	389	$	321
Deferred taxes on amounts to be collected through future rates		14		12
Payment for termination of purchased power contracts with NUGs		59		64
Electric restructuring liabilities		160		180
Fuel and purchased energy		7		7
Other		20		13
Total Deferred Tax Liabilities, net		649		597
Deferred tax assets included in Other Current Assets		10		7
Total Consolidated Deferred Tax Liabilities, net - non-current	$	659	$	604

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ACE

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, 2010 and 2009.

The Tax Reform Act of 1986 repealed the investment tax credit (ITC) for property placed in service after December 31, 1985, except for certain transition property. ITC previously earned on ACE’s property continues to be amortized to income over the useful lives of the related property.

Other Taxes

Taxes other than income taxes for each year are shown below. These amounts are recoverable through rates.

	2010		2009			2008
	(millions of dollars)
Gross Receipts/Delivery	$	20	$	20		$	21
Property		3		2			2
Environmental, Use and Other		3		(1	)		1
Total	$	26	$	21		$	24

(12) PREFERRED STOCK

The preferred stock amounts outstanding as of December 31, 2010 and 2009 are as follows:

	Redemption Price		Shares Outstanding				December 31,
			2010		2009		2010		2009
							(millions of dollars)
4.0% Series of 1944, $100 per share par value	$	105.50		24,268		24,268	$	2	$	2
4.35% Series of 1949, $100 per share par value	$	101.00		2,942		2,942		—		—
4.35% Series of 1953, $100 per share par value	$	101.00		1,680		1,680		—		—
4.10% Series of 1954, $100 per share par value	$	101.00		20,504		20,504		2		2
4.75% Series of 1958, $100 per share par value	$	101.00		8,631		8,631		1		1
5.0% Series of 1960, $100 per share par value	$	100.00		4,120		4,120		1		1
Total Preferred Stock				62,145		62,145	$	6	$	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. On January 26, 2011, ACE called for the redemption of all of its outstanding cumulative preferred stock at the redemption prices listed in the table above. The transaction will close on February 25, 2011.

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ACE

(13) FAIR VALUE DISCLOSURES

Fair Value of Assets and Liabilities Excluding Issued Debt and Equity Instruments

ACE has adopted FASB guidance on fair value measurement and disclosures (ASC 820) which 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:

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 their fair value is based on the fair value of the assets underlying the policies. The underlying assets of these life insurance policies consist of short-term cash equivalents and fixed income securities that are priced using observable market data. 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, 2010 and 2009. 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.

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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
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.

	Fair Value Measurements at December 31, 2009
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Cash equivalents
Treasury Fund	$	17	$	17	$	—	$	—
	$	17	$	17	$	—	$	—
LIABILITIES
Executive deferred compensation plan liabilities
Life Insurance Contracts	$	1	$	—	$	1	$	—
	$	1	$	—	$	1	$	—

Fair Value of Debt and Equity Instruments

The estimated fair values of ACE’s issued debt and equity instruments at December 31, 2010 and 2009 are shown below:

	December 31, 2010				December 31, 2009
	(millions of dollars)
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	633	$	710	$	610	$	674
Transition Bonds issued by ACE Funding		367		406		402		427
Redeemable Serial Preferred Stock		6		5		6		4

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ACE

The fair value of long-term debt issued by ACE was based on actual trade prices as of December 31, 2010 and 2009, or a discounted cash flow model where actual trade prices were not available. The fair values of Transition Bonds issued by ACE Funding, including amounts due within one year, were derived based on bid prices obtained from brokers where 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

Regulatory and Other Matters

Rate Proceedings

Over the last several years, ACE has proposed the adoption of mechanisms to decouple retail distribution revenue from the amount of power delivered to retail customers. At this time, a BSA is pending for ACE 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 BSA increases rates if actual distribution revenues fall below the approved level and decreases rates if actual distribution revenues are above the approved level. The result is that, over time, ACE collects its authorized revenues for distribution service. As a consequence, a BSA “decouples” distribution revenue from unit sales consumption and ties the growth in distribution revenues to the growth in the number of customers. Some advantages of the BSA are that it (i) eliminates revenue fluctuations due to weather and changes in customer usage patterns and, therefore, provides for more predictable distribution revenues that are better aligned with costs, (ii) provides for more reliable fixed-cost recovery, (iii) tends to stabilize customers’ delivery bills, and (iv) removes any disincentives for ACE to promote energy efficiency programs for their customers, because it breaks the link between overall sales volumes and distribution revenues.

Environmental Litigation

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. In addition, federal and state statutes authorize governmental agencies to compel responsible parties to clean up certain abandoned or unremediated hazardous waste sites. ACE 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. Although penalties assessed for violations of environmental laws and regulations are not recoverable from ACE’s customers, environmental clean-up costs incurred by ACE would be included in its cost of service for ratemaking purposes.

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 with respect to the site. If liable, ACE would be responsible for reimbursing EPA for clean-up costs incurred and to be incurred by the agency 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

315

ACE

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 cost for future response measures will be approximately $6 million. ACE understands 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.

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. With the court’s permission, the plaintiffs filed amended complaints in September 2009. ACE, as part of a group of defendants, filed a motion to dismiss in October 2009. In a March 24, 2010 order, the court denied the defendants’ motion to dismiss. Although it is too early in the process to characterize the magnitude of the potential liability at this site, ACE does not believe that it had extensive business transactions, if any, with the Ward Transformer site.

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 National Priorities List (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. 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. 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 at the site as the owner of a facility on which a hazardous substance has been deposited. ACE currently is engaged in settlement negotiations with NJDEP and EPA to resolve its alleged liability at the site by donating property to NJDEP and by making a payment in an amount to be determined. Costs incurred by ACE to resolve this matter are not expected to be material.

Appeal of New Jersey Flood Hazard Regulations. In November 2007, NJDEP adopted amendments to the agency’s regulations under the Flood Hazard Area Control Act (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. In November 2008, ACE filed an appeal of these regulations with the Appellate Division of the Superior Court of New Jersey. The grounds for ACE’s appeal include the lack of administrative record justification for the FHACA regulations and conflict between the FHACA regulations and other state and federal regulations and standards for maintenance of electric power transmission and distribution facilities. The matter was argued before the Appellate Division on January 3, 2011 and the decision of the court is pending.

316

ACE

Contractual Obligations

As of December 31, 2010, ACE’s contractual obligations under non-derivative fuel and power purchase contracts were $284 million in 2011, $572 million in 2012 to 2013, $575 million in 2014 to 2015, and $2,144 million in 2016 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, 2010, 2009 and 2008 were $100 million, $100 million and $94 million, respectively.

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,
	2010	2009				2008
	(millions of dollars)
(Expense) Income
Purchased power under Default Electricity Supply contracts with Conectiv Energy Supply, Inc. (a)(d)	$(174)		$	(185	)	$	(171	)
Meter reading services provided by Millennium Account Services LLC (b)	(4)			(4	)		(4	)
Intercompany use revenue (c)	2			3			—

(a) Included in purchased energy expense.

(b) Included in other operation and maintenance expense.

(c) Included in operating revenue.

(d) During 2010, PHI sold Conectiv Energy’s wholesale power generation business.

As of December 31, 2010 and 2009, ACE had the following balances on its balance sheets due to related parties:

	2010			2009
	(millions of dollars)
Liability
Payable to Related Party (current) (a)
PHI Service Company	$	(13	)	$	(38	)
PHI Parent Company		—			(3	)
Conectiv Energy Supply, Inc.		(14	)		(15	)
Other		(2	)		(2	)
Total	$	(29	)	$	(58	)

(a) These amounts are included in the “Accounts payable due to associated companies” balances on the consolidated balance sheets.

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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.

	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
	2009
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(millions of dollars)
Total Operating Revenue	$	344		$	287		$	441		$	279		$	1,351
Total Operating Expenses		328			258			387			255			1,228
Operating Income		16			29			54			24			123
Other Expenses		(16	)		(17	)		(16	)		(16	)		(65	)
Income Before Income Tax Expense		—			12			38			8			58
Income Tax (Benefit) Expense		(2	)		4			15			—	(c)		17
Net Income	$	2		$	8		$	23		$	8		$	41

(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.

(c) Includes $2 million benefit related to the resolution of an uncertain state income tax position.

(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 is repositioning itself as a regulated transmission and distribution company. In connection with this repositioning, 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 that are allocated to its operating segments. This review has resulted in the adoption of a restructuring plan. PHI began implementing the plan during the third quarter, identifying 164 employee positions that were to be eliminated during the fourth quarter of 2010. The plan also focuses on identifying additional cost reduction opportunities through process improvements and operational efficiencies.

In connection with the restructuring plan, ACE recorded a pre-tax restructuring charge of $6 million for the year ended December 31, 2010 related to its allocation of severance, pension, and health and welfare benefits for terminations of corporate services employees at PHI. 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 has been reflected as a separate line item in the consolidated statements of income.

318

ACE

A reconciliation of ACE’s accrued restructuring charges for the year ended December 31, 2010 is as follows:

	Year Ended December 31, 2010
	(millions of dollars)
Beginning balance as of January 1, 2010	$	—
Restructuring charge		6
Cash payments		—
Ending balance as of December 31, 2010	$	6

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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

Pepco Holdings, Inc.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Under the supervision, and with the participation of management, including the chief executive officer and the chief financial officer, Pepco Holdings has evaluated the effectiveness of the design and operation of its disclosure controls and procedures as of December 31, 2010, and, based upon this evaluation, the chief executive officer and the chief financial officer of Pepco Holdings have concluded that these controls and procedures are effective to provide reasonable assurance that material information relating to Pepco Holdings and its subsidiaries that is required to be disclosed in reports filed with, or submitted to, the Securities and Exchange Commission (SEC) under the Securities Exchange Act of 1934, as amended (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 chief executive officer and chief financial officer, 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” in Part II, Item 8 of this Form 10-K.

Attestation Report of the Registered Public Accounting Firm

See “Report of Independent Registered Public Accounting Firm” in Part II, Item 8 of this Form 10-K.

Changes in Internal Control over Financial Reporting

During the quarter ended December 31, 2010, there was no change in Pepco Holdings’ internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, Pepco Holdings’ internal controls over financial reporting.

In October 2010, Pepco, a regulated subsidiary of PHI, began activation of the Advanced Metering Infrastructure (AMI) in its District of Columbia service territory, which remotely collects customer meter data for billing and other purposes. Pepco’s activation process in the District of Columbia is expected to continue through December 2011.

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Potomac Electric Power Company

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Under the supervision, and with the participation of management, including the chief executive officer and the chief financial officer, Pepco has evaluated the effectiveness of the design and operation of its disclosure controls and procedures as of December 31, 2010, and, based upon this evaluation, the chief executive officer and the chief financial officer of Pepco have concluded that these controls and procedures are effective to provide reasonable assurance that material information relating to Pepco 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 chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act)

The Dodd-Frank 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 the 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, Pepco is exempt from the requirement that it include in its Annual Report on Form 10-K an attestation report on internal control over financial reporting by an independent registered public accounting firm; however, management’s annual report on internal control over financial reporting, pursuant to Section 404(a) of the Sarbanes-Oxley Act, is still required.

Management’s Annual Report on Internal Control over Financial Reporting

See “Management’s Report on Internal Control over Financial Reporting” in Part II, Item 8 of this Form 10-K.

Changes in Internal Control over Financial Reporting

During the quarter ended December 31, 2010, there was no change in Pepco’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, Pepco’s internal controls over financial reporting.

In October 2010, Pepco began activation of the Advanced Metering Infrastructure (AMI) in its District of Columbia service territory, which remotely collects customer meter data for billing and other purposes. Pepco’s activation process in the District of Columbia is expected to continue through December 2011.

Delmarva Power & Light Company

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Under the supervision, and with the participation of management, including the chief executive officer and the chief financial officer, DPL has evaluated the effectiveness of the design and operation of its disclosure controls and procedures as of December 31, 2010, and, based upon this evaluation, the chief executive officer and the chief financial officer of DPL have concluded that these controls and procedures are effective to provide reasonable assurance that material information relating to DPL 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 chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

321

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act)

The Dodd-Frank 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 the 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, DPL is exempt from the requirement that it include in its Annual Report on Form 10-K an attestation report on internal control over financial reporting by an independent registered public accounting firm; however, management’s annual report on internal control over financial reporting, pursuant to Section 404(a) of the Sarbanes-Oxley Act, is still required.

Management’s Annual Report on Internal Control over Financial Reporting

See “Management’s Report on Internal Control over Financial Reporting” in Part II, Item 8 of this Form 10-K.

Changes in Internal Control over Financial Reporting

During the quarter ended December 31, 2010, there was no change in DPL’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, DPL’s internal controls over financial reporting.

Atlantic City Electric Company

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Under the supervision, and with the participation of management, including the chief executive officer and the chief financial officer, ACE has evaluated the effectiveness of the design and operation of its disclosure controls and procedures as of December 31, 2010, and, based upon this evaluation, the chief executive officer and the chief financial officer of ACE have concluded that these controls and procedures are effective to provide reasonable assurance that material information relating to ACE and its subsidiary 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 chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act)

The Dodd-Frank 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 the 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, ACE is exempt from the requirement that it include in its Annual Report on Form 10-K an attestation report on internal control over financial reporting by an independent registered public accounting firm; however, management’s annual report on internal control over financial reporting, pursuant to Section 404(a) of the Sarbanes-Oxley Act, is still required.

Management’s Annual Report on Internal Control over Financial Reporting

See “Management’s Report on Internal Control over Financial Reporting” in Part II, Item 8 of this Form 10-K.

Changes in Internal Control over Financial Reporting

During the quarter ended December 31, 2010, there was no change in ACE’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, ACE’s internal controls over financial reporting.

322

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.

The following information to be included in PHI’s definitive proxy statement for the 2011 Annual Meeting, which is expected to be filed with the SEC on or about March 31, 2011, is incorporated herein by reference:

• The information under the heading “Nominees for Election as Directors.”

• The information under the heading “Security Ownership of Certain Beneficial Owners and Management — Section 16(a) Beneficial Ownership Reporting Compliance.”

• The information concerning PHI’s Corporate Business Policies under the heading “Where do I find the Company’s Corporate Business Policies, Corporate Governance Guidelines and Committee Charters?”

• The information regarding the membership and function of the Audit Committee and the financial expertise of its members under the heading “Board Committees — Audit Committee.”

324

Executive Officers of PHI

The names of the executive officers of PHI, their ages and the positions they held as of February 25, 2011, 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.

PEPCO HOLDINGS

Name	Age	Office and Length of Service
Joseph M. Rigby	54	Chairman of the Board 5/09 - Present, President 3/08 - Present, and Chief Executive Officer 3/09 - Present (1)
David M. Velazquez	51	Executive Vice President 3/09 - Present (2)
Kirk J. Emge	61	Senior Vice President and General Counsel 3/08 - Present (3)
Anthony J. Kamerick	63	Senior Vice President and Chief Financial Officer 6/09 - Present (4)
Beverly L. Perry	63	Senior Vice President 10/02 - Present
Ronald K. Clark	55	Vice President and Controller 8/05 - Present
Paul W. Friel	62	Vice President and General Auditor 5/05 - Present
Ernest L. Jenkins	56	Vice President 5/05 – Present
Hallie M. Reese	47	Vice President, PHI Service Company 5/05 - Present
John U. Huffman	51	President 6/06 - Present, and Chief Executive Officer, Pepco Energy Services, Inc. 3/09 - Present (5)

(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.

325

(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) 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 11. EXECUTIVE COMPENSATION

Pepco Holdings, Inc.

The following information to be included in PHI’s definitive proxy statement for the 2011 Annual Meeting, which is expected to be filed with the SEC on or about March 31, 2011, is incorporated herein by reference:

• The information under the heading “2010 Director Compensation.”

• The information under the heading “Compensation Discussion and Analysis.”

• The information under the heading “Executive Compensation.”

• The information under the heading “Compensation/Human Resources Committee Report.”

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.

The information to be included under the heading “Security Ownership of Certain Beneficial Owners and Management” in PHI’s definitive proxy statement for the 2011 Annual Meeting, which is expected to be filed with the SEC on or about March 31, 2011, is incorporated herein by reference.

The following table provides information as of December 31, 2010, with respect to the shares of PHI’s common stock that may be issued under PHI’s existing equity compensation plans.

326

Equity Compensation Plans Information

Plan Category	Number of Securities to be Issued Upon Exercise of Outstanding Options			Weighted-Average Exercise Price of Outstanding Options			Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Outstanding Options)
Equity Compensation Plans Approved by Shareholders (a)		(b	)		(b	)		7,927,210
Equity Compensation Plans Not Approved by Shareholders		—			—			471,562	(c)
Total		—			—			8,398,772

(a) Consists solely of the Pepco Holdings, Inc. Long-Term Incentive Plan.

(b) In connection with the acquisition by Pepco of Conectiv (i) outstanding options granted under the Potomac Electric Power Company Long-Term Incentive Plan were converted into options to purchase shares of PHI common stock and (ii) options granted under the Conectiv Incentive Compensation Plan were converted into options to purchase shares of PHI common stock. As of December 31, 2010, options to purchase an aggregate of 280,266 shares of PHI common stock, having a weighted average exercise price of $22.2996, were outstanding.

(c) Consists of shares of PHI common stock available for future issuance under the PHI Non-Management Directors Compensation Plan. Under this plan, each director who is not an employee of PHI or any of its subsidiaries (“non-management director”) is entitled to elect to receive his or her annual retainer, retainer for service as a committee chairman, if any, and meeting fees in: (i) cash, (ii) shares of PHI’s common stock, (iii) a credit to an account for the director established under PHI’s Executive and Director Deferred Compensation Plan or (iv) any combination thereof. The plan expires on December 31, 2014 unless terminated earlier by the Board of Directors.

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.

The information to be included under the heading “Board Review of Transactions With Related Parties” in PHI’s definitive proxy statement for the 2011 Annual Meeting, which is expected to be filed with the SEC on or about March 31, 2011, is incorporated herein by reference.

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.

327

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 2010 and 2009 fiscal years, reviews of the financial statements included in the 2010 and 2009 Forms 10-Q of Pepco Holdings and its subsidiary reporting companies, reviews of public filings, comfort letters and other attest services were $5,470,329 and $6,290,054, respectively. The amount for 2009 includes $144,638 for the 2009 audit that was billed after the 2009 amount was disclosed in Pepco Holding’s proxy statement for the 2010 Annual Meeting.

Audit-Related Fees

The aggregate fees billed by PricewaterhouseCoopers LLP for audit-related services rendered for the 2010 and 2009 fiscal years were $738,843 and $77,522, respectively. The amount for 2009 audit-related services was billed after the 2009 amount was disclosed in Pepco Holding’s proxy statement for the 2010 Annual Meeting. These services 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 2010 and 2009 fiscal years were $720,731 and $674,359, respectively. The amount for 2009 includes $169,545 that was billed after the 2009 amount was disclosed in Pepco Holding’s proxy statement for the 2010 Annual Meeting. 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 2010 and 2009 fiscal years were $12,500 and $3,000, respectively, which represented 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 2011 Annual Meeting of Shareholders, which is expected to be filed with the SEC on or about March 31, 2011, and is incorporated herein by reference.

328

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, 2010, 2009 and 2008

Consolidated Statements of Comprehensive Income for each of the years ended December 31, 2010, 2009 and 2008

Consolidated Balance Sheets as of December 31, 2010 and 2009

Consolidated Statements of Cash Flows for each of the years ended December 31, 2010, 2009 and 2008

Consolidated Statements of Equity for each of the years ended December 31, 2010, 2009 and 2008

Notes to Consolidated Financial Statements

Potomac Electric Power Company

Statements of Income for each of the years ended December 31, 2010, 2009 and 2008

Balance Sheets as of December 31, 2010 and 2009

Statements of Cash Flows for each of the years ended December 31, 2010, 2009 and 2008

Statements of Equity for each of the years ended December 31, 2010, 2009 and 2008

Notes to Financial Statements

Delmarva Power & Light Company

Statements of Income for each of the years ended December 31, 2010, 2009 and 2008

Balance Sheets as of December 31, 2010 and 2009

Statements of Cash Flows for each of the years ended December 31, 2010, 2009 and 2008

Statements of Equity for each of the years ended December 31, 2010, 2009 and 2008

Notes to Financial Statements

Atlantic City Electric Company

Consolidated Statements of Income for each of the years ended December 31, 2010, 2009 and 2008

Consolidated Balance Sheets as of December 31, 2010 and 2009

Consolidated Statements of Cash Flows for each of the years ended December 31, 2010, 2009 and 2008

Consolidated Statements of Equity for each of the years ended December 31, 2010, 2009 and 2008

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	330	N/A	N/A	N/A
Schedule II, Valuation and Qualifying Accounts	334	334	335	335

329

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,
	2010			2009			2008
	(millions of dollars, except share data)
OPERATING REVENUE	$	—		$	—		$	—
OPERATING EXPENSES
Other operation and maintenance		5			5			5
Total operating expenses		5			5			5
OPERATING LOSS		(5	)		(5	)		(5	)
OTHER INCOME (EXPENSES)
Interest and dividend income		—			—			2
Interest expense		(72	)		(87	)		(90	)
Loss on extinguishment of debt		(189	)		—			—
Income from equity investments		287			278			239
Total other income		26			191			151
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE		21			186			146
INCOME TAX BENEFIT RELATED TO CONTINUING OPERATIONS		(118	)		(37	)		(37	)
NET INCOME FROM CONTINUING OPERATIONS		139			223			183
(LOSS) INCOME FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES		(107	)		12			117
NET INCOME	$	32		$	235		$	300
EARNINGS PER SHARE
Earnings per share of common stock from Continuing Operations	$	0.62		$	1.01		$	0.90
(Loss) earnings per share of common stock from Discontinued Operations		(0.48	)		0.05			0.57
Basic and diluted earnings per share of common stock	$	0.14		$	1.06		$	1.47

The accompanying Notes are an integral part of these financial statements.

330

PEPCO HOLDINGS, INC. (Parent Company)

BALANCE SHEETS

	As of December 31,
	2010			2009
	(millions of dollars, except share data)
ASSETS
Current Assets
Cash and cash equivalents	$	131		$	585
Prepayments of income taxes		99			8
Accounts receivable and other		5			33
		235			626
Investments and Other Assets
Goodwill		1,398			1,398
Notes receivable from subsidiary companies		154			472
Investment in consolidated companies		3,033			3,347
Other		19			16
Investments held for sale		355			879
		4,959			6,112
Total Assets	$	5,194		$	6,738
LIABILITIES AND EQUITY
Current Liabilities
Short-term debt	$	230		$	324
Current portion of long-term debt		—			450
Interest and taxes accrued		15			60
		245			834
Deferred Credits
Liabilities and accrued interest related to uncertain tax positions		14			—
Long-Term Debt		705			1,648
Commitments and Contingencies (Note 4)
Equity
Common stock, $.01 par value; authorized 400,000,000 shares; 225,082,252 and 222,269,895 shares outstanding, respectively		2			2
Premium on stock and other capital contributions		3,275			3,227
Accumulated other comprehensive loss		(106	)		(241	)
Retained earnings		1,059			1,268
Total equity		4,230			4,256
Total Liabilities and Equity	$	5,194		$	6,738

The accompanying Notes are an integral part of these financial statements.

331

PEPCO HOLDINGS, INC. (Parent Company)

STATEMENTS OF CASH FLOWS

	For the Year Ended December 31,
	2010			2009			2008
	(millions of dollars)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	32		$	235		$	300
Loss (income) from discontinued operations		107			(12	)		(117	)
Adjustments to reconcile net income to net cash from operating activities:
Distributions from related parties less than earnings		(150	)		(186	)		(53	)
Deferred income taxes		(5	)		—			2
Changes in:
Prepaid and other		24			(24	)		(10	)
Accounts payable		1			(4	)		16
Interest and taxes		(130	)		19			(5	)
Other assets and liabilities		31			16			(2	)
Net Cash (Used By) From Operating Activities		(90	)		44			131
CASH FLOWS FROM INVESTING ACTIVITIES
Investment in property, plant and equipment		—			—			—
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		(241	)		(238	)		(222	)
Common stock issued for the Dividend Reinvestment Plan and employee-related compensation		47			49			51
Issuance of common stock		—			—			265
Issuance of long-term debt		250			—			—
Capital distribution to subsidiaries		(31	)		(255	)		(175	)
Reacquisition of long-term debt		(1,644	)		—			—
Decrease in notes receivable from associated companies		318			156			79
(Repayments) issuances of short-term debt, net		(94	)		274			50
Costs of issuances		(4	)		(1	)		(10	)
Net Cash (Used By) From Financing Activities		(1,399	)		(15	)		38
Net (decrease) increase in cash and cash equivalents		(454	)		29			169
Cash and cash equivalents at beginning of year		585			556			387
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	131		$	585		$	556

The accompanying Notes are an integral part of these financial statements.

332

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 included in Part II, Item 8 of this Form 10-K.

(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 included in Part II, Item 8 of this Form 10-K.

(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:

	2010		2009
	(millions of dollars)
Conectiv	$	772	$	1,156
Potomac Electric Power Company		1,428		1,435
Potomac Capital Investment Corporation		498		472
Pepco Energy Services, Inc.		331		278
PHI Service Company		4		6
Total investment in consolidated companies	$	3,033	$	3,347

(6) INVESTMENTS HELD FOR SALE

As of December 31, 2010 and 2009, Pepco Holdings held for sale its investment in Conectiv Energy Holding Company, LLC, a subsidiary of Conectiv. The balances of investments held for sale of $355 million and $879 million as of December 31, 2010 and 2009, respectively, are inclusive of net intercompany receivables of $310 million and net intercompany liabilities of $908 million, respectively.

(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.

333

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, 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
Year Ended December 31, 2008
Allowance for uncollectible accounts - customer and other accounts receivable	$	30	$	43	$	6	$	(44	)	$	35

(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, 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
Year Ended December 31, 2008
Allowance for uncollectible accounts - customer and other accounts receivable	$	13	$	18	$	1	$	(17	)	$	15

(a) Collection of accounts previously written off.

(b) Uncollectible accounts written off.

334

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, 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
Year Ended December 31, 2008
Allowance for uncollectible accounts - customer and other accounts receivable	$	8	$	17	$	3	$	(18	)	$	10

(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, 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
Year Ended December 31, 2008
Allowance for uncollectible accounts - customer and other accounts receivable	$	5	$	8	$	2	$	(9	)	$	6

(a) Collection of accounts previously written off.

(b) Uncollectible accounts written off.

335

3. EXHIBITS

The documents listed below are being filed herewith or have previously been filed and are incorporated herein by reference from the documents indicated and made a part hereof.

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	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.
3.4	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.
3.5	PHI	Bylaws	Exh. 3 to PHI’s Form 8-K, 5/3/07.
3.6	Pepco	Bylaws	Exh. 3.1 to Pepco’s Form 10-Q, 5/5/06.
3.7	DPL	Bylaws	Exh. 3.2.1 to DPL’s Form 10-Q 5/9/05.
3.8	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.

336

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.

337

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.

338

		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.

339

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.

340

		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
		One Hundred and Fifth Supplemental Indenture	Exh. 4.4 to DPL’s Form 8-K, 10/1/09.
		One Hundred and Sixth Supplemental Indenture	Filed herewith.
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.
		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.

341

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.
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.

342

May 1, 1975	Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
December 1, 1976	Exh. 2(b) to ACE’s Registration Statement No. 2-66280, 12/21/79.
January 1, 1980	Exh. 4(e) to ACE’s Form 10-K, 3/25/81.
May 1, 1981	Exh. 4(a) to ACE’s Form 10-Q, 8/10/81.
November 1, 1983	Exh. 4(d) to ACE’s Form 10-K, 3/30/84.
April 15, 1984	Exh. 4(a) to ACE’s Form 10-Q, 5/14/84.
July 15, 1984	Exh. 4(a) to ACE’s Form 10-Q, 8/13/84.
October 1, 1985	Exh. 4 to ACE’s Form 10-Q, 11/12/85.
May 1, 1986	Exh. 4 to ACE’s Form 10-Q, 5/12/86.
July 15, 1987	Exh. 4(d) to ACE’s Form 10-K, 3/28/88.
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 33-49279, 1/6/93.
January 1, 1993	Exh. 4.05(hh) to ACE’s Registration Statement 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.

343

		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.
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.
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.

344

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*	Exh. 10.5 to PHI’s Form 10-K, 3/2/09.
10.3	PHI	Pepco Holdings, Inc. Executive and Director Deferred Compensation Plan*	Exh. 10.6 to PHI’s Form 10-K, 3/2/09.
10.4	PHI Pepco	Potomac Electric Power Company Director and Executive Deferred Compensation Plan*	Exh. 10.22 to PHI’s Form 10-K, 3/28/03.
10.5	PHI Pepco	Potomac Electric Power Company Long-Term Incentive Plan*	Exh. 4 to Pepco’s Form S-8, 6/12/98.
10.6	PHI	Conectiv Incentive Compensation Plan*	Exh. 99(e) to Conectiv’s Registration Statement No. 333-18843, 12/26/96.
10.7	PHI	Conectiv Supplemental Executive Retirement Plan*	Exh. 10.9 to PHI’s Form 10-K, 2/26/10.
10.8	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.
10.9	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.
10.10	PHI	Conectiv Deferred Compensation Plan*	Exh. 10.1 to PHI’s Form 10-Q, 8/6/04.
10.11	PHI	Form of Employee Nonqualified Stock Option Agreement*	Exh. 10.2 to PHI’s Form 10-Q, 11/8/04.
10.12	PHI	Form of Director Nonqualified Stock Option Agreement*	Exh. 10.3 to PHI’s Form 10-Q, 11/8/04.
10.13	PHI	Form of Election Regarding Payment of Director Retainer/Fees*	Exh. 10.4 to PHI’s Form 10-Q, 11/8/04.
10.14	PHI	Form of Executive and Director Deferred Compensation Plan Executive Deferral Agreement*	Exh. 10.5 to PHI’s Form 10-Q, 11/8/04.
10.15	PHI	Form of Executive Incentive Compensation Plan Participation Agreement*	Exh. 10.6 to PHI’s Form 10-Q, 11/8/04.
10.16	PHI	Form of Restricted Stock Agreement*	Exh. 10.7 to PHI’s Form 10-Q, 11/8/04.
10.17	PHI	Form of Election with Respect to Stock Tax Withholding*	Exh. 10.8 to PHI’s Form 10-Q, 11/8/04.
10.18	PHI	Non-Management Directors Compensation Plan*	Exh. 10.21 to PHI’s Form 10-K, 3/2/09.
10.19	PHI	Annual Executive Incentive Compensation Plan dated as of February 9, 2009*	Exh. 10.22 to PHI’s Form 10-K, 3/2/09.

345

10.20	PHI	Non-Management Director Compensation Arrangements*	Exh. 10.24 to PHI’s Form 10-K, 2/29/08.
10.21	PHI	Form of Election regarding Non-Management Directors Compensation Plan*	Exh. 10.57 to PHI’s Form 10-K, 3/16/05.
10.22	PHI Pepco	Change-in-Control Severance Plan for Certain Executive Employees*	Exh. 10.25 to PHI’s Form 10-K, 3/2/09.
10.23	PHI Pepco DPL ACE	Amended and Restated Credit Agreement, dated as of May 2, 2007, between PHI, Pepco, DPL and ACE, the lenders party thereto, Wachovia Bank, National Association, as administrative agent and swingline lender, Citicorp USA, Inc., as syndication agent, The Royal Bank of Scotland, plc, The Bank of Nova Scotia and JPMorgan Chase Bank, N.A., as documentation agents, and Wachovia Capital Markets, LLC and Citigroup Global Markets Inc., as joint lead arrangers and joint book runners	Exh. 10 to PHI’s Form 10-Q, 5/7/07.
10.24	PHI	Pepco Holdings, Inc. Combined Executive Retirement Plan*	Exh. 10.28 to PHI’s Form 10-K, 3/2/09.
10.25	PHI	PHI Named Executive Officer 2009 Compensation Determinations*	Exh. 10.30 to PHI’s Form 10-K, 3/2/09.
10.26	PHI	PHI Named Executive Officer 2010 Compensation Determinations*	Exh. 10.37 to PHI’s Form 10-K, 2/26/10.
10.27	DPL	Transmission Purchase and Sale Agreement By and Between Delmarva Power & Light Company and Old Dominion Electric Cooperative dated as of June 13, 2007	Exh. 10.1 to DPL’s Form 10-Q, 8/6/07.
10.28	DPL	Purchase And Sale Agreement By and Between Delmarva Power & Light Company and A&N Electric Cooperative dated as of June 13, 2007	Exh. 10.2 to DPL’s Form 10-Q, 8/6/07.

346

10.29	PHI	Severance Agreement of Paul H. Barry dated June 12, 2009*	Exh. 10.1 to PHI’s Form 8-K, 6/12/09.
10.30	PHI	PHI Named Executive Officer 2011 Compensation Determinations*	Filed herewith.
10.31	PHI	Employment Agreement of John U. Huffman dated November 23, 2009*	Exh. 10.38 to PHI’s Form 10-K, 2/26/10.
10.32	PHI	Employment Agreement of Gary J. Morsches dated February 3, 2010*	Exh. 10.39 to PHI’s Form 10-K, 2/26/10.
10.33	PHI	Purchase Agreement, dated as of April 20, 2010, by and among Pepco Holdings, Inc., Conectiv, LLC, Conectiv Energy Holding Company, LLC and New Development Holdings, LLC	Exh. 2.1 to PHI’s Form 8-K, 7/8/10.
10.34	PHI	Separation Agreement of Gary J. Morsches*	Filed herewith.
10.35	PHI	Amended and Restated Credit Agreement, dated October 16, 2009, by and among Bank of America, N.A., Banc of America Securities, KeyBank National Association, JPMorgan Chase Bank, N.A., SunTrust Bank, The Bank of Nova Scotia, Morgan Stanley Bank, N.A., Credit Suisse, Cayman Islands Branch, Wells Fargo Bank, N.A. and Manufacturers and Traders Trust Company	Exh. 10.1 to PHI’s Form 8-K, 10/22/09.
10.36	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.
10.37	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.
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.

347

12.4	ACE	Statements Re: Computation of Ratios	Filed herewith.
21	PHI	Subsidiaries of the Registrant	Filed herewith.
23.1	PHI	Consent of Independent Registered Public Accounting Firm	Filed herewith.
23.2	Pepco	Consent of Independent Registered Public Accounting Firm	Filed herewith.
23.3	DPL	Consent of Independent Registered Public Accounting Firm	Filed herewith.
23.4	ACE	Consent of Independent Registered Public Accounting Firm	Filed herewith.
31.1	PHI	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	Filed herewith.
31.2	PHI	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	Filed herewith.
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.
101. INS	PHI Pepco DPL ACE	XBRL Instance Document	Submitted herewith.
101. SCH	PHI Pepco DPL ACE	XBRL Taxonomy Extension Schema Document	Submitted herewith.
101. CAL	PHI Pepco DPL ACE	XBRL Taxonomy Extension Calculation Linkbase Document	Submitted herewith.
101. DEF	PHI Pepco DPL ACE	XBRL Taxonomy Extension Definition Linkbase Document	Submitted herewith.
101. LAB	PHI Pepco DPL ACE	XBRL Taxonomy Extension Label Linkbase Document	Submitted herewith.
101. PRE	PHI Pepco DPL ACE	XBRL Taxonomy Extension Presentation Linkbase Document	Submitted herewith.

* Management contract or compensatory plan or arrangement.

348

** 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 Pepco Holdings, Inc., those of its subsidiaries that are registrants, Conectiv and ACE Funding are provided below:

Pepco Holdings, Inc. in file number 001-31403

Potomac Electric Power Company in file number 001-01072

Conectiv in file number 001-13895

Delmarva Power & Light Company in file number 001-01405

Atlantic City Electric Company in file number 001-03559

Atlantic City Electric Transition Funding LLC in file number 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.

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

349

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 25, 2011	By	/S/     JOSEPH M. RIGBY
		Joseph M. Rigby
		Chairman of the Board, President and
		Chief Executive Officer

	POTOMAC ELECTRIC POWER COMPANY (Pepco) (Registrant)
February 25, 2011	By	/S/    DAVID M. VELAZQUEZ
		David M. Velazquez,
		President and Chief Executive Officer

	DELMARVA POWER & LIGHT COMPANY (DPL) (Registrant)
February 25, 2011	By	/S/    DAVID M. VELAZQUEZ
		David M. Velazquez,
		President and Chief Executive Officer

	ATLANTIC CITY ELECTRIC COMPANY (ACE) (Registrant)
February 25, 2011	By	/S/    DAVID M. VELAZQUEZ
		David M. Velazquez,
		President and Chief Executive Officer

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 25, 2011
/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 25, 2011
/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 25, 2011
/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 25, 2011

Signature	Title	Date
/S/    J.B. DUNN         Jack B. Dunn, IV	Director, Pepco Holdings	February 25, 2011
/S/    T. C. GOLDEN         Terence C. Golden	Director, Pepco Holdings	February 25, 2011
/S/    FRANK O. HEINTZ         Frank O. Heintz	Director, Pepco Holdings	February 25, 2011
/S/    PATRICK T. HARKER         Patrick T. Harker	Director, Pepco Holdings	February 25, 2011
/S/    BARBARA J. KRUMSIEK         Barbara J. Krumsiek	Director, Pepco Holdings	February 25, 2011
/S/    GEORGE F. MACCORMACK         George F. MacCormack	Director, Pepco Holdings	February 25, 2011
/S/    LAWRENCE C. NUSSDORF         Lawrence C. Nussdorf	Director, Pepco Holdings	February 25, 2011
/S/    PATRICIA A. OELRICH         Patricia A. Oelrich	Director, Pepco Holdings	February 25, 2011
/S/    FRANK ROSS         Frank Ross	Director, Pepco Holdings	February 25, 2011
/S/    PAULINE A. SCHNEIDER         Pauline A. Schneider	Director, Pepco Holdings	February 25, 2011
/S/    LESTER P. SILVERMAN         Lester P. Silverman	Director, Pepco Holdings	February 25, 2011
/S/    KIRK J. EMGE         Kirk J. Emge	Director, Pepco and DPL	February 25, 2011
/S/    CHARLES R. DICKERSON         Charles R. Dickerson	Director, Pepco	February 25, 2011
/S/    WILLIAM M. GAUSMAN         William M. Gausman	Director, Pepco	February 25, 2011
/S/    MICHAEL J. SULLIVAN         Michael J. Sullivan	Director, Pepco	February 25, 2011

INDEX TO EXHIBITS FILED HEREWITH
Exhibit No.	Registrant(s)	Description of Exhibit
4.4	PHI DPL	One Hundred and Sixth Supplemental Indenture
10.30	PHI	PHI Named Executive Officer 2011 Compensation Determinations*
10.34	PHI	Separation Agreement of Gary J. Morsches*
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