UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

THE SECURITIES EXCHANGE ACT OF 1934

For the quarter ended March 31, 2011

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 500 North Wakefield Drive Newark, DE 19702 Telephone: (202)872-2000		51-0084283
001-03559	ATLANTIC CITY ELECTRIC COMPANY (ACE), a New Jersey corporation 500 North Wakefield Drive Newark, DE 19702 Telephone: (202)872-2000		21-0398280

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 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 H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with reduced disclosure format specified in General Instruction H(2) of Form 10-Q.

Registrant	Number of Shares of Common Stock of the Registrant Outstanding at March 31, 2011
Pepco Holdings	225,770,379 ($.01 par value)
Pepco	100 ($.01 par value) (a)
DPL	1,000 ($2.25 par value) (b)
ACE	8,546,017 ($3.00 par value) (b)

(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-Q 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.

TABLE OF CONTENTS

		Page
	Glossary of Terms		i
PART I         FINANCIAL INFORMATION			1
Item 1.	- Financial Statements		1
Item 2.	- Management’s Discussion and Analysis of Financial Condition and Results of Operations		97
Item 3.	- Quantitative and Qualitative Disclosures About Market Risk		149
Item 4.	- Controls and Procedures		151
PART II         OTHER INFORMATION			152
Item 1.	- Legal Proceedings		152
Item 1A	- Risk Factors		153
Item 2.	- Unregistered Sales of Equity Securities and Use of Proceeds		154
Item 3.	- Defaults Upon Senior Securities		154
Item 4.	- Reserved		154
Item 5.	- Other Information		154
Item 6.	- Exhibits		155
Signatures			156

GLOSSARY OF TERMS

Term	Definition
ACE	Atlantic City Electric Company
ACE Funding	Atlantic City Electric Transition Funding LLC
ADITC	Accumulated deferred investment tax credits
AMI	Advanced metering infrastructure
AOCL	Accumulated Other Comprehensive Loss
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)
Bondable Transition Property	The principal and interest payments on the Transition Bonds and related taxes, expenses and fees
BSA	Bill Stabilization Adjustment
Calpine	Calpine Corporation
CERCLA	Comprehensive Environmental Response, Compensation, and Liability Act of 1980
Conectiv	A wholly owned subsidiary of PHI and the parent of DPL and ACE
Cooling Degree Days	Daily difference in degrees by which the mean (high and low divided by 2) dry bulb temperature is above a base of 65 degrees Fahrenheit
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 Standard Offer Service or BGS
Default Electricity Supply Revenue	Revenue primarily from Default Electricity Supply
DOE	U.S. Department of Energy
DPL	Delmarva Power & Light Company
DPSC	Delaware Public Service Commission
EDIT	Excess Deferred Income Taxes
EIS	Environmental Impact Statement
EmPower Maryland	A Maryland demand-side management program for Pepco and DPL
Energy Services	Energy savings performance contracting services provided principally to federal, state and local government customers, and designing, constructing and operating combined heat and power, and central energy plants by Pepco Energy Services
EPA	U.S. Environmental Protection Agency
EPS	Earnings per share
Exchange Act	Securities Exchange Act of 1934, as amended
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FHACA	Flood Hazard Area Control Act
GAAP	Accounting principles generally accepted in the United States of America
GCR	Gas Cost Rate
GWh	Gigawatt hour
Heating Degree Days	Daily difference in degrees by which the mean (high and low divided by 2) dry bulb temperature is below a base of 65 degrees Fahrenheit
IRS	Internal Revenue Service
ISDA	International Swaps and Derivatives Association
ISRA	New Jersey’s Industrial Site Recovery Act
LCAPP	Long-term Capacity Agreement Pilot Program enacted by legislation in New Jersey
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

i

Term	Definition
MDC	MDC Industries, Inc.
MFVRD	Modified fixed variable rate design
Mirant	Mirant Corporation
MMBtu	One Million British Thermal Units
MPSC	Maryland Public Service Commission
MSCG	Morgan Stanley Capital Group, Inc.
MUCR	Mandatory unitary combined reporting
MWh	Megawatt hours
New Jersey Societal Benefit Charge	Charge to ACE customers, included in revenue, to recover costs associated with New Jersey Societal Benefit Programs
New Jersey Societal Benefit Programs	Various NJBPU - mandated social programs for which ACE receives revenues to recover costs
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
NUGs	Non-utility generators
NYMEX	New York Mercantile Exchange
Patient Protection Act	Patient Protection and Affordable Care Act
PCB	Polychlorinated biphenyls
PCI	Potomac Capital Investment Corporation and its subsidiaries
Pepco	Potomac Electric Power Company
Pepco Energy Services	Pepco Energy Services, Inc. and its subsidiaries
Pepco Holdings or PHI	Pepco Holdings, Inc.
PHI Retirement Plan	PHI’s noncontributory retirement plan
PJM	PJM Interconnection, LLC
PJM RTO	PJM regional transmission organization
Power Delivery	PHI’s Power Delivery Business
PPA	Power purchase agreement
PRP	Potentially responsible party
PUHCA 2005	Public Utility Holding Company Act of 2005
RECs	Renewable energy credits
Regulated T&D Electric Revenue	Revenue from the transmission and the distribution of electricity to PHI’s customers within its service territories at regulated rates
RI/FS	Remedial investigation and feasibility study
ROE	Return on equity
RTEP	PJM’s Regional Transmission Expansion Plan
SEC	Securities and Exchange Commission
SOCAs	Standard Offer Capacity Agreements required to be entered into by ACE pursuant to LCAPP
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
Treasury rate lock	A hedging transaction that allows a company to “lock in” a specific interest rate corresponding to the rate of a designated Treasury bond for a determined period of time
VADEQ	Virginia Department of Environmental Quality
VaR	Value at Risk

ii

PEPCO HOLDINGS

PART I FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

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
Consolidated Statements of Income (Loss)		2		49		65		83
Consolidated Statements of Comprehensive Income (Loss)		3		N/A		N/A		N/A
Consolidated Balance Sheets		4		50		66		84
Consolidated Statements of Cash Flows		6		52		68		86
Notes to Consolidated Financial Statements		7		53		69		87

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

1

PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended March 31,
	2011			2010
	(millions of dollars, except per share data)
Operating Revenue
Power Delivery	$	1,249		$	1,262
Pepco Energy Services		373			547
Other		12			10
Total Operating Revenue		1,634			1,819
Operating Expenses
Fuel and purchased energy		995			1,287
Other services cost of sales		43			25
Other operation and maintenance		234			214
Depreciation and amortization		105			89
Other taxes		111			92
Deferred electric service costs		(3	)		(19	)
Total Operating Expenses		1,485			1,688
Operating Income		149			131
Other Income (Expenses)
Interest expense		(62	)		(83	)
Loss from equity investments		(1	)		(1	)
Other income		10			6
Total Other Expenses		(53	)		(78	)
Income from Continuing Operations Before Income Tax Expense		96			53
Income Tax Expense Related to Continuing Operations		34			25
Net Income from Continuing Operations		62			28
Income from Discontinued Operations, net of Income Taxes		2			8
Net Income		64			36
Retained Earnings at Beginning of Period		1,059			1,268
Dividends Paid on Common Stock (Note 15)		(61	)		(60	)
Retained Earnings at End of Period	$	1,062		$	1,244
Basic and Diluted Share Information
Weighted average shares outstanding (millions)		225			222
Earnings per share of common stock from Continuing Operations	$	0.27		$	0.13
Earnings per share of common stock from Discontinued Operations		0.01			0.03
Basic and diluted earnings per share	$	0.28		$	0.16

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

2

PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)

	Three Months Ended March 31,
	2011			2010
	(millions of dollars)
Net income	$	64		$	36
Other comprehensive income (loss) from continuing operations
Gain (loss) from continuing operations on commodity derivatives designated as cash flow hedges:
Losses arising during period		(1	)		(90	)
Amount of losses reclassified into income		27			49
Net gains (losses) on commodity derivatives		26			(41	)
Losses on treasury rate locks reclassified into income		—			1
Amortization of losses for prior service costs		1			—
Other comprehensive income (loss) from continuing operations, before income taxes		27			(40	)
Income tax expense (benefit) from continuing operations		11			(16	)
Other comprehensive income (loss) from continuing operations, net of income taxes		16			(24	)
Other comprehensive income (loss) from discontinued operations, net of income taxes		—			(42	)
Comprehensive income (loss)	$	80		$	(30	)

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

3

PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31, 2011			December 31, 2010
	(millions of dollars)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	18		$	20
Restricted cash equivalents		13			11
Accounts receivable, less allowance for uncollectible accounts of $50 million and $51 million, respectively		939			1,027
Inventories		116			126
Derivative assets		31			45
Prepayments of income taxes		225			276
Deferred income tax assets, net		50			90
Prepaid expenses and other		78			51
Conectiv Energy assets held for sale		21			111
Total Current Assets		1,491			1,757
INVESTMENTS AND OTHER ASSETS
Goodwill		1,407			1,407
Regulatory assets		1,870			1,915
Investment in finance leases held in trust		1,437			1,423
Income taxes receivable		97			114
Restricted cash equivalents		6			5
Assets and accrued interest related to uncertain tax positions		4			11
Other		169			169
Conectiv Energy assets held for sale		1			6
Total Investments and Other Assets		4,991			5,050
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		12,255			12,120
Accumulated depreciation		(4,495	)		(4,447	)
Total Property, Plant and Equipment		7,760			7,673
TOTAL ASSETS	$	14,242		$	14,480

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

4

PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31, 2011			December 31, 2010
	(millions of dollars, except shares)
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Short-term debt	$	567		$	534
Current portion of long-term debt and project funding		78			75
Accounts payable and accrued liabilities		505			587
Capital lease obligations due within one year		7			8
Taxes accrued		101			96
Interest accrued		76			45
Liabilities and accrued interest related to uncertain tax positions		4			3
Derivative liabilities		61			66
Other		275			321
Liabilities associated with Conectiv Energy assets held for sale		9			62
Total Current Liabilities		1,683			1,797
DEFERRED CREDITS
Regulatory liabilities		533			528
Deferred income taxes, net		2,778			2,714
Investment tax credits		25			26
Pension benefit obligation		227			332
Other postretirement benefit obligations		430			429
Income taxes payable		—			2
Liabilities and accrued interest related to uncertain tax positions		59			148
Derivative liabilities		14			21
Other		182			175
Liabilities associated with Conectiv Energy assets held for sale		—			10
Total Deferred Credits		4,248			4,385
LONG-TERM LIABILITIES
Long-term debt		3,626			3,629
Transition bonds issued by ACE Funding		323			332
Long-term project funding		15			15
Capital lease obligations		86			86
Total Long-Term Liabilities		4,050			4,062
COMMITMENTS AND CONTINGENCIES (NOTE 15)
EQUITY
Common stock, $.01 par value – authorized 400,000,000 shares, 225,770,379 and 225,082,252 shares outstanding, respectively		2			2
Premium on stock and other capital contributions		3,287			3,275
Accumulated other comprehensive loss		(90	)		(106	)
Retained earnings		1,062			1,059
Total Shareholders’ Equity		4,261			4,230
Non-controlling interest		—			6
Total Equity		4,261			4,236
TOTAL LIABILITIES AND EQUITY	$	14,242		$	14,480

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

5

PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March  31,
	2011			2010
	(millions of dollars)
OPERATING ACTIVITIES
Net income	$	64		$	36
Income from discontinued operations		(2	)		(8	)
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		105			89
Non-cash rents from cross-border energy lease investments		(14	)		(13	)
Deferred income taxes		90			40
Other		(4	)		(3	)
Changes in:
Accounts receivable		87			6
Inventories		10			2
Prepaid expenses		10			17
Regulatory assets and liabilities, net		11			(1	)
Accounts payable and accrued liabilities		(126	)		(48	)
Pension contributions		(110	)		—
Pension benefit obligation, excluding contributions		16			18
Cash collateral related to derivative activities		31			(77	)
Taxes accrued		(49	)		(1	)
Interest accrued		31			24
Other assets and liabilities		16			15
Conectiv Energy net assets held for sale		31			(29	)
Net Cash From Operating Activities		197			67
INVESTING ACTIVITIES
Investment in property, plant and equipment		(171	)		(159	)
Department of Energy capital reimbursement awards received		9			—
Changes in restricted cash equivalents		(2	)		2
Net other investing activities		—			(1	)
Investment in property, plant and equipment associated with Conectiv Energy assets held for sale		—			(49	)
Net Cash Used By Investing Activities		(164	)		(207	)
FINANCING ACTIVITIES
Dividends paid on common stock		(61	)		(60	)
Common stock issued for the Dividend Reinvestment Plan and employee related compensation		14			15
Redemption of preferred stock of subsidiaries		(6	)		—
Issuances of long-term debt		—			23
Reacquisition of long-term debt		(9	)		(24	)
Issuances of short-term debt, net		33			197
Net other financing activities		(7	)		(21	)
Net financing activities associated with Conectiv Energy assets held for sale		—			2
Net Cash (Used by) From Financing Activities		(36	)		132
Net Decrease in Cash and Cash Equivalents		(3	)		(8	)
Cash and Cash Equivalents of discontinued operations		—			(1	)
Cash and Cash Equivalents at Beginning of Period		21			46
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	18		$	37
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for income taxes, net	$	2		$	2

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

6

PEPCO HOLDINGS

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 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 methodologies 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 in New Jersey. In these Notes to the Consolidated Financial Statements, these supply service obligations are referred to generally as Default Electricity Supply.

7

PEPCO HOLDINGS

Pepco Energy Services

Pepco Energy Services is engaged in the following businesses:

• retail supply of electricity and natural gas under its remaining contractual obligations,

• 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, and

• 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 owns and operates two oil-fired generation facilities that are scheduled for deactivation in May 2012.

In December 2009, PHI announced the wind down of the retail energy supply component of the Pepco Energy Services business. Pepco Energy Services is implementing this wind down by not entering into any new supply contracts, while continuing to perform under its existing supply contracts through their expiration dates. The retail energy supply business has historically generated a substantial portion of the operating revenues and net income of the Pepco Energy Services segment. Operating revenues related to the retail energy supply business for the three months ended March 31, 2011 and 2010 were $305 million and $497 million, respectively, while operating income for the same periods was $12 million and $21 million, respectively.

In connection with the operation of the retail energy supply business, as of March 31, 2011, Pepco Energy Services provided letters of credit of $92 million and posted net cash collateral of $87 million. These collateral requirements, which are based on existing wholesale energy purchase and sale contracts and current market prices, will decrease as the contracts expire, with the collateral expected to be fully released by June 1, 2014. The energy services business will not be affected by the wind down of the retail energy supply business.

Other Business Operations

Through its subsidiary Potomac Capital Investment Corporation (PCI), PHI maintains a portfolio of cross-border energy lease investments, with a book value at March 31, 2011 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 (15), “Commitments and Contingencies – PHI Cross-Border Energy Lease Investments.”

Discontinued Operations

In April 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 constitute a separate segment for financial reporting purposes. Substantially all of the information in these Notes to the Consolidated Financial Statements with respect to the operations of the former Conectiv Energy segment has been consolidated in Note (16), “Discontinued Operations.”

8

PEPCO HOLDINGS

(2) SIGNIFICANT ACCOUNTING POLICIES

Financial Statement Presentation

Pepco Holdings’ unaudited Consolidated Financial Statements are prepared in conformity with accounting principles generally accepted in the United States of America (GAAP). Pursuant to the rules and regulations of the Securities and Exchange Commission, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been omitted. Therefore, these financial statements should be read along with the annual financial statements included in PHI’s Annual Report on Form 10-K for the year ended December 31, 2010. In the opinion of PHI’s management, the Consolidated Financial Statements contain all adjustments (which all are of a normal recurring nature) necessary to present fairly Pepco Holdings’ financial condition as of March 31, 2011, in accordance with GAAP. The year-end December 31, 2010 Consolidated Balance Sheet was derived from audited financial statements, but does not include all disclosures required by GAAP. Interim results for the three months ended March 31, 2011 may not be indicative of PHI’s results that will be realized for the full year ending December 31, 2011, since its Power Delivery business and the retail energy supply business of Pepco Energy Services are seasonal.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the Consolidated Financial Statements and accompanying notes. Although Pepco Holdings believes that its estimates and assumptions are reasonable, they are based upon information available to management at the time the estimates are made. Actual results may differ significantly from these estimates.

Significant matters that involve the use of estimates include the assessment of goodwill and long-lived assets for impairment, fair value calculations for certain derivative instruments, the costs of providing pension and other postretirement benefits, evaluation of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of interest related to income taxes, accrual of restructuring charges, recognition of changes in network service transmission rates for prior service year costs, and the recognition of income tax benefits for investments in finance leases held in trust associated with PHI’s portfolio of cross-border energy lease investments. Additionally, PHI is subject to legal, regulatory, and other proceedings and claims that arise in the ordinary course of its business. PHI records an estimated liability for these proceedings and claims, when it is probable that a loss has been incurred and the loss is reasonably estimable.

Network Service Transmission Rates

In May of every year, each of PHI’s utility subsidiaries provides its updated network service transmission rate to the Federal Energy Regulatory Commission (FERC) to be effective for June 1 of that year through May 31 of the following year. The updated network transmission rate includes an adjustment for costs incurred in the prior service year not yet reflected in rates charged to customers, that PHI’s utility subsidiaries accrue as an adjustment to transmission revenue prior to their inclusion in transmission rates. In the first quarter of 2011, PHI’s utility subsidiaries revised their fourth quarter 2010 estimates of the adjustments to be included in the transmission rates to be filed in May 2011 based on updated cost information from 2010, and recorded the changes in the estimates as transmission revenue adjustments. The revised estimates resulted in a $4 million increase in transmission revenues, which was recorded in the first quarter of 2011 for transmission service provided during the first ten months of the 2010-2011 service year. In the fourth quarter of 2010, PHI’s utility subsidiaries had estimated and recorded a $2 million decrease in revenues for transmission services provided during the first seven months of the 2010-2011 service year. In the second quarter of 2011, PHI’s utility subsidiaries will revise their first quarter 2011 estimates as needed to reflect the adjustments to be filed by them for transmission services provided during the entire 2010-2011 service year as part of the transmission service rates submitted to FERC for the 2011-2012 service year.

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Consolidation of Variable Interest Entities

In accordance with the provisions of the Financial Accounting Standards Board (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. The subsidiaries of Pepco Holdings have contractual arrangements with several entities to which the guidance applies.

ACE Power Purchase Agreements

Pepco Holdings, 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, Pepco Holdings 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 the three months ended March 31, 2011, 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 three months ended March 31, 2011 and 2010, were approximately $57 million and $72 million, respectively, of which approximately $53 million and $67 million, respectively, consisted of power purchases under the PPAs. The power purchase costs are recoverable from ACE’s customers through regulated rates.

DPL Renewable Energy Transactions

PHI, through its DPL subsidiary, has entered into four wind PPAs in the aggregate amount of 350 megawatts as of March 31, 2011 that includes the purchase of renewable energy credits (RECs) and one solar REC purchase agreement with a 10 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 are with land-based facilities and one 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. The other wind agreements, which have terms ranging from 20 to 25 years, are currently expected to become operational during 2011 for the two land-based contracts and 2016 for the offshore contract, if the projects are ultimately completed. DPL’s purchases under the wind PPA’s totaled $5 million and $3 million for the three months ended March 31, 2011 and 2010, respectively. On April 6, 2011, DPL agreed to amend one of the land-based wind contracts to change the location of the wind facility and reduce the maximum generation capacity from 60 megawatts to 38 megawatts. The amendment requires DPSC approval. Upon DPSC approval, the amendment would reduce the aggregate amount of generation capacity associated with the four wind PPAs from 350 megawatts to 328 megawatts.

When the wind facilities 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 delays 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.

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The term of the agreement with the solar facility is 20 years and DPL is obligated to purchase RECs in an amount up to 70 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 bonds (Transition Bonds). The proceeds of the sale of each series of Transition Bonds have been transferred to ACE in exchange for the transfer by ACE to ACE Funding of the right to collect non-bypassable transition bond charges (the Transition Bond Charges) from ACE customers pursuant to bondable stranded costs rate orders issued by the New Jersey Board of Public Utilities (NJBPU) in an amount sufficient to fund the principal and interest payments on the Transition Bonds and related taxes, expenses and fees (Bondable Transition Property). ACE collects the Transition Bond Charges from its customers on behalf of ACE Funding and the holders of the Transition Bonds. The assets of ACE Funding, including the Bondable Transition Property, and the Transition Bond Charges collected from ACE’s customers, are not available to creditors of ACE. The holders of the Transition Bonds have recourse only to the assets of ACE Funding. ACE owns 100 percent of the equity of ACE Funding and PHI consolidates ACE Funding in its financial statements as ACE is the primary beneficiary of ACE Funding under the variable interest entity consolidation guidance.

ACE Standard Offer Capacity Agreements

On April 28, 2011, ACE entered into three Standard Offer Capacity Agreements (SOCAs) by order of the NJBPU. The SOCAs were established as part of the Long-term Capacity Agreement Pilot Program (LCAPP) that was enacted in January 2011 under a New Jersey state law to promote the construction of qualified electric generation facilities in New Jersey. The SOCAs are 15-year, financially settled transactions approved by the NJBPU that would allow generators selected by the NJBPU to receive payments from or make payments to ACE and the other electric distribution companies in New Jersey based on the difference between the fixed price set by the NJBPU in the SOCAs and the market resource clearing price for capacity.

The NJBPU awarded the SOCAs to three generation companies that would each construct a combined cycle, natural gas facility totaling an aggregate amount of capacity of 1,949 megawatts. ACE’s share of the payments under the SOCAs would be based on its proportion of load in New Jersey, which is approximately 15 percent, or 292 megawatts, of the aggregate capacity under the contracts. Payments would begin when the facilities are operational, which is currently estimated to be 2015 for two of the facilities and 2016 for the third facility. The NJBPU has approved full recovery from distribution customers of payments made by ACE when the SOCA price set by the NJBPU exceeds the market resource clearing price and ACE’s distribution customers would be entitled to any payments received when the market resource clearing price exceeds the SOCA price.

ACE and the other electric distribution companies in New Jersey entered into the SOCAs under protest and also requested that the NJBPU postpone implementation of the LCAPP and delay execution of the SOCAs based on concerns about the potential cost to distribution customers. The NJBPU denied that request and, on March 29, 2011, ordered the electric distribution companies in New Jersey, including ACE, to sign the SOCAs. ACE and the other electric distribution companies filed a joint motion for reconsideration of the order on April 8, 2011, which is pending review by the NJBPU.

PHI is currently assessing the appropriate accounting treatment for the SOCAs, including the applicability of FASB guidance on the consolidation of variable interest entities, leases and derivative instruments. PHI’s accounting review is expected to be completed in the second quarter of 2011.

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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 concluded that an interim impairment test was not required during the three months ended March 31, 2011 as described in Note (6), “Goodwill.”

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in Pepco Holdings’ gross revenues were $96 million and $74 million for the three months ended March 31, 2011 and 2010, respectively.

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 either individually or in the aggregate:

PES Derivative Accounting Adjustments

During the first quarter of 2011, PHI recorded an adjustment associated with an increase in the value of certain derivatives from October 1, 2010 to December 31, 2010, which had been erroneously recorded in other comprehensive income at December 31, 2010. This adjustment resulted in an increase in revenue and pre-tax earnings of $2 million.

Income Tax Adjustments

During the first quarter of 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 quarter ended March 31, 2010. The adjustment represents the reversal of erroneously recorded interest income for state income tax purposes related to uncertain and effectively settled tax positions, including $2 million, $3 million and $1 million recorded in 2009, 2008 and 2007, respectively.

(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Fair Value Measurements and Disclosures (ASC 820)

The FASB issued new disclosure requirements that require significant items within the reconciliation of the Level 3 valuation category to be presented in separate categories for purchases, sales, issuances and settlements. The guidance is effective beginning with PHI’s March 31, 2011 financial statements. PHI has incorporated the new disclosure requirements in Note (14), “Fair Value Disclosures,” of its financial statements.

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Goodwill (ASC 350)

The FASB issued new guidance on performing goodwill impairment tests that was effective beginning January 1, 2011 for PHI. Under the new guidance, the carrying value of the reporting unit must include the liabilities that are part of the capital structure of the reporting unit. PHI already allocates liabilities to the reporting unit when performing its goodwill impairment test, so the new guidance will not change PHI’s goodwill impairment test methodology.

Revenue Recognition (ASC 605)

The FASB issued new guidance to help determine separate units of accounting for multiple-deliverables within a single contract that was effective beginning January 1, 2011 for PHI. The energy services contracts of Pepco Energy Services are primarily impacted by this guidance because they often have multiple elements, which could include design, installation, operation and maintenance, measurement and verification services. PHI and its subsidiaries adopted the new guidance, effective January 1, 2011, and it did not have a material impact on Pepco Energy Services’ revenue recognition methods or results of operations nor did it have a material impact on PHI’s overall financial condition, results of operations or cash flows.

(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

There are no recently issued accounting standards that have not yet been adopted by PHI.

(5) SEGMENT INFORMATION

Pepco Holdings’ management has identified its operating segments at March 31, 2011 as Power Delivery, Pepco Energy Services and Other Non-Regulated. In the tables below, the Corporate and Other column is included to reconcile the segment data with consolidated data and includes unallocated Pepco Holdings’ (parent company) capital costs, such as acquisition financing costs. Segment financial information for continuing operations for the three months ended March 31, 2011 and 2010 is as follows:

	Three Months Ended March 31, 2011
	(millions of dollars)
	Power Delivery		Pepco Energy Services		Other Non- Regulated			Corporate and Other  (a)			PHI Consolidated
Operating Revenue	$	1,249	$	373	$	14		$	(2	)	$	1,634
Operating Expenses (b)		1,131		357		2			(5	)		1,485
Operating Income		118		16		12			3			149
Interest Income		—		—		1			(1	)		—
Interest Expense		50		1		3			8			62
Other Income (Expenses)		8		1		(1	)		1			9
Preferred Stock Dividends		—		—		1			(1	)		—
Income Tax Expense (Benefit)		29		6		2			(3	)		34
Net Income (Loss) from Continuing Operations		47		10		6			(1	)		62
Total Assets		10,667		613		1,645			1,295			14,220
Construction Expenditures	$	160	$	1	$	—		$	10		$	171

(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. Additionally, Corporate and Other includes intercompany amounts of $(2) million for Operating Revenue, $(2) million for Operating Expense, $(5) million for Interest Income, $(4) million for Interest Expense, and $(1) million for Preferred Stock Dividends.

(b) Includes depreciation and amortization of $105 million, consisting of $97 million for Power Delivery, $4 million for Pepco Energy Services and $4 million for Corporate and Other.

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	Three Months Ended March 31, 2010
	(millions of dollars)
	Power Delivery			Pepco Energy Services		Other Non- Regulated			Corporate and Other  (a)			PHI Consolidated
Operating Revenue	$	1,262		$	547	$	13		$	(3	)	$	1,819
Operating Expenses (b)		1,169			522		1			(4	)		1,688
Operating Income		93			25		12			1			131
Interest Income		—			—		1			(1	)		—
Interest Expense		51			5		4			23			83
Other Income (Expenses)		4			1		(1	)		1			5
Preferred Stock Dividends		—			—		1			(1	)		—
Income Tax Expense (Benefit)		26	(c)		8		3			(12	)(d)		25
Net Income (Loss) from Continuing Operations		20			13		4			(9	)		28
Total Assets		10,223			757		1,548			1,238			13,766
Construction Expenditures	$	151		$	1	$	—		$	7		$	159

(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. Additionally, Corporate and Other includes intercompany amounts of $(3) million for Operating Revenue, $(4) million for Operating Expense, $(12) million for Interest Income, $(12) million for Interest Expense, and $(1) million for Preferred Stock Dividends.

(b) Includes depreciation and amortization of $89 million, consisting of $82 million for Power Delivery, $4 million for Pepco Energy Services, and $3 million for Corporate and Other.

(c) Includes $8 million reversal of accrued interest income on uncertain and effectively settled state income tax positions.

(d) Includes $8 million reversal of valuation allowances on deferred tax assets related to state net operating losses partially offset by a charge of $4 million to write off a deferred tax asset related to the Medicare Part D subsidy.

(6) GOODWILL

PHI’s goodwill balance of $1.4 billion was unchanged during the three months ended March 31, 2011. 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 March 31, 2011, PHI concluded that there were no events requiring it to perform an interim goodwill impairment test. PHI will continue to monitor for indicators of goodwill impairment.

(7) LEASING ACTIVITIES

Investment in Finance Leases Held in Trust

As of March 31, 2011 and December 31, 2010, Pepco Holdings had cross-border energy lease investments of $1.4 billion consisting of hydroelectric generation and coal-fired electric generating facilities and natural gas distribution networks located outside of the United States.

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The components of the cross-border energy lease investments at March 31, 2011 and at December 31, 2010 are summarized below:

	March 31, 2011			December 31, 2010
	(millions of dollars)
Scheduled lease payments to PHI, net of non-recourse debt	$	2,265		$	2,265
Less: Unearned and deferred income		(828	)		(842	)
Investment in finance leases held in trust		1,437			1,423
Less: Deferred income tax liabilities		(816	)		(816	)
Net investment in finance leases held in trust	$	621		$	607

Income recognized from cross-border energy lease investments was comprised of the following for the three months ended March 31, 2011 and 2010:

	Three Months Ended March  31,
	2011		2010
	(millions of dollars)
Pre-tax income from PHI’s cross-border energy lease investments (included in “Other revenue”)	$	14	$	13
Income tax expense		4		4
Net income from PHI’s cross-border energy lease investments	$	10	$	9

PHI regularly monitors the financial performance and condition of the lessees under its cross-border energy lease investments. Changes in credit quality are assessed to determine if they should be reflected in the carrying value of the leases. PHI reviews each lessee’s performance versus annual compliance requirements set by the terms and conditions of the leases. This includes a comparison of published credit ratings to minimum credit rating requirements in the leases for lessees with public credit ratings. In addition, PHI routinely meets with senior executives of the lessees to discuss the company and asset performance. If the annual compliance requirements or minimum credit ratings are not met, remedies are available under the leases. At March 31, 2011, all lessees were in compliance with the terms and conditions of their lease agreements.

The table below shows PHI’s net investment in these leases by the published credit ratings of the lessees as of March 31, 2011 and December 31, 2010:

Lessee Rating (a)	March 31, 2011		December 31, 2010
	(millions of dollars)
Rated Entities
AA/Aa and above	$	716	$	709
A		555		549
Total		1,271		1,258
Non Rated Entities		166		165
Total	$	1,437	$	1,423

(a) Excludes the credit ratings of collateral posted by the lessees in these transactions.

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(8) PENSION AND OTHER POSTRETIREMENT BENEFITS

The following Pepco Holdings information is for the three months ended March 31, 2011 and 2010:

	Pension Benefits						Other Postretirement Benefits
	2011			2010			2011			2010
	(millions of dollars)
Service cost	$	10		$	11		$	2		$	2
Interest cost		26			30			9			10
Expected return on plan assets		(31	)		(33	)		(5	)		(4	)
Amortization of prior service cost		—			—			(1	)		(1	)
Amortization of net actuarial loss		13			11			4			3
Net periodic benefit cost	$	18		$	19		$	9		$	10

Pension and Other Postretirement Benefits

Net periodic benefit cost related to continuing operations 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 pension and other postretirement benefit costs related to continuing operations.

Pension Contributions

PHI’s funding policy with regard to PHI’s noncontributory retirement plan (the PHI Retirement Plan) is to maintain a funding level that is at least equal to the funding target level under the Pension Protection Act of 2006. Although PHI projects there will be no minimum funding requirement under the Pension Protection Act guidelines in 2011, PHI currently anticipates that it or its subsidiaries may make aggregate discretionary tax-deductible contributions in 2011 of up to $150 million to bring its plan assets to at least the funding target level for 2011 under the Pension Protection Act.

On March 14, 2011, Pepco, ACE and DPL made discretionary tax-deductible contributions to the PHI Retirement Plan in the amounts of $40 million, $30 million and $40 million, respectively. During 2010, PHI Service Company made discretionary tax-deductible contributions totaling $100 million to the PHI Retirement Plan, which brought plan assets to the funding target level for 2010 under the Pension Protection Act. Pepco, ACE and DPL did not make contributions to the PHI Retirement Plan in 2010.

(9) DEBT

Credit Facilities

PHI’s principal credit source is an unsecured $1.5 billion syndicated credit facility, which can be used by PHI and its utility subsidiaries to borrow funds, obtain letters of credit and support the issuance of commercial paper. This facility is in effect until May 2012. At the PHI level, the 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 collectively, at any given time, may not exceed $625 million.

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In October 2010, PHI 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 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 the $1.5 billion credit facility or either of the bi-lateral credit agreements. Neither the credit facility nor the bi-lateral credit agreements include 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 March 31, 2011, each borrower was in compliance with its covenants under the primary credit facilities to which it is a party.

At March 31, 2011 and December 31, 2010, the amount of cash plus borrowing capacity under the primary credit facilities available to meet the future liquidity needs of PHI and its utility subsidiaries on a consolidated basis each totaled $1.2 billion. PHI’s utility subsidiaries had combined cash and borrowing capacity under the $1.5 billion credit facility of $455 million and $462 million at March 31, 2011 and December 31, 2010, respectively.

Financing Activities

In January 2011, ACE Funding made principal payments of $6 million on Series 2002-1 Bonds, Class A-2, and $2 million on Series 2003-1 Bonds, Class A-2.

Financing Activities Subsequent to March 31, 2011

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

On May 2, 2011, DPL repurchased, pursuant to a mandatory repurchase obligation, $35 million of 4.9% Delaware Economic Development Authority tax- exempt put bonds due May 1, 2026. DPL plans to remarket these bonds during the second quarter of 2011.

Collateral Requirements of Pepco Energy Services

Pepco Energy Services, in the ordinary course of its retail energy supply business, enters into various contracts to buy and sell electricity, fuels and related products, including derivative instruments, designed to reduce its financial exposure to changes in the value of its assets and obligations due to energy price fluctuations. These contracts typically have collateral requirements. Depending on the contract terms, the collateral required to be posted by Pepco Energy Services can be of varying forms, including cash and letters of credit.

During periods of declining energy prices, Pepco Energy Services 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

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amounts over the life of the arrangement based on the fair value of the underlying contracts at the time of the novation. For the three months ended March 31, 2011 and 2010, Pepco Energy Services recognized less than $1 million and approximately $2 million, respectively, of the fees in “Interest expense.”

As of March 31, 2011, Pepco Energy Services had posted net cash collateral of $87 million and provided letters of credit of $92 million. At December 31, 2010, Pepco Energy Services had posted net cash collateral of $117 million and provided letters of credit of $113 million. As its retail energy supply business is wound down, Pepco Energy Services’ collateral requirements will be further reduced.

Collateral Requirements

At March 31, 2011 and December 31, 2010, the aggregate amount of cash, plus borrowing capacity under the credit facilities available to meet the combined future liquidity needs of Pepco Energy Services totaled $724 million and $728 million, respectively.

(10) INCOME TAXES

A reconciliation of PHI’s consolidated effective income tax rate from continuing operations is as follows:

	Three Months Ended March 31,
	2011					2010
	(millions of dollars)
Income tax at federal statutory rate	$	33		35.0	%	$	19		35.0	%
Increases (decreases) resulting from:
Depreciation		—		—			1		1.9
State income taxes, net of federal effect		5		5.0			4		7.5
Cross-border energy lease investments		(1	)	(1.2	)		(1	)	(1.9	)
Change in estimates and interest related to uncertain and effectively settled tax positions		1		1.2			9		17.0
Tax credits		(1	)	(1.2	)		(1	)	(1.9	)
Medicare Part D subsidy		—		—			4		7.5
Release of valuation allowance		—		—			(8	)	(15.1	)
Permanent differences related to deferred compensation funding		(2	)	(2.2	)		—		—
Other, net		(1	)	(1.2	)		(2	)	(2.8	)
Consolidated income tax expense related to continuing operations	$	34		35.4	%	$	25		47.2	%

PHI’s consolidated effective tax rates from continuing operations for the three months ended March 31, 2011 and 2010 were 35.4% and 47.2%, respectively. The reduction in the effective tax rate is partially due to changes in estimates and interest related to uncertain and effectively settled tax positions that had increased PHI’s effective tax rate for the three months ended March 31, 2010. The changes, primarily related to a $2 million reversal of accrued interest income on state income tax positions that PHI no longer believes is more likely than not to be realized and the reversal of $6 million of erroneously accrued interest income on uncertain and effectively settled state income tax positions, each recorded in 2010.

The decrease in the rate is further impacted by the 2010 change in taxation of the Medicare Part D subsidy enacted by the Patient Protection and Affordable Care Act (Patient Protection Act) that increased PHI’s effective tax rate for the three months ended March 31, 2010. PHI receives a tax-free federal subsidy for the costs it incurs for certain prescription drugs covered under its post-employment benefit plan. Prior to the Patient Protection Act, the costs incurred for those prescription drugs were also tax deductible. The Patient

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Protection Act includes a provision, effective beginning in 2013, which eliminates the tax deductibility of the prescription drug costs. As a result, PHI wrote off $5 million of deferred tax assets. Of this amount, $3 million was established as a regulatory asset, which PHI anticipates will be recoverable from its utility customers in the future. This change increased PHI’s first quarter 2010 tax expense by $4 million, which was partially offset through a reduction in Operating Expenses resulting in a $2 million decrease to net income.

The decrease in the rate between 2011 and 2010 is also affected by the 2010 release of $8 million of valuation allowances on deferred tax assets related to state net operating losses resulting from the planned restructuring of certain PHI subsidiaries. On April 1, 2010, as part of an ongoing effort to simplify PHI’s organizational structure, certain of PHI’s subsidiaries were converted to single member limited liability companies. In addition to increased organizational flexibility and reduced administrative costs, a consequence of converting these entities is to allow PHI to include income or losses in the former corporations in a single state income tax return, thus permitting the release of the valuation allowances.

(11) NON-CONTROLLING INTEREST

On February 25, 2011, ACE redeemed all of its outstanding cumulative preferred stock for approximately $6 million.

(12) EARNINGS PER SHARE

Reconciliations of the numerator and denominator for basic and diluted earnings per share (EPS) of common stock calculations are shown below:

	Three Months Ended March 31,
	2011		2010
	(millions of dollars, except per share data)
Income (Numerator):
Net income from continuing operations	$	62	$	28
Net income from discontinued operations		2		8
Net income	$	64	$	36
Shares (Denominator) (in millions):
Weighted average shares outstanding for basic computation:
Average shares outstanding		225		222
Adjustment to shares outstanding		—		—
Weighted Average Shares Outstanding for Computation of Basic Earnings Per Share of Common Stock		225		222
Net effect of potentially dilutive shares (a)		—		—
Weighted Average Shares Outstanding for Computation of Diluted Earnings Per Share of Common Stock		225		222
Basic and diluted earnings per share of common stock from continuing operations	$	0.27	$	0.13
Basic and diluted earnings per share of common stock from discontinued operations		0.01		0.03
Basic and diluted earnings per share	$	0.28	$	0.16

(a) The number of options to purchase shares of common stock that were excluded from the calculation of diluted EPS because they were anti-dilutive were 133,066 and 285,266 for the three months ended March 31, 2011 and 2010, respectively.

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(13) DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Derivatives are used by the Pepco Energy Services and Power Delivery segments to hedge commodity price risk, as well as by PHI, from time to time, to hedge interest rate risk.

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 physical natural gas and electricity for distribution to customers. The primary risk management objective is to manage the spread between retail sales commitments and the cost of supply used to service those commitments to ensure stable cash flows and lock in favorable prices and margins when they become available.

Pepco Energy Services’ commodity contracts that are not designated for hedge accounting, do not qualify for hedge accounting, or do not meet the requirements for normal purchase and normal sale accounting are marked to market through current earnings. Forward contracts that meet the requirements for normal purchase and normal sale accounting are accounted for using accrual accounting.

In the Power Delivery business, DPL uses derivative instruments in the form of swaps and over-the-counter options primarily to reduce gas commodity price volatility and to 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 from its customers through a fuel adjustment clause approved by the DPSC.

PHI also uses derivative instruments from time to time to mitigate the effects of fluctuating interest rates on debt 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 treasury rate locks were terminated at a loss. The loss has been deferred in Accumulated Other Comprehensive Loss (AOCL) and is being recognized in income over the life of the debt issued as interest payments are made.

The tables below identify the balance sheet location and fair values of derivative instruments as of March 31, 2011 and December 31, 2010:

	As of March 31, 2011
Balance Sheet Caption	Derivatives Designated as Hedging Instruments			Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting			Net Derivative Instruments
	(millions of dollars)
Derivative Assets (current assets)	$	38		$	33		$	71		$	(40	)	$	31
Derivative Assets (non-current assets)		7			2			9			(9	)		—
Total Derivative Assets		45			35			80			(49	)		31
Derivative Liabilities (current liabilities)		(106	)		(53	)		(159	)		98			(61	)
Derivative Liabilities (non-current liabilities)		(47	)		(9	)		(56	)		42			(14	)
Total Derivative Liabilities		(153	)		(62	)		(215	)		140			(75	)
Net Derivative (Liability) Asset	$	(108	)	$	(27	)	$	(135	)	$	91		$	(44	)

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	As of December 31, 2010
Balance Sheet Caption	Derivatives Designated as Hedging Instruments			Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting			Net Derivative Instruments
	(millions of dollars)
Derivative Assets (current assets)	$	40		$	43		$	83		$	(38	)	$	45
Derivative Assets (non-current assets)		16			3			19			(19	)		—
Total Derivative Assets		56			46			102			(57	)		45
Derivative Liabilities (current liabilities)		(125	)		(63	)		(188	)		122			(66	)
Derivative Liabilities (non-current liabilities)		(68	)		(10	)		(78	)		57			(21	)
Total Derivative Liabilities		(193	)		(73	)		(266	)		179			(87	)
Net Derivative (Liability) Asset	$	(137	)	$	(27	)	$	(164	)	$	122		$	(42	)

Under FASB guidance on the offsetting of balance sheet accounts (ASC 210-20), PHI offsets the fair value amounts recognized for derivative instruments and the fair value amounts recognized for related collateral positions executed with the same counterparty under master netting agreements. The amount of cash collateral that was offset against these derivative positions is as follows:

	March 31, 2011		December 31, 2010
	(millions of dollars)
Cash collateral pledged to counterparties with the right to reclaim (a)	$	91	$	122

(a) Includes cash deposits on commodity brokerage accounts

As of March 31, 2011 and December 31, 2010, all PHI cash collateral pledged related to derivative instruments accounted for at fair value was entitled to 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. Effective January 1, 2011, Pepco Energy Services elected to no longer apply cash flow hedge accounting to its natural gas derivatives. Amounts included in AOCL for natural gas flow hedges will remain and be reflected in earnings as the hedge transactions are completed. Cash flow hedge activity during the three months ended March 31, 2011 and 2010 is provided in the tables below:

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	Three Months Ended March  31,
	2011			2010
	(millions of dollars)
Amount of net pre-tax loss arising during the period included in accumulated other comprehensive loss	$	(1	)	$	(90	)
Amount of net pre-tax loss reclassified into income:
Effective portion:
Fuel and Purchased Energy		27			46
Ineffective portion: (a)
Revenue		—			3
Total net pre-tax loss reclassified into income		27			49
Net pre-tax gain (loss) on commodity derivatives included in accumulated other comprehensive loss	$	26		$	(41	)

(a) For the three months ended March 31, 2011 and 2010, no amounts were reclassified from AOCL to income because the forecasted hedged transactions were deemed probable not to occur.

As of March 31, 2011 and December 31, 2010, 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	March 31, 2011		December 31, 2010
Forecasted Purchases Hedges
Natural gas (One Million British Thermal Units (MMBtu))		—		8,597,106
Electricity (Megawatt hours (MWh))		3,130,280		2,677,640
Electricity Capacity (MW-Days)		—		34,730
Forecasted Sales Hedges
Electricity (MWh)		1,829,360		2,517,200

Power Delivery

All premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all of DPL’s gains and losses related to hedging activities, are deferred under FASB guidance on regulated operations until recovered from customers through a fuel adjustment clause approved by the DPSC. The following table indicates the amounts of the net unrealized derivative gain (loss) deferred as a regulatory liability (regulatory asset) and the realized loss recognized in the Consolidated Statements of Income for the three months ended March 31, 2011 and 2010:

	Three Months Ended March  31,
	2011			2010
	(millions of dollars)
Net Unrealized Gain (Loss) Deferred as a Regulatory Liability (Asset)	$	1		$	(5	)
Net Realized Loss Recognized in Fuel and Purchased Energy Expense		(2	)		(2	)

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As of March 31, 2011 and December 31, 2010, DPL had the following outstanding commodity forward contracts that were entered into to hedge forecasted transactions:

	Quantities
Commodity	March 31, 2011		December 31, 2010
Forecasted Purchases Hedges
Natural Gas (MMBtu)		1,225,000		1,670,000

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 March 31, 2011 and 2010. 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 March 31, 2011
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)	$	62	$	38		38 months
Interest Rate		11		1		257 months
Total	$	73	$	39

(a) AOCL on PHI’s Consolidated Balance Sheet as of March 31, 2011, 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 distribution. Although Pepco Energy Services no longer designates its natural gas derivatives as cash flow hedges effective January 1, 2011, gains or losses previously deferred in AOCL as of December 31, 2010 would remain in AOCL unless it is probable that the hedged forecasted transaction will not occur. At March 31, 2011, the amount remaining in AOCL was $51 million.

	As of March 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)	$	124	$	74		50 months
Interest Rate		21		3		269 months
Total	$	145	$	77

(a) AOCL on PHI’s Consolidated Balance Sheet as of March 31, 2010, includes a $17 million balance related to minimum pension liability and a $145 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 distribution.

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PEPCO HOLDINGS

Other Derivative Activity

Pepco Energy Services

Pepco Energy Services holds certain derivatives that are not in hedge accounting relationships nor are they designated as normal purchases or normal sales. These derivatives are recorded at fair value on the balance sheet with changes in fair value recorded through income.

For the three months ended March 31, 2011 and 2010, the amount of the derivative gain (loss) for Pepco Energy Services recognized in income is provided in the table below:

	Three Months Ended March 31, 2011								Three Months Ended March 31, 2010
	Revenue			Fuel and Purchased Energy Expense		Total			Revenue		Fuel and Purchased Energy Expense		Total
	(millions of dollars)
Realized mark-to-market gains (losses)	$	(4	)	$	—	$	(4	)	$	1	$	—	$	1
Unrealized mark-to-market gains (losses)		—			—		—			—		—		—
Total net mark-to-market gains (losses)	$	(4	)	$	—	$	(4	)	$	1	$	—	$	1

As of March 31, 2011 and December 31, 2010, Pepco Energy Services had the following net outstanding commodity forward contract volumes and net position on derivatives that did not qualify for hedge accounting:

	March 31, 2011			December 31, 2010
Commodity	Quantity		Net Position	Quantity		Net Position
Financial transmission rights (MWh)		122,666	Short		381,215	Long
Electric Capacity (MW–Days)		48,045	Short		2,265	Short
Electric (MWh)		1,263,480	Short		1,455,800	Short
Natural gas (MMBtu)		43,386,006	Short		45,889,486	Short

Power Delivery

DPL holds certain derivatives that are not in hedge accounting relationships nor are they designated as normal purchases or normal sales. These derivatives are recorded at fair value on the Consolidated Balance Sheets with the gain or loss for the change in fair value recorded in income. In accordance with FASB guidance on regulated operations, offsetting regulatory liabilities or regulatory assets are recorded on the Consolidated Balance Sheets and the recognition of the gain or loss is deferred because of the DPSC-approved fuel adjustment clause. For the three months ended March 31, 2011 and 2010, the net amount of the unrealized derivative gain (loss) deferred as a regulatory liability (regulatory asset) and the net realized loss recognized in the Consolidated Statements of Income is provided in the table below:

	Three Months Ended March  31,
	2011			2010
	(millions of dollars)
Net Unrealized Gain (Loss) Deferred as a Regulatory Liability (Asset)	$	7		$	(6	)
Net Realized Loss Recognized in Fuel and Purchased Energy Expense		(7	)		(7	)

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As of March 31, 2011 and December 31, 2010, DPL had the following net outstanding natural gas commodity forward contracts that did not qualify for hedge accounting:

	March 31, 2011			December 31, 2010
Commodity	Quantity		Net Position	Quantity		Net Position
Natural Gas (MMBtu)		6,748,882	Long		7,827,635	Long

Contingent Credit Risk Features

The primary contracts used by the Pepco Energy Services and Power Delivery segments for derivative transactions are entered into under the International Swaps and Derivatives Association Master Agreement (ISDA) or similar agreements that closely mirror the principal credit provisions of the ISDA. The ISDAs include a Credit Support Annex (CSA) that governs the mutual posting and administration of collateral security. The failure of a party to comply with an obligation under the CSA, including an obligation to transfer collateral security when due or the failure to maintain any required credit support, constitutes an event of default under the ISDA for which the other party may declare an early termination and liquidation of all transactions entered into under the ISDA, including foreclosure against any collateral security. In addition, some of the ISDAs have cross default provisions under which a default by a party under another commodity or derivative contract, or the breach by a party of another borrowing obligation in excess of a specified threshold, is a breach under the ISDA.

Under the ISDA or similar agreements, the parties establish a dollar threshold of unsecured credit for each party in excess of which the party would be required to post collateral to secure its obligations to the other party. The amount of the unsecured credit threshold varies according to the senior, unsecured debt rating of the respective parties or that of a guarantor of the party’s obligations. The fair values of all transactions between the parties are netted under the master netting provisions. Transactions may include derivatives accounted for on-balance sheet as well as those designated as normal purchases and normal sales that are accounted for off-balance sheet. If the aggregate fair value of the transactions in a net loss position exceeds the unsecured credit threshold, then collateral is required to be posted in an amount equal to the amount by which the unsecured credit threshold is exceeded. The obligations of Pepco Energy Services are usually guaranteed by PHI. The obligations of DPL are stand-alone obligations without the guaranty of PHI. If PHI’s or DPL’s credit rating were to fall below “investment grade,” the unsecured credit threshold would typically be set at zero and collateral would be required for the entire net loss position. Exchange-traded contracts are required to be fully collateralized without regard to the credit rating of the holder.

The gross fair value of PHI’s derivative liabilities, excluding the impact of offsetting transactions or collateral under master netting agreements, with credit risk-related contingent features on March 31, 2011 and December 31, 2010, was $127 million and $156 million, respectively, before giving effect to the impact of a credit rating downgrade that would increase these amounts or offsetting transactions that are encompassed within master netting agreements that would alter these amounts. As of those dates, PHI had not posted any cash collateral against the gross derivative liability. PHI’s net settlement amount in the event of a downgrade of PHI’s and DPL’s senior unsecured debt rating to below “investment grade” as of March 31, 2011 and December 31, 2010, would have been approximately $182 million and $176 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 under master netting agreements include derivatives and normal purchase and normal sale contracts in a gain position as well as letters of credit already posted as collateral. At March 31, 2011 and December 31, 2010, normal purchase and normal sale contracts in a loss position also increased PHI’s obligation.

PHI’s primary sources for posting cash collateral or letters of credit are its credit facilities. At March 31, 2011 and December 31, 2010, the aggregate amount of cash plus borrowing capacity under the primary credit facilities available to meet the future liquidity needs of PHI and its subsidiaries totaled $1.2 billion, of which $724 million and $728 million, respectively, was available to Pepco Energy Services.

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(14) 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) that established a framework for measuring fair value and expanded disclosures about fair value measurements. As defined in the guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). PHI utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. Accordingly, PHI utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1) and the lowest priority to unobservable inputs (level 3). PHI classifies its fair value balances in the fair value hierarchy based on the observability of the inputs used in the fair value calculation as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis, such as the New York Mercantile Exchange (NYMEX).

Level 2 – Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using broker quotes in liquid markets and other observable data. Level 2 also includes those financial instruments that are valued using 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.

PHI’s level 2 derivative instruments primarily consist of electricity derivatives at March 31, 2011. 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, which 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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PEPCO HOLDINGS

Executive deferred compensation plan assets and liabilities that are classified as level 3 include certain life insurance policies that are valued using the cash surrender value of the policies, net of loans against those policies, which does not represent a quoted price in an active market.

The following tables set forth, by level within the fair value hierarchy, PHI’s financial assets and liabilities (excluding assets and liabilities held for sale) that were accounted for at fair value on a recurring basis as of March 31, 2011 and December 31, 2010. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. PHI’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Fair Value Measurements at March 31, 2011
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)(a)		Significant Other Observable Inputs (Level 2)(a)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Derivative instruments (b)
Electricity (c)	$	17	$	—	$	17	$	—
Cash equivalents
Treasury Fund		19		19		—		—
Executive deferred compensation plan assets
Money Market Funds		11		11		—		—
Life Insurance Contracts		63		—		46		17
	$	110	$	30	$	63	$	17
LIABILITIES
Derivative instruments (b)
Electricity (c)	$	73	$	—	$	73	$	—
Natural Gas (d)		79		55		5		19
Executive deferred compensation plan liabilities
Life Insurance Contracts		30		—		30		—
	$	182	$	55	$	108	$	19

(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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PEPCO HOLDINGS

	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.

Reconciliations of the beginning and ending balances of PHI’s fair value measurements using significant unobservable inputs (level 3) for the three months ended March 31, 2011 and 2010 are shown below:

	Three Months Ended March 31, 2011
	Natural Gas			Life Insurance Contracts
	(millions of dollars)
Beginning balance as of January 1	$	(23	)	$	19
Total gains or (losses) (realized and unrealized)
Included in income		—			3
Included in accumulated other comprehensive loss		—			—
Included in regulatory liabilities		(1	)		—
Purchases		—			—
Issuances		—			(1	)
Settlements		5			(4	)
Transfers in (out) of level 3		—			—
Ending balance as of March 31	$	(19	)	$	17

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	Three Months Ended March  31, 2010
	Natural Gas			Life Insurance Contracts
	(millions of dollars)
Beginning balance as of January 1	$	(29	)	$	19
Total gains or (losses) (realized and unrealized)
Included in income		—			1
Included in accumulated other comprehensive loss		—			—
Included in regulatory liabilities		(12	)		—
Purchases		—			—
Issuances		—			(1	)
Settlements		4			—
Transfers in (out) of level 3		—			—
Ending balance as of March 31	$	(37	)	$	19

The breakdown of realized and unrealized gains or (losses) on level 3 instruments included in income as a component of “Other” income or “Other operation and maintenance” expense for the periods below were as follows:

	Three Months Ended March 31,
	2011		2010
	(millions of dollars)
Total gains included in income for the period	$	3	$	1
Change in unrealized gains relating to assets still held at reporting date	$	1	$	1

Fair Value of Debt and Equity Instruments

The estimated fair values of PHI’s issued debt and equity instruments at March 31, 2011 and December 31, 2010 are shown below:

	March 31, 2011				December 31, 2010
	(millions of dollars)
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	3,664	$	4,051	$	3,665	$	4,045
Transition Bonds issued by ACE Funding		359		394		367		406
Long-Term Project Funding		19		19		19		19
Redeemable Serial Preferred Stock		—		—		6		5

The fair value of Long-Term Debt issued by PHI and its utility subsidiaries was based on actual trade prices as of March 31, 2011 and December 31, 2010. Where trade prices were not available, PHI obtained and validated bid prices from brokers or used a discounted cash flow model 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 and validated by PHI 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.

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(15) COMMITMENTS AND CONTINGENCIES

Regulatory and Other Matters

District of Columbia Divestiture Case

In June 2000, the District of Columbia Public Service Commission (DCPSC) approved a divestiture settlement under which Pepco is required to share with its District of Columbia customers the net proceeds realized by Pepco from the sale of its generation-related assets in 2000. This approval left unresolved issues of (i) whether Pepco should be required to share with customers the excess deferred income taxes (EDIT) and accumulated deferred investment tax credits (ADITC) associated with the sold assets and, if so, whether such sharing would violate the normalization provisions of the Internal Revenue Code and its implementing regulations and (ii) whether Pepco was entitled to deduct certain costs in determining the amount of proceeds to be shared.

In May 2010, the DCPSC issued an order addressing all of the remaining issues related to the sharing of the proceeds of Pepco’s divestiture of its generating assets. In the order, the DCPSC ruled that Pepco is not required to share EDIT and ADITC with customers. However, the order also disallowed certain items that Pepco had included in the costs deducted from the proceeds of the sale of the generation assets. The disallowance of these costs, together with interest on the disallowed amount, increased the aggregate amount Pepco was required to distribute to customers, pursuant to the sharing formula, by approximately $11 million, which PHI recognized as an expense in 2010 and refunded the amounts to its customers. In June 2010, Pepco filed an application for reconsideration of the DCPSC’s order, 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). In July 2010, the DCPSC denied Pepco’s application for reconsideration. In September 2010, Pepco filed an appeal of the DCPSC’s decision with the District of Columbia Court of Appeals. On April 12, 2011, the Court of Appeals affirmed the DCPSC order. Pepco does not intend to appeal this decision.

Maryland Public Service Commission Reliability Investigation

In August 2010, following the major storm events that occurred in July and August 2010, the Maryland Public Service Commission (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. On March 2, 2011, an independent consultant retained by the MPSC to review and make recommendations regarding the reliability of Pepco’s distribution system and the quality of its service filed its report with the MPSC. Pepco is preparing its testimony, which will address the report and will be filed in advance of the hearings 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.

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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 bill stabilization adjustment (BSA) has been approved and implemented for Pepco and DPL electric service in Maryland and for Pepco electric service in the District of Columbia. The MPSC has 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 the implementation has been deferred by the DPSC pending the development of an implementation plan and a customer education plan. DPL anticipates that the MFVRD will be in place for electric service by early in 2012.

• A MFVRD has been approved in concept for DPL natural gas service in Delaware, but a proposed settlement in the pending base rate proceeding would defer the request for implementation until an implementation plan and a customer education plan are developed.

• In New Jersey, a BSA that had been proposed by ACE as part of a Phase 2 to its current base rate proceeding has not been included in a settlement filed on April 20, 2011, which is subject to NJBPU approval, and accordingly there is no BSA proposal currently pending.

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 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.

On February 1, 2011, the MPSC initiated proceedings for Pepco and DPL, as well as unaffiliated utilities including 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. The MPSC has scheduled a legislative-style hearing on this matter in July 2011. An adjustment to remove revenues lost as a result of major storm outages is already included in the BSA for Pepco in the District of Columbia as approved by the DCPSC. The materiality of any such BSA modifications that may be made by the MPSC would depend on the duration and extent of any major storm outages.

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Delaware

DPL makes an annual Gas Cost Rate (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 allowing DPL to place the new rates into effect on November 1, 2010, subject to refund and pending final DPSC approval. The effect of the proposed two-year amortization upon rates is an increase of 0.1% in the level of GCR. If the DPSC does not accept DPL’s proposal for a two-year amortization, the adjustment would result in an increase of 6.9% in the GCR.

In July 2010, DPL submitted an application with the DPSC to increase its natural gas distribution base rates. As subsequently amended in September 2010 (to replace test year data for the twelve months ended June 2010 with the actual data) and in October 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 return on equity (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 was placed into effect on February 2, 2011, in each case subject to refund and pending final DPSC approval. On February 9, 2011, DPL, DPSC staff, and the Attorney General of Delaware entered into a proposed settlement agreement, which provides for an annual rate increase of approximately $5.8 million, based on an ROE of 10%. In the settlement agreement, the parties agreed to defer the implementation of the MFVRD until an implementation plan and a customer education plan are developed. The proposed settlement agreement is subject to final review and approval by the DPSC. A decision is expected by the end of July 2011. The excess amount collected will be refunded to customers through a bill credit after final DPSC approval of a refund plan.

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. In August 2010, the MPSC issued an order approving a rate increase of approximately $7.8 million, based on an ROE of 9.83%, which Pepco placed into effect on August 19, 2010. In September 2010, Pepco filed with the MPSC a motion for reconsideration of the following issues, which, if approved, in the aggregate would increase annual revenue by approximately $8.5 million: (i) denial of inclusion in rate base of certain reliability plant investments, which occurred subsequent to the test period but before the rate effective period; (ii) denial of Pepco’s request to increase depreciation rates to reflect a corrected formula relating to the cost of removal expenses; and (iii) 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 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.

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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 terms of the sale, Calpine has assumed responsibility for performing the ISRA-required remediation and for the payment of all related ISRA compliance costs up to $10 million. PHI is obligated to indemnify Calpine for any ISRA compliance remediation costs in excess of $10 million. According to preliminary estimates, the costs of ISRA-required remediation activities at the nine generating facility sites located in New Jersey are in the range of approximately $7 million to $18 million. PHI has accrued approximately $4 million as of March 31, 2011 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 March 31, 2011, PHI had accrued approximately $5 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 has agreed to indemnify Calpine for any monetary penalties, fines or assessments arising out of the NJDEP orders. At this time, the costs to resolve this matter are not expected to be material.

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 March 31, 2011, 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 Corporation (Mirant) for defense and indemnification in connection with the sale by Pepco of its generation assets to Mirant in 2000.

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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, PHI and Pepco do not believe these suits will have a material adverse effect on their respective financial conditions, 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 CERCLA, which did not involve ACE, the U.S. Supreme Court rejected an EPA argument that the sale of a useful product constituted an arrangement for disposal or treatment of hazardous substances. While this decision supports ACE’s position, at this time ACE cannot predict how EPA will proceed with respect to the Franklin Slag Pile site, or what portion, if any, of the Franklin Slag Pile site response costs EPA would seek to recover from ACE. Costs to resolve this matter are not expected to be material.

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

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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. The amount of the remediation costs that may be imposed cannot be predicted at this time; however, based on current information, PHI and Pepco do not believe these suits will have a material adverse effect on their respective financial conditions, results of operations or cash flows.

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 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 and therefore, costs incurred to resolve this matter are not expected to be material.

Benning Road Site. In September 2010, PHI received a letter from EPA stating that EPA and the District of Columbia Department of the Environment (DDOE) have identified the Benning Road location, consisting of a transmission and distribution facility operated by Pepco and a generation facility operated by Pepco Energy Services, as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. The letter stated that the principal contaminants of concern are polychlorinated biphenyls (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, to clean up the facility) is not reached. In an October 2010 letter, 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 stated that EPA will list the Benning Road site on the NPL if contamination at the facility is not addressed in a timely manner. In January 2011, in response to these EPA and District of Columbia letters, Pepco and Pepco Energy Services entered into a consent decree with DDOE that requires 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. In February 2011, the consent decree was filed with the United States District Court, but will not become final until the DDOE files a motion requesting the District Court to enter the consent decree. In light of the consent decree, Pepco and Pepco Energy Services anticipate that EPA will recognize that Pepco and Pepco Energy Services are making constructive movement toward cleanup and 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. As of March 31, 2011, PHI had an accrued liability of $14 million with respect to 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

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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 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. The financial impact related to these amendments cannot be predicted at this time; however, based on current information, PHI and ACE do not believe these suits will have a material adverse effect on their respective financial conditions, results of operations or cash flows.

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. As of March 31, 2011, 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 during the remainder of 2011.

Potomac River Mineral Oil Release

On January 23, 2011, a coupling failure on a transformer cooler pipe resulted in a release of non-toxic mineral oil at Pepco’s Potomac River substation in Alexandria, Virginia. An overflow of an underground secondary containment reservoir resulted in approximately 4,500 gallons of mineral oil flowing into the Potomac River.

On March 22, 2011 and March 31, 2011, DDOE issued compliance directives that require Pepco to prepare an incident report, provide certain records, amend Pepco’s surface water and river sediments sampling plan and prepare ecological risk assessment and natural resources damage assessment work plans. Pepco is complying with DDOE’s compliance directives. On March 16, 2011, the Virginia Department of Environmental Quality (VADEQ) requested documentation regarding the release and the preparation of an emergency response report, which Pepco submitted to the agency on April 20, 2011. On March 25, 2011, Pepco received a notice of violation from VADEQ, which advised Pepco of information on which VADEQ may rely to institute an administrative or judicial enforcement action in connection with the mineral oil release and indicated that Pepco may be asked to enter into a consent order to formalize a corrective action plan and schedule. The amount of penalties, if any, that may be imposed by either or both of these agencies cannot be predicted at this time; however, based on current information, PHI and Pepco do not believe this matter will have a material adverse effect on their respective financial conditions, results of operations or cash flows.

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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 by the Internal Revenue Service (IRS) 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 $56 million. As of March 31, 2011, 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 March 31, 2011, PHI has claimed approximately $589 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.

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 IRS revenue agent’s reports 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 income tax return review 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 March 31, 2011, it would be obligated to pay approximately $636 million in additional federal and state taxes and $137 million of interest. The $636 million in additional federal and state taxes is net of the $74 million tax payment made in January 2011. In addition, the IRS could require PHI to pay a penalty of up to 20% on the amount of additional taxes due.

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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 $773 million in federal and state taxes and interest due as of March 31, 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.

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 District Council that imposes mandatory unitary combined reporting (MUCR) beginning with tax year 2011 for companies doing business in the District of Columbia. The Council must still enact further legislation providing guidance on how to implement MUCR before this legislation is effective. The required implementing legislation has been included in the Mayor’s budget proposal (the Budget Bill) for the fiscal year ending September 30, 2012, which was submitted to the Council on April 1, 2011.

Based upon PHI’s interpretation of the language in the Budget Bill, the legislation would, if enacted, result in a change in PHI’s overall state income tax rate and could require a material 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. Public hearings will be held on the Budget Bill in May 2011, with a vote to be taken by the Council on June 7, 2011. If the Council approves the Budget Bill, including the MUCR implementation guidance, the legislation is subject to a 30-day Congressional review period and, if Congress does not intervene during this review period, the legislation will become binding law. The effect of the legislation has not been accounted for as of March 31, 2011, because the legislative process was not complete.

Management continues to analyze the impact that the tax reporting aspects 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.

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As of March 31, 2011, 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		DPL		ACE		Pepco		Total
Energy marketing obligations of Conectiv Energy (a)	$	10	$	—	$	—	$	—	$	10
Energy procurement obligations of Pepco Energy Services (a)		218		—		—		—		218
Guarantees associated with disposal of Conectiv Energy assets (b)		45		—		—		—		45
Guaranteed lease residual values (c)		2		5		3		3		13
Total	$	275	$	5	$	3	$	3	$	286

(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 customer load obligations of Pepco Energy Services.

(b) Represents guarantees by PHI in connection with transfers of a Conectiv Energy tolling agreement and derivatives portfolio. The tolling agreement guarantee covers the payment performance of the entity to which the tolling agreement was assigned. The guaranteed amount was $20 million at March 31, 2011, and declines monthly through the second quarter of 2012 when the tolling agreement terminates. The derivative portfolio guarantee is currently $25 million and covers Conectiv Energy’s performance prior to the assignment. This guarantee will reduce to approximately $13 million in July 2011 and remain in effect until the end of 2015.

(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 March 31, 2011, obligations under the guarantees were approximately $13 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 guarantee is remote.

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.

Energy Savings Performance Contracts

Pepco Energy Services has a diverse portfolio of energy savings performance contracts that are associated with the installation of energy savings equipment for federal, state and local government customers. As part of those contracts, Pepco Energy Services typically guarantees that the equipment or systems installed by Pepco Energy Services will generate a specified amount of energy savings on an annual basis over a multi-year period. As of March 31, 2011, Pepco Energy Services’ energy savings guarantees on both completed projects and projects under construction totaled $405 million over the life of the performance contracts with the longest remaining term being 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 and the amount is reasonably estimable. The accrued liability for energy savings performance contracts has not changed significantly during the three months ended March 31, 2011 and currently is less than $1 million. Pepco Energy Services did not make any significant payouts under the contracts and there was no significant change in the type of contracts issued for the three months ended March 31, 2011. Based on its historical experience, Pepco Energy Services believes the probability of incurring a material loss under its energy savings performance contracts is remote.

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PEPCO HOLDINGS

Dividends

On April 28, 2011, Pepco Holdings’ Board of Directors declared a dividend on common stock of 27 cents per share payable June 30, 2011, to shareholders of record on June 10, 2011.

(16) DISCONTINUED OPERATIONS

In April 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 day entered into a 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 the wholesale power generation business to Calpine from which PHI received proceeds at the closing in the amount of approximately $1.64 billion. The liquidation of the remaining Conectiv Energy assets and businesses has been substantially completed.

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 are as follows:

	Three Months Ended March  31,
	2011			2010
	(millions of dollars)
Income from operations of discontinued operations, net of income taxes	$	3		$	8
Net losses from dispositions of assets and businesses of discontinued operations, net of income taxes		(1	)		—
Income From Discontinued Operations, net of income taxes	$	2		$	8

Income from operations of discontinued operations, net of income taxes for the three months ended March 31, 2011, includes after-tax income of $4 million arising from adjustments to certain accrued expenses for obligations associated with the sale of the wholesale power generation business to Calpine. These adjustments were made to reflect the actual amounts paid to Calpine during the first quarter of 2011.

Net losses from dispositions of assets and businesses of discontinued operations, net of income taxes for the three months ended March 31, 2011 includes an expense of approximately $1 million (after-tax) which was incurred in connection with the financial transaction entered into with a third party on January 6, 2011, 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 paid the third party $82 million, primarily representing the fair value of the derivatives at February 1, 2011, and an after-tax administrative fee of $1 million. Substantially all of the mark-to-market gains and losses associated with these derivatives were recorded in earnings through December 31, 2010 and accordingly no additional material gain or loss was recognized as a result of this transaction in 2011.

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PEPCO HOLDINGS

Balance Sheet Information

Details of the assets and liabilities of Conectiv Energy held for sale at March 31, 2011 and December 31, 2010 are as follows:

	March 31, 2011			December 31, 2010
	(millions of dollars)
Current Assets
Cash and cash equivalents	$	—		$	1
Accounts receivable, less allowance for uncollectible accounts		8			81
Inventories		8			20
Derivative assets		—			3
Prepaid expenses and other		5			6
Total Current Assets		21			111
Investments and Other Assets
Derivative assets		—			4
Other		1			2
Total Investments and Other Assets		1			6
Property, Plant and Equipment
Property, plant and equipment		1			2
Accumulated depreciation		(1	)		(2	)
Net Property, Plant and Equipment		—			—
Current Liabilities
Accounts payable and accrued liabilities		3			40
Derivative liabilities		—			15
Other		6			7
Total Current Liabilities		9			62
Deferred Credits
Derivative liabilities		—			10
Other		—			—
Total Deferred Credits		—			10
Net Assets	$	13		$	45

41

PEPCO HOLDINGS

Derivative Instruments and Hedging Activities

Conectiv Energy used derivative instruments primarily to reduce its financial exposure to changes in the value of its assets and obligations due to commodity price fluctuations. The derivative instruments used included forward contracts, futures, swaps, and exchange-traded and over-the-counter options. The two primary risk management objectives were: (i) to manage the spread between the cost of fuel used to operate electric generation facilities and the revenue received from the sale of the power produced by those facilities, and (ii) to manage the spread between wholesale sale commitments and the cost of supply used to service those commitments to ensure stable cash flows and lock in favorable prices and margins when they became available.

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 accounted 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 were marked to market through current earnings. All option contracts were marked to market through current earnings. Certain natural gas and oil futures and swaps were used as fair value hedges to protect the value of natural gas transportation contracts and physical fuel inventory. Some forward contracts were accounted for using standard accrual accounting since these contracts met the requirements for normal purchase and normal sale accounting.

As of March 31, 2011, Conectiv Energy had no material energy commodity contracts and substantially all cash collateral had been returned.

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PEPCO HOLDINGS

The tables below identify the balance sheet location and fair values of Conectiv Energy’s derivative instruments as of March 31, 2011 and December 31, 2010:

	As of March 31, 2011
Balance Sheet Caption	Derivatives Designated as Hedging Instruments		Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting			Net Derivative Instruments
	(millions of dollars)
Derivative Assets (current assets held for sale)	$	—	$	1		$	1		$	(1	)	$	—
Derivative Assets (non-current assets held for sale)		—		—			—			—			—
Total Derivative Assets		—		1			1			(1	)		—
Derivative Liabilities (current liabilities associated with assets held for sale)		—		(1	)		(1	)		1			—
Derivative Liabilities (non-current liabilities associated with assets held for sale)		—		—			—			—			—
Total Derivative Liabilities		—		(1	)		(1	)		1			—
Net Derivative (Liability) Asset	$	—	$	—		$	—		$	—		$	—

	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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PEPCO HOLDINGS

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:

	March 31, 2011		December 31, 2010
	(millions of dollars)
Cash collateral pledged to counterparties with the right to reclaim	$	—	$	65

As of December 31, 2010, all cash collateral pledged 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 three months ended March 31, 2011 and 2010 is provided in the table below:

	Three Months Ended March  31,
	2011		2010
	(millions of dollars)
Amount of net pre-tax loss arising during the period included in other comprehensive loss	$	—	$	(118	)
Amount of net pre-tax loss reclassified into income:
Effective portion:
Loss from discontinued operations, net of income taxes		—		45
Ineffective portion:
Loss from discontinued operations net of income taxes (a)		—		3
Total net pre-tax loss reclassified into income		—		48
Net pre-tax loss on commodity derivatives included in other comprehensive loss comprehensive loss	$	—	$	(70	)

(a) For the three months ended March 31, 2011 and 2010, amounts of zero and $1 million, respectively, were reclassified from AOCL to income because the forecasted transactions were deemed probable not to occur.

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PEPCO HOLDINGS

As of March 31, 2011 and December 31, 2010, Conectiv Energy had no energy commodity contracts employed as cash flow hedges.

Cash Flow Hedges Included in Accumulated Other Comprehensive Loss

As of March 31, 2011, Conectiv Energy had no remaining AOCL. The table below provides details regarding effective cash flow hedges of Conectiv Energy included in PHI’s Consolidated Balance Sheet as of March 31, 2010. Cash flow hedges are marked to market on the Consolidated Balance Sheet with corresponding adjustments to AOCL to the extent the hedges are effective. The data in the table indicates 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 March 31, 2010 (a)	$	145	$	202		45 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.

Other Derivative Activity

In connection with its energy commodity activities, Conectiv Energy held certain derivatives that did 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 three months ended March 31, 2011 and 2010, is provided in the table below:

	For the Three Months Ended March 31,
	2011		2010
	(millions of dollars)
Realized mark-to-market gains	$	—	$	3
Unrealized mark-to-market (losses) gains		—		(1	)
Total net mark-to-market gains (losses)	$	—	$	2

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PEPCO HOLDINGS

As of March 31, 2011 and December 31, 2010, Conectiv Energy had the following net outstanding commodity forward contract volumes and net positions on derivatives that did not qualify for hedge accounting:

	March 31, 2011			December 31, 2010
Commodity	Quantity		Net Position	Quantity		Net Position
Natural gas (MMBtu)		—	—		450,000	Long
Heating oil (Barrels)		2,000	Short		64,000	Short
Electricity (MWh)		—	—		1,200	Long
Financial transmission rights (MWh)		153,744	Short		702,358	Short

Contingent Credit Risk Features

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 March 31, 2011 and December 31, 2010 was zero and $117 million, respectively. As of those dates, Conectiv Energy had posted cash collateral of zero and $12 million, respectively, in the normal course of business against the gross derivative liability resulting in a net liability of zero and $105 million, respectively, before giving effect to offsetting transactions that are encompassed within master netting agreements that would reduce this amount.

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. 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. As of March 31, 2011, Conectiv Energy had posted net cash collateral of less than $1 million and there were no letters of credit outstanding.

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 (14), “Fair Value Disclosures.”

As of March 31, 2011, Conectiv Energy’s financial assets and liabilities that were accounted for at fair value were immaterial.

As of December 31, 2010, level 2 instruments consist of electricity and natural gas 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 estimates of fair value for level 3 electricity derivatives at December 31, 2010 were calculated with the use of pricing information obtained from a third party pricing system used widely throughout the energy industry.

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PEPCO HOLDINGS

The following table sets 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:

	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 Interconnection, LLC Load service strategy.

Reconciliations of the beginning and ending balances of Conectiv Energy’s fair value measurements using significant unobservable inputs (Level 3) for the three months ended March 31, 2011 and 2010 are shown below:

	For the Three Months Ended March 31,
	2011			2010
	(millions of dollars)
Beginning balance as of January 1	$	3		$	27
Total gains or (losses) (realized and unrealized)
Included in loss from discontinued operations, net of taxes (a)		—			69
Included in accumulated other comprehensive loss		—			5
Purchases		—			—
Issuances		—			—
Settlements		(3	)		(27	)
Transfers in (out) of Level 3		—			—
Ending balance as of March 31	$	—		$	74

(a) As of March 31, 2010, $56 million of the $69 million gain is unrealized.

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PEPCO HOLDINGS

(17) RESTRUCTURING CHARGE

With the ongoing wind down of the retail energy supply business of Pepco Energy Services and the disposition of Conectiv Energy, PHI repositioned itself as a regulated transmission and distribution company during 2010. In connection with this repositioning, PHI completed a comprehensive organizational review in 2010 that identified opportunities to streamline the organization and to achieve certain reductions in corporate overhead costs that are allocated to its operating segments, which resulted in the adoption of a restructuring plan. PHI began implementation of the plan during 2010, identifying 164 employee positions that were eliminated. The plan also includes additional cost reduction opportunities that are being implemented through process improvements and operational efficiencies.

In connection with the restructuring plan, PHI recorded a pre-tax restructuring charge of $30 million in 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 was allocated to PHI’s operating segments and was reflected as a separate line item in the Consolidated Statements of Income at December 31, 2010.

Reconciliations of PHI’s accrued restructuring charges for the three months ended March 31, 2011 are as follows:

	Three Months Ended March 31, 2011
	(millions of dollars)
	Power Delivery			Pepco Energy Services		Other Non- Regulated		Corporate and Other			PHI Consolidated
Beginning balance as of January 1, 2011	$	28		$	—	$	—	$	1		$	29
Restructuring charge		—			—		—		—			—
Cash payments		(20	)		—		—		(1	)		(21	)
Ending balance as of March 31, 2011	$	8		$	—	$	—	$	—		$	8

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PEPCO

POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended March 31,
	2011			2010
	(millions of dollars)
Operating Revenue	$	534		$	552
Operating Expenses
Purchased energy		255			315
Other operation and maintenance		102			88
Depreciation and amortization		42			38
Other taxes		92			75
Total Operating Expenses		491			516
Operating Income		43			36
Other Income (Expenses)
Interest expense		(24	)		(25	)
Other income		6			3
Total Other Expenses		(18	)		(22	)
Income Before Income Tax Expense		25			14
Income Tax Expense		7			6
Net Income		18			8
Retained Earnings at Beginning of Period		723			730
Dividends Paid to Parent		—			(25	)
Retained Earnings at End of Period	$	741		$	713

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

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PEPCO

POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

(Unaudited)

	March 31, 2011			December 31, 2010
	(millions of dollars)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	116		$	88
Accounts receivable, less allowance for uncollectible accounts of $19 million and $20 million, respectively		345			373
Inventories		48			44
Prepayments of income taxes		47			95
Income taxes receivable		32			37
Prepaid expenses and other		24			34
Total Current Assets		612			671
INVESTMENTS AND OTHER ASSETS
Regulatory assets		207			191
Prepaid pension expense		308			274
Investment in trust		25			25
Income taxes receivable		27			34
Other		59			57
Total Investments and Other Assets		626			581
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		6,268			6,185
Accumulated depreciation		(2,636	)		(2,609	)
Net Property, Plant and Equipment		3,632			3,576
TOTAL ASSETS	$	4,870		$	4,828

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

50

PEPCO

POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

(Unaudited)

	March 31, 2011		December 31, 2010
	(millions of dollars, except shares)
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities	$	179	$	194
Accounts payable due to associated companies		65		75
Capital lease obligations due within one year		7		8
Taxes accrued		64		62
Interest accrued		37		18
Other		108		119
Total Current Liabilities		460		476
DEFERRED CREDITS
Regulatory liabilities		155		147
Deferred income taxes, net		983		958
Investment tax credits		6		7
Other postretirement benefit obligations		68		67
Income taxes payable		2		3
Liabilities and accrued interest related to uncertain tax positions		57		52
Other		67		64
Total Deferred Credits		1,338		1,298
LONG-TERM LIABILITIES
Long-term debt		1,540		1,540
Capital lease obligations		86		86
Total Long-Term Liabilities		1,626		1,626
COMMITMENTS AND CONTINGENCIES (NOTE 10)
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		741		723
Total Equity		1,446		1,428
TOTAL LIABILITIES AND EQUITY	$	4,870	$	4,828

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

51

PEPCO

POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March  31,
	2011			2010
	(millions of dollars)
OPERATING ACTIVITIES
Net income	$	18		$	8
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		42			38
Deferred income taxes		26			16
Changes in:
Accounts receivable		28			2
Inventories		(4	)		(4	)
Regulatory assets and liabilities, net		(4	)		8
Accounts payable and accrued liabilities		(33	)		(15	)
Pension contribution		(40	)		—
Taxes accrued		50			13
Interest accrued		19			19
Other assets and liabilities		16			12
Net Cash From Operating Activities		118			97
INVESTING ACTIVITIES
Investment in property, plant and equipment		(97	)		(65	)
Department of Energy capital reimbursement awards received		8			—
Changes in restricted cash equivalents		—			1
Net other investing activities		(1	)		—
Net Cash Used By Investing Activities		(90	)		(64	)
FINANCING ACTIVITIES
Dividends paid to Parent		—			(25	)
Reacquisition of long-term debt		—			(16	)
Net other financing activities		—			(5	)
Net Cash Used by Financing Activities		—			(46	)
Net Increase (Decrease) in Cash and Cash Equivalents		28			(13	)
Cash and Cash Equivalents at Beginning of Period		88			213
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	116		$	200
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash received for income taxes (includes payments from PHI for Federal income taxes)	$	70		$	23

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

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PEPCO

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 energy 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

Financial Statement Presentation

Pepco’s unaudited financial statements are prepared in conformity with accounting principles generally accepted in the United States of America (GAAP). Pursuant to the rules and regulations of the Securities and Exchange Commission, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been omitted. Therefore, these financial statements should be read along with the annual financial statements included in Pepco’s Annual Report on Form 10-K for the year ended December 31, 2010. In the opinion of Pepco’s management, the financial statements contain all adjustments (which all are of a normal recurring nature) necessary to present fairly Pepco’s financial condition as of March 31, 2011, in accordance with GAAP. The year-end December 31, 2010 Balance Sheet was derived from audited financial statements, but does not include all disclosures required by GAAP. Interim results for the three months ended March 31, 2011 may not be indicative of results that will be realized for the full year ending December 31, 2011 since the sales of electric energy are seasonal.

Use of Estimates

The preparation of financial statements in conformity with 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 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 it is probable that a loss has been incurred and the loss is reasonably estimable.

Network Service Transmission Rates

In May of every year, Pepco provides its updated network service transmission rate to the Federal Energy Regulatory Commission (FERC) to be effective for June 1 of that year through May 31 of the following year. The updated network transmission rate includes an adjustment for costs incurred in the prior service year not yet reflected in rates charged to customers, that Pepco accrues as an adjustment to transmission revenue prior to their inclusion in transmission rates. In the first quarter of 2011, Pepco revised its fourth quarter 2010 estimate of the adjustment to be included in the transmission rates to be filed in May 2011 based on updated cost information from 2010, and recorded the change in the estimate as a transmission revenue adjustment. The revised estimate resulted in an immaterial increase in transmission revenues, which

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was recorded in the first quarter of 2011 for transmission service provided during the first ten months of the 2010-2011 service year. In the fourth quarter of 2010, Pepco had estimated and recorded an immaterial decrease in revenues for transmission services provided during the first seven months of the 2010-2011 service year. In the second quarter of 2011, Pepco will revise its first quarter 2011 estimate as needed to reflect the adjustment to be filed for transmission services provided during the entire 2010-2011 service year as part of the transmission service rates submitted to FERC for the 2011-2012 service year.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in Pepco’s gross revenues were $85 million and $63 million for the three months ended March 31, 2011 and 2010, respectively.

Reclassifications and Adjustments

Certain prior period amounts have been reclassified in order to conform to current period presentation. The following adjustments have been recorded which are not considered material individually or in the aggregate:

Income Tax Adjustments

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

(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Fair Value Measurements and Disclosures (Accounting Standards Codification (ASC) 820)

The Financial Accounting Standards Board (FASB) issued new disclosure requirements that require significant items within the reconciliation of the Level 3 valuation category to be presented in separate categories for purchases, sales, issuances and settlements. The guidance is effective beginning with Pepco’s March 31, 2011 financial statements. Pepco has incorporated the new disclosure requirements in Note (9), “Fair Value Disclosures,” of its financial statements.

(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

There are no recently issued accounting standards that have not yet been adopted by Pepco.

(5) SEGMENT INFORMATION

The company operates its business as one regulated utility segment, which includes all of its services as described above.

(6) PENSION AND OTHER POSTRETIREMENT BENEFITS

Pepco accounts for its participation in the Pepco Holdings benefit plans as participation in a multi-employer plan. PHI’s pension and other postretirement net periodic benefit cost for the three months ended March 31, 2011 and 2010, before intercompany allocations from the PHI Service Company, were $27 million and $29 million, respectively. Pepco’s allocated share was $10 million and $7 million, respectively, for the three months ended March 31, 2011 and 2010.

On March 14, 2011, Pepco made a discretionary tax-deductible contribution to PHI’s noncontributory retirement plan of $40 million. Pepco did not make a contribution to the PHI Retirement Plan in 2010.

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(7) DEBT

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 credit facility is $1.5 billion, all or any portion of which may be used to obtain loans or to issue letters of credit. At the PHI level, the 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 collectively, at any given time, may not exceed $625 million.

At March 31, 2011 and December 31, 2010, the aggregate amount of cash, plus borrowing capacity under the $1.5 billion credit facility available to meet the future liquidity needs of PHI’s utility subsidiaries was $455 million and $462 million, respectively.

(8) INCOME TAXES

A reconciliation of Pepco’s effective income tax rate is as follows:

	Three Months Ended March 31,
	2011					2010
	(millions of dollars)
Income tax at federal statutory rate	$	9		35.0	%	$	5		35.0	%
Increases (decreases) resulting from:
Depreciation		—		—			1		8.6
Change in estimates and interest related to uncertain and effectively settled tax positions		—		—			1		7.1
State income taxes, net of federal effect		1		4.4			1		5.7
Permanent differences related to deferred compensation funding		(1	)	(4.4	)		—		—
Asset removal costs		(1	)	(4.0	)		(1	)	(3.5	)
Other, net		(1	)	(3.0	)		(1	)	(10.0	)
Income tax expense	$	7		28.0	%	$	6		42.9	%

Pepco’s effective tax rates for the three months ended March 31, 2011 and 2010 were 28.0% and 42.9%, respectively. The decrease in the effective tax rate primarily resulted from changes in estimates and interest relating to uncertain and effectively settled tax positions, permanent differences related to deferred compensation funding and depreciation.

In March of 2011, Pepco accrued $3 million related to estimated proceeds from life insurance policies on a former executive. This income is not taxable and is included in the permanent differences related to deferred compensation funding.

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(9) 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) that established a framework for measuring fair value and expanded disclosures about fair value measurements. As defined in the guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Pepco utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. Accordingly, Pepco utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1) and the lowest priority to unobservable inputs (level 3). Pepco classifies its fair value balances in the fair value hierarchy based on the observability of the inputs used in the fair value calculation as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 – Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using broker quotes in liquid markets and other observable data. Level 2 also includes those financial instruments that are valued using internally developed methodologies that have been corroborated by observable market data through correlation or by other means. Significant assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

Executive deferred compensation plan assets consist of life insurance policies that are categorized as level 2 assets because they are priced based on the assets underlying the policies, which consist of short-term cash equivalents and fixed income securities that are priced using observable market data. 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, net of loans against those policies, which does not represent a quoted price in an active market.

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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 March 31, 2011 and December 31, 2010. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Pepco’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Fair Value Measurements at March 31, 2011
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)(a)		Significant Other Observable Inputs (Level 2)(a)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Executive deferred compensation plan assets
Money Market Funds	$	7	$	7	$	—	$	—
Life Insurance Contracts		56		—		40		16
	$	63	$	7	$	40	$	16
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, 2010
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)(a)		Significant Other Observable Inputs (Level 2)(a)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Executive deferred compensation plan assets
Money Market Funds	$	6	$	6	$	—	$	—
Life Insurance Contracts		59		—		41		18
	$	65	$	6	$	41	$	18
LIABILITIES
Executive deferred compensation plan liabilities
Life Insurance Contracts	$	11	$	—	$	11	$	—
	$	11	$	—	$	11	$	—

(a) There were no significant transfers of instruments between level 1 and level 2 valuation categories.

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Reconciliations of the beginning and ending balances of Pepco’s fair value measurements using significant unobservable inputs (level 3) for the three months ended March 31, 2011 and 2010 are shown below:

	Life Insurance Contracts
	Three Months Ended March 31,
	2011			2010
	(millions of dollars)
Beginning balance as of January 1	$	18		$	18
Total gains or (losses) (realized and unrealized)
Included in income		3			1
Included in accumulated other comprehensive loss		—			—
Purchases		—			—
Issuances		(1	)		(1	)
Settlements		(4	)		—
Transfers in (out) of level 3		—			—
Ending balance as of March 31	$	16		$	18

The breakdown of realized and unrealized gains on level 3 instruments included in income as a component of “Other” income or “Other operation and maintenance” expense for the periods below were as follows:

	Three Months Ended March  31,
	2011		2010
	(millions of dollars)
Total gains included in income for the period	$	3	$	1
Change in unrealized gains relating to assets still held at reporting date	$	1	$	1

Fair Value of Debt and Equity Instruments

The estimated fair values of Pepco’s issued debt and equity instruments at March 31, 2011 and December 31, 2010 are shown below:

	March 31, 2011				December 31, 2010
	(millions of dollars)
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	1,540	$	1,730	$	1,540	$	1,722

The fair value of long-term debt issued by Pepco was based on actual trade prices as of March 31, 2011 and December 31, 2010.

The carrying amounts of all other financial instruments in the accompanying financial statements approximate fair value.

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(10) COMMITMENTS AND CONTINGENCIES

Regulatory and Other Matters

District of Columbia Divestiture Case

In June 2000, the District of Columbia Public Service Commission (DCPSC) approved a divestiture settlement under which Pepco is required to share with its District of Columbia customers the net proceeds realized by Pepco from the sale of its generation-related assets in 2000. This approval left unresolved issues of (i) whether Pepco should be required to share with customers the excess deferred income taxes (EDIT) and accumulated deferred investment tax credits (ADITC) associated with the sold assets and, if so, whether such sharing would violate the normalization provisions of the Internal Revenue Code and its implementing regulations and (ii) whether Pepco was entitled to deduct certain costs in determining the amount of proceeds to be shared.

In May 2010, the DCPSC issued an order addressing all of the remaining issues related to the sharing of the proceeds of Pepco’s divestiture of its generating assets. In the order, the DCPSC ruled that Pepco is not required to share EDIT and ADITC with customers. However, the order also disallowed certain items that Pepco had included in the costs deducted from the proceeds of the sale of the generation assets. The disallowance of these costs, together with interest on the disallowed amount, increased the aggregate amount Pepco was required to distribute to customers, pursuant to the sharing formula, by approximately $11 million, which PHI recognized as an expense in 2010 and refunded the amounts to its customers. In June 2010, Pepco filed an application for reconsideration of the DCPSC’s order, 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). In July 2010, the DCPSC denied Pepco’s application for reconsideration. In September 2010, Pepco filed an appeal of the DCPSC’s decision with the District of Columbia Court of Appeals. On April 12, 2011, the Court of Appeals affirmed the DCPSC order. Pepco does not intend to appeal this decision.

Maryland Public Service Commission Reliability Investigation

In August 2010, following the major storm events that occurred in July and August 2010, the Maryland Public Service Commission (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. On March 2, 2011, an independent consultant retained by the MPSC to review and make recommendations regarding the reliability of Pepco’s distribution system and the quality of its service filed its report with the MPSC. Pepco is preparing its testimony, which will address the report and will be filed in advance of the hearings 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.

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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 bill stabilization adjustment (BSA) has been approved and implemented for electric service in Maryland and 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). 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 Pepco to promote energy efficiency programs for its customers, because it breaks the link between overall sales volumes and distribution revenues.

On February 1, 2011, the MPSC initiated proceedings for Pepco and its affiliate DPL, as well as unaffiliated utilities including 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. The MPSC has scheduled a legislative-style hearing on this matter in July 2011. An adjustment to remove revenues lost as a result of major storm outages is already included in the BSA for Pepco in the District of Columbia as approved by the DCPSC. The materiality of any such BSA modifications that may be made by the MPSC would depend on the duration and extent of any major storm outages.

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. In August 2010, the MPSC issued an order approving a rate increase of approximately $7.8 million, based on an ROE of 9.83%, which Pepco placed into effect on August 19, 2010. In September 2010, Pepco filed with the MPSC a motion for reconsideration of the following issues, which, if approved, in the aggregate would increase annual revenue by approximately $8.5 million: (i) denial of inclusion in rate base of certain reliability plant investments, which occurred subsequent to the test period but before the rate effective period; (ii) denial of Pepco’s request to increase depreciation rates to reflect a corrected formula relating to the cost of removal expenses; and (iii) 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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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 March 31, 2011, 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 Corporation (Mirant) for defense and indemnification in connection with the sale by Pepco of its generation assets to Mirant in 2000.

While the aggregate amount of monetary damages sought in the remaining suits (excluding those tendered to Mirant) is approximately $360 million, Pepco believes 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, Pepco does not believe these suits will have a material adverse effect on its financial conditions, 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 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

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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. The amount of the remediation costs that may be imposed cannot be predicted at this time; however, based on current information, Pepco does not believe these suits will have a material adverse effect on its financial condition, results of operations or cash flows.

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 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 and therefore, costs incurred to resolve this matter are not expected to be material.

Benning Road Site. In September 2010, PHI received a letter from EPA stating that EPA and the District of Columbia Department of the Environment (DDOE) have identified the Benning Road location, consisting of a transmission and distribution facility operated by Pepco and a generation facility operated by Pepco Energy Services, as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. The letter stated that the principal contaminants of concern are polychlorinated biphenyls (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, to clean up the facility) is not reached. In an October 2010 letter, 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 stated that EPA will list the Benning Road site on the NPL if contamination at the facility is not addressed in a timely manner. In January 2011, in response to these EPA and District of Columbia letters, Pepco and Pepco Energy Services entered into a consent decree with DDOE that requires 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. In February 2011, the consent decree was filed with the United States District Court, but will not become final until the DDOE files a motion requesting the District Court to enter the consent decree. In light of the consent decree, Pepco and Pepco Energy Services anticipate that EPA will recognize that Pepco and Pepco Energy Services are making constructive movement toward cleanup and will refrain from listing the Benning Road facility on the NPL. Pepco preliminarily estimates that costs for performing the RI/FS will be approximately $600,000 and the remediation costs will be approximately $13 million. As of March 31, 2011, PHI had an accrued liability of approximately $14 million with respect to this matter.

Potomac River Mineral Oil Release

On January 23, 2011, a coupling failure on a transformer cooler pipe resulted in a release of non-toxic mineral oil at Pepco’s Potomac River substation in Alexandria, Virginia. An overflow of an underground secondary containment reservoir resulted in approximately 4,500 gallons of mineral oil flowing into the Potomac River.

On March 22, 2011 and March 31, 2011, DDOE issued compliance directives that require Pepco to prepare an incident report, provide certain records, amend Pepco’s surface water and river sediments sampling plan and prepare ecological risk assessment and natural resources damage assessment work plans. Pepco is complying with DDOE’s compliance directives. On March 16, 2011, the Virginia Department of Environmental Quality (VADEQ) requested documentation regarding the release and the preparation of an

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emergency response report, which Pepco submitted to the agency on April 20, 2011. On March 25, 2011, Pepco received a notice of violation from VADEQ, which advised Pepco of information on which VADEQ may rely to institute an administrative or judicial enforcement action in connection with the mineral oil release and indicated that Pepco may be asked to enter into a consent order to formalize a corrective action plan and schedule. The amount of penalties, if any, that may be imposed by either or both of these agencies cannot be predicted at this time; however, based on current information, Pepco does not believe this matter will have a material adverse effect on its financial conditions, results of operations or cash flows.

District of Columbia Tax Legislation

In December 2009, the Mayor of the District of Columbia approved legislation adopted by the District Council that imposes mandatory unitary combined reporting (MUCR) beginning with tax year 2011 for companies doing business in the District of Columbia. The Council must still enact further legislation providing guidance on how to implement MUCR before this legislation is effective. The required implementing legislation has been included in the Mayor’s budget proposal (the Budget Bill) for the fiscal year ending September 30, 2012, which was submitted to the Council on April 1, 2011.

Based upon Pepco’s interpretation of the language in the Budget Bill, the legislation would, if enacted, result in a change in Pepco’s overall state income tax rate and could require a material adjustment to Pepco’s net deferred income tax liabilities. Further, to the extent that the change in rate increases net deferred income tax liabilities, Pepco must determine if these increased tax liabilities are probable of recovery in future rates. Public hearings will be held on the Budget Bill in May 2011, with a vote to be taken by the Council on June 7, 2011. If the Council approves the Budget Bill, including the MUCR implementation guidance, the legislation is subject to a 30-day Congressional review period and, if Congress does not intervene during this review period, the legislation will become binding law. The effect of the legislation has not been accounted for as of March 31, 2011, because the legislative process was not complete.

Management continues to analyze the impact that the tax reporting aspects of this legislation, if completed, may have on the financial position, results of operations and cash flows of Pepco.

(11) 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 three months ended March 31, 2011 and 2010 were approximately $43 million and $45 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 three months ended March 31, 2011 and 2010 were approximately $4 million and $1 million, respectively.

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As of March 31, 2011 and December 31, 2010, Pepco had the following balances on its Balance Sheets due to related parties:

Asset (Liability)	March 31, 2011			December 31, 2010
	(millions of dollars)
Payable to Related Party (current) (a)
PHI Service Company	$	(18	)	$	(27	)
Pepco Energy Services (b)		(47	)		(48	)
Total	$	(65	)	$	(75	)
Money Pool Balance with Pepco Holdings (included in Cash and cash equivalents)	$	108		$	82

(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.

(12) RESTRUCTURING CHARGE

With the ongoing wind down of the retail energy supply business of Pepco Energy Services and the disposition of Conectiv Energy, PHI repositioned itself as a regulated transmission and distribution company during 2010. In connection with this repositioning, PHI completed a comprehensive organizational review in 2010 that identified opportunities to streamline the organization and to achieve certain reductions in corporate overhead costs that are allocated to its operating segments, which resulted in the adoption of a restructuring plan. PHI began implementation of the plan during 2010, identifying 164 employee positions that were eliminated. The plan also includes additional cost reduction opportunities that are being implemented through process improvements and operational efficiencies.

In connection with the restructuring plan, Pepco recorded a pre-tax restructuring charge of $15 million in 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 was reflected as a separate line item in the Statements of Income at December 31, 2010.

A reconciliation of Pepco’s accrued restructuring charges for the three months ended March 31, 2011 is as follows:

	Three Months Ended March 31, 2011
	(millions of dollars)
Beginning balance as of January 1, 2011	$	15
Restructuring charge		—
Cash payments		(11	)
Ending balance as of March 31, 2011	$	4

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DELMARVA POWER & LIGHT COMPANY

STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended March  31,
	2011			2010
	(millions of dollars)
Operating Revenue
Electric	$	298		$	299
Natural Gas		102			95
Total Operating Revenue		400			394
Operating Expenses
Purchased energy		182			201
Gas purchased		71			66
Other operation and maintenance		65			61
Depreciation and amortization		22			20
Other taxes		11			10
Total Operating Expenses		351			358
Operating Income		49			36
Other Income (Expenses)
Interest expense		(11	)		(10	)
Other income		2			1
Total Other Expenses		(9	)		(9	)
Income Before Income Tax Expense		40			27
Income Tax Expense		17			13
Net Income		23			14
Retained Earnings at Beginning of Period		494			472
Retained Earnings at End of Period	$	517		$	486

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

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DELMARVA POWER & LIGHT COMPANY

BALANCE SHEETS

(Unaudited)

	March 31, 2011			December 31, 2010
	(millions of dollars)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	63		$	69
Accounts receivable, less allowance for uncollectible accounts of $13 million and $13 million, respectively		204			212
Inventories		31			41
Prepayments of income taxes		61			62
Prepaid expenses and other		18			22
Total Current Assets		377			406
INVESTMENTS AND OTHER ASSETS
Goodwill		8			8
Regulatory assets		213			242
Prepaid pension expense		174			139
Other		24			21
Total Investments and Other Assets		419			410
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		3,027			3,000
Accumulated depreciation		(902	)		(901	)
Net Property, Plant and Equipment		2,125			2,099
TOTAL ASSETS	$	2,921		$	2,915

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

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DELMARVA POWER & LIGHT COMPANY

BALANCE SHEETS

(Unaudited)

	March 31, 2011		December 31, 2010
	(millions of dollars, except shares)
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Short-term debt	$	105	$	105
Current portion of long-term debt		35		35
Accounts payable and accrued liabilities		79		98
Accounts payable due to associated companies		17		34
Taxes accrued		7		6
Interest accrued		13		7
Derivative liabilities		13		15
Other		67		73
Total Current Liabilities		336		373
DEFERRED CREDITS
Regulatory liabilities		313		310
Deferred income taxes, net		581		561
Investment tax credits		7		7
Other postretirement benefit obligations		24		22
Liabilities and accrued interest related to uncertain tax positions		24		24
Derivative liabilities		6		8
Other		36		39
Total Deferred Credits		991		971
LONG-TERM LIABILITIES
Long-term debt		730		730
COMMITMENTS AND CONTINGENCIES (NOTE 12)
EQUITY
Common stock, $2.25 par value, 1,000 shares authorized, 1,000 shares outstanding		—		—
Premium on stock and other capital contributions		347		347
Retained earnings		517		494
Total Equity		864		841
TOTAL LIABILITIES AND EQUITY	$	2,921	$	2,915

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

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STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
	2011			2010
	(millions of dollars)
OPERATING ACTIVITIES
Net income	$	23		$	14
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		22			20
Deferred income taxes		18			—
Changes in:
Accounts receivable		6			2
Inventories		9			5
Regulatory assets and liabilities, net		18			13
Accounts payable and accrued liabilities		(34	)		(25	)
Pension contribution		(40	)		—
Taxes accrued		(4	)		12
Interest accrued		6			7
Other assets and liabilities		10			5
Net Cash From Operating Activities		34			53
INVESTING ACTIVITIES
Investment in property, plant and equipment		(41	)		(48	)
Net other investing activities		1			(1	)
Net Cash Used By Investing Activities		(40	)		(49	)
FINANCING ACTIVITIES
Net other financing activities		—			(6	)
Net Cash Used By Financing Activities		—			(6	)
Net Decrease in Cash and Cash Equivalents		(6	)		(2	)
Cash and Cash Equivalents at Beginning of Period		69			26
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	63		$	24
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid (received) for income taxes (includes payments to (from) PHI for Federal income taxes)	$	4		$	(1	)

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 energy 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).

(2) SIGNIFICANT ACCOUNTING POLICIES

Financial Statement Presentation

DPL’s unaudited financial statements are prepared in conformity with accounting principles generally accepted in the United States of America (GAAP). Pursuant to the rules and regulations of the Securities and Exchange Commission, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been omitted. Therefore, these financial statements should be read along with the annual financial statements included in DPL’s Annual Report on Form 10-K for the year ended December 31, 2010. In the opinion of DPL’s management, the financial statements contain all adjustments (which all are of a normal recurring nature) necessary to present fairly DPL’s financial condition as of March 31, 2011, in accordance with GAAP. The year-end December 31, 2010 Balance Sheet was derived from audited financial statements, but does not include all disclosures required by GAAP. Interim results for the three months ended March 31, 2011 may not be indicative of results that will be realized for the full year ending December 31, 2011 since the sales of electric energy and natural gas are seasonal.

Use of Estimates

The preparation of financial statements in conformity with 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 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 it is probable that a loss has been incurred and the loss is reasonably estimable.

Network Service Transmission Rates

In May of every year, DPL provides its updated network service transmission rate to the Federal Energy Regulatory Commission (FERC) to be effective for June 1 of that year through May 31 of the following year. The updated network transmission rate includes an adjustment for costs incurred in the prior service year not yet reflected in rates charged to customers, that DPL accrues as an adjustment to transmission revenue prior to their inclusion in transmission rates. In the first quarter of 2011, DPL revised its fourth

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quarter 2010 estimate of the adjustment to be included in the transmission rates to be filed in May 2011 based on updated cost information from 2010, and recorded the change in the estimate as a transmission revenue adjustment. The revised estimate resulted in a $3 million increase in transmission revenues, which was recorded in the first quarter of 2011 for transmission service provided during the first ten months of the 2010-2011 service year. In the fourth quarter of 2010, DPL had estimated and recorded a $1 million decrease in revenues for transmission services provided during the first seven months of the 2010-2011 service year. In the second quarter of 2011, DPL will revise its first quarter 2011 estimate as needed to reflect the adjustment to be filed for transmission services provided during the entire 2010-2011 service year as part of the transmission service rates submitted to FERC for the 2011-2012 service year.

Consolidation of Variable Interest Entities – DPL Renewable Energy Transactions

DPL has entered into four wind power purchase agreements (PPAs) in the aggregate amount of 350 megawatts as of March 31, 2011 that includes the purchase of renewable energy credits (RECs) and one solar REC purchase agreement with a 10 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 are with land-based facilities and one is with an offshore facility. One of the land-based wind 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. The other wind agreements, which have terms ranging from 20 to 25 years, are currently expected to become operational during 2011 for the two land-based contracts and 2016 for the offshore contract, if the projects are ultimately completed. DPL’s purchases under the wind PPA’s totaled $5 million and $3 million for the three months ended March 31, 2011 and 2010, respectively. On April 6, 2011, DPL agreed to amend one of the land-based wind contracts to change the location of the wind facility and reduce the maximum generation capacity from 60 megawatts to 38 megawatts. The amendment requires DPSC approval. Upon DPSC approval, the amendment would reduce the aggregate amount of generation capacity associated with the four wind PPAs from 350 megawatts to 328 megawatts.

When the wind facilities 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 delays 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 70 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 Financial Accounting Standards Board (FASB) guidance on the consolidation of variable interest entities (Accounting Standards Codification (ASC) 810).

Goodwill

Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired at the acquisition date. All of DPL’s goodwill was generated by DPL’s acquisition of Conowingo Power Company in 1995. DPL tests its goodwill for impairment annually and whenever an event occurs or circumstances change in the interim that would more likely than not reduce the fair value of DPL below its carrying amount. DPL performs its annual impairment test on November 1. Factors that may result in an interim impairment test include, but are not limited to: a change in the identified reporting units; an adverse

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change in business conditions; an adverse regulatory action; or an impairment of DPL’s long-lived assets. As described in Note (6), “Goodwill,” DPL concluded that an interim impairment test was not required during the three months ended March 31, 2011.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in DPL’s gross revenues were $5 million for each of the three months ended March 31, 2011 and 2010.

(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Fair Value Measurements and Disclosures (ASC 820)

The FASB issued new disclosure requirements that require significant items within the reconciliation of the Level 3 valuation category to be presented in separate categories for purchases, sales, issuances and settlements. The guidance is effective beginning with DPL’s March 31, 2011 financial statements. DPL has incorporated the new disclosure requirements in Note (11), “Fair Value Disclosures,” of its financial statements.

Goodwill (ASC 350)

The FASB issued new guidance on performing goodwill impairment tests that was effective beginning January 1, 2011 for DPL. Under the new guidance, the carrying value of the reporting unit must include the liabilities that are part of the capital structure of the reporting unit. DPL already allocates liabilities to the reporting unit when performing its goodwill impairment test, so the new guidance will not change DPL’s goodwill impairment test methodology.

(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

There are no recently issued accounting standards that have not yet been adopted by DPL.

(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 three month period ending March 31, 2011. All of DPL’s goodwill was generated by its acquisition of Conowingo Power Company in 1995.

DPL’s annual impairment test as of November 1, 2010 indicated that goodwill was not impaired. As of March 31, 2011, DPL concluded that there were no events requiring it to perform an interim goodwill impairment test. DPL will continue to monitor for indicators of goodwill impairment.

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(7) PENSION AND OTHER POSTRETIREMENT BENEFITS

DPL accounts for its participation in the Pepco Holdings benefit plans as participation in a multi-employer plan. PHI’s pension and other postretirement net periodic benefit cost for the three months ended March 31, 2011 and 2010, before intercompany allocations from the PHI Service Company, were $27 million and $29 million, respectively. DPL’s allocated share was $7 million and $4 million, respectively, for the three months ended March 31, 2011 and 2010.

On March 14, 2011, DPL made a discretionary tax-deductible contribution to PHI’s noncontributory retirement plan of $40 million. DPL did not make contribution to the PHI Retirement Plan in 2010.

(8) DEBT

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 credit facility is $1.5 billion, all or any portion of which may be used to obtain loans or to issue letters of credit. At the PHI level, the 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 collectively, at any given time, collectively may not exceed $625 million.

At March 31, 2011 and December 31, 2010, the aggregate amount of cash, plus borrowing capacity under the $1.5 billion credit facility available to meet the future liquidity needs of PHI’s utility subsidiaries was $455 million and $462 million, respectively.

Financing Activities Subsequent to March 31, 2011

On May 2, 2011, DPL repurchased, pursuant to a mandatory repurchase obligation, $35 million of 4.9% Delaware Economic Development Authority tax- exempt put bonds due May 1, 2026. DPL plans to remarket these bonds during the second quarter of 2011.

(9) INCOME TAXES

A reconciliation of DPL’s effective income tax rate is as follows:

	Three Months Ended March 31,
	2011				2010
	(millions of dollars)
Income tax at federal statutory rate	$	14	35.0	%	$	9	35.0	%
Increases resulting from:
State income taxes, net of federal effect		2	6.0			1	5.2
Change in estimates and interest related to uncertain and effectively settled tax positions		1	1.5			2	7.4
Other, net		—	—			1	0.6
Income tax expense	$	17	42.5	%	$	13	48.2	%

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DPL’s effective tax rates for the three months ended March 31, 2011 and 2010 were 42.5% and 48.2%, respectively. The decrease in the rate primarily resulted from a decrease in changes in estimates and interest related to uncertain and effectively settled tax positions, primarily related to a 2010 reversal of $2 million of accrued interest income on state income tax positions that DPL no longer believes is more likely than not to be realized.

(10) DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

DPL uses derivative instruments in the form of swaps and over-the-counter options primarily to reduce gas commodity price volatility and to 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 from its customers through a fuel adjustment clause approved by the DPSC.

The tables below identify the balance sheet location and fair values of derivative instruments as of March 31, 2011 and December 31, 2010:

	As of March 31, 2011
Balance Sheet Caption	Derivatives Designated as Hedging Instruments			Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting		Net Derivative Instruments
	(millions of dollars)
Derivative Assets (current assets)	$	—		$	—		$	—		$	—	$	—
Derivative Assets (non-current assets)		—			—			—			—		—
Total Derivative Assets		—			—			—			—		—
Derivative Liabilities (current liabilities)		(4	)		(13	)		(17	)		4		(13	)
Derivative Liabilities (non-current liabilities)		—			(6	)		(6	)		—		(6	)
Total Derivative Liabilities		(4	)		(19	)		(23	)		4		(19	)
Net Derivative (Liability) Asset	$	(4	)	$	(19	)	$	(23	)	$	4	$	(19	)

	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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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:

	March 31, 2011		December 31, 2010
	(millions of dollars)
Cash collateral pledged to counterparties with the right to reclaim	$	4	$	6

As of March 31, 2011 and December 31, 2010, all DPL cash collateral pledged related to derivative instruments accounted for at fair value was entitled to be offset under master netting agreements.

Derivatives Designated as Hedging Instruments

Cash Flow Hedges

All premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all of DPL’s gains and losses related to hedging activities, are deferred under FASB guidance on regulated operations until recovered from customers through a fuel adjustment clause approved by the DPSC. The following table indicates the amounts of the net unrealized derivative gain (loss) deferred as a regulatory liability (regulatory asset) and the realized loss recognized in the Statements of Income for the three months ended March 31, 2011 and 2010:

	Three Months Ended March  31,
	2011			2010
	(millions of dollars)
Net Unrealized Gain (Loss) Deferred as a Regulatory Liability (Asset)	$	1		$	(5	)
Net Realized Loss Recognized in Purchased Energy or Gas Purchased		(2	)		(2	)

As of March 31, 2011 and December 31, 2010, DPL had the following outstanding commodity forward contracts that were entered into to hedge forecasted transactions:

	Quantities
Commodity	March 31, 2011		December 31, 2010
Forecasted Purchases Hedges
Natural Gas (One Million British Thermal Units (MMBtu))		1,225,000		1,670,000

Other Derivative Activity

DPL holds certain derivatives that are not in hedge accounting relationships nor are they designated as normal purchases or normal sales. These derivatives are recorded at fair value on the Balance Sheets with changes in the fair value recorded in income. In accordance with FASB guidance on regulatory operations, offsetting regulatory liabilities or regulatory assets are recorded on the Balance Sheets and the recognition of the gain or loss is deferred because of the DPSC-approved fuel adjustment clause. For the three months ended March 31, 2011 and 2010, the net amount of the unrealized derivative gain (loss) deferred as a regulatory liability (regulatory asset) and the net realized loss recognized in the Statements of Income is provided in the table below:

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	Three Months Ended March  31,
	2011			2010
	(millions of dollars)
Net Unrealized Gain (Loss) Deferred as a Regulatory Liability (Asset)	$	7		$	(6	)
Net Realized Loss Recognized in Purchased Energy or Gas Purchased		(7	)		(7	)

As of March 31, 2011 and December 31, 2010, DPL had the following net outstanding natural gas commodity forward contracts that did not qualify for hedge accounting:

	March 31, 2011				December 31, 2010
Commodity	Quantity		Net Position		Quantity		Net Position
Natural Gas (MMBtu)		6,748,882		Long		7,827,635		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.

Under the ISDA or similar agreements, the parties establish a dollar threshold of unsecured credit for each party in excess of which the party would be required to post collateral to secure its obligations to the other party. The amount of the unsecured credit threshold varies according to the senior, unsecured debt rating of the respective parties or that of a guarantor of the party’s obligations. The fair values of all transactions between the parties are netted under the master netting provisions. Transactions may include derivatives accounted for on-balance sheet as well as those designated as normal purchases and normal sales that are accounted for off-balance sheet. If the aggregate fair value of the transactions in a net loss position exceeds the unsecured credit threshold, then collateral is required to be posted in an amount equal to the amount by which the unsecured credit threshold is exceeded. The obligations of 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 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 March 31, 2011 and December 31, 2010, was $19 million and $23 million, respectively, before giving effect to the impact of a credit rating downgrade that would increase this amount or offsetting transactions that are encompassed within master netting agreements that would alter these amounts. As of those dates, DPL had not posted any cash collateral against the gross derivative liability. DPL’s net settlement amount in the event of a downgrade of DPL’s senior unsecured debt rating to below “investment grade” as of March 31, 2011 and December 31, 2010, would have been approximately $37 million and $31 million, respectively, after taking into account the master netting agreements.

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DPL’s primary source for posting cash collateral or letters of credit are PHI’s credit facilities. At March 31, 2011 and December 31, 2010, the aggregate amount of cash plus borrowing capacity under the PHI credit facilities available to meet the liquidity needs of PHI’s utility subsidiaries was $455 million and $462 million, respectively.

(11) 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) that established a framework for measuring fair value and expanded disclosures about fair value measurements. As defined in the guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). DPL utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. Accordingly, DPL utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1) and the lowest priority to unobservable inputs (level 3). DPL classifies its fair value balances in the fair value hierarchy based on the observability of the inputs used in the fair value calculation as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis, such as the New York Mercantile Exchange (NYMEX).

Level 2 – Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using broker quotes in liquid markets and other observable data. Level 2 also includes those financial instruments that are valued using internally developed methodologies that have been corroborated by observable market data through correlation or by other means. Significant assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

Level 3 – Pricing inputs include significant inputs that are generally less observable than those from objective sources. Level 3 includes those financial instruments that are valued using models or other valuation methodologies.

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, net of loans against those policies, which does not represent a quoted price in an active market.

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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 March 31, 2011 and December 31, 2010. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. DPL’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Fair Value Measurements at March 31, 2011
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)(a)		Significant Other Observable Inputs (Level 2)(a)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Executive deferred compensation plan assets
Money Market Funds	$	2	$	2	$	—	$	—
Life Insurance Contracts		1		—		—		1
	$	3	$	2	$	—	$	1
LIABILITIES
Derivative instruments (b)
Natural Gas	$	23	$	4	$	—	$	19
	$	23	$	4	$	—	$	19

(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.

	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	$	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.

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Reconciliations of the beginning and ending balances of DPL’s fair value measurements using significant unobservable inputs (level 3) for the three months ended March 31, 2011 and 2010 are shown below:

	Three Months Ended March 31, 2011
	Natural Gas			Life Insurance Contracts
	(millions of dollars)
Beginning balance as of January 1	$	(23	)	$	1
Total gains or (losses) (realized and unrealized):
Included in income		—			—
Included in accumulated other comprehensive loss		—			—
Included in regulatory liabilities		(1	)		—
Purchases		—			—
Issuances		—			—
Settlements		5			—
Transfers in (out) of level 3		—			—
Ending balance as of March 31	$	(19	)	$	1

	Three Months Ended March 31, 2010
	Natural Gas			Life Insurance Contracts
	(millions of dollars)
Beginning balance as of January 1	$	(29	)	$	1
Total gains or (losses) (realized and unrealized):
Included in income		—			—
Included in accumulated other comprehensive loss		—			—
Included in regulatory liabilities		(12	)		—
Purchases		—			—
Issuances		—			—
Settlements		4			—
Transfers in (out) of level 3		—			—
Ending balance as of March 31	$	(37	)	$	1

Fair Value of Debt and Equity Instruments

The estimated fair values of DPL’s issued debt and equity instruments as of March 31, 2011 and December 31, 2010 are shown below:

	March 31, 2011				December 31, 2010
	(millions of dollars)
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	765	$	821	$	765	$	822

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The fair value of long-term debt issued by DPL was based on actual trade prices as of March 31, 2011 and December 31, 2010. Where trade prices were not available, DPL obtained and validated bid prices from brokers or used a discounted cash flow model to estimate fair value.

The carrying amounts of all other financial instruments in the accompanying financial statements approximate fair value.

(12) 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 bill stabilization adjustment (BSA) has been approved and implemented for electric service in Maryland. The Maryland Public Service Commission (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 the implementation has been deferred by the DPSC pending the development of an implementation plan and a customer education plan. DPL anticipates that the MFVRD will be in place for electric service by early in 2012.

• A MFVRD has been approved in concept for DPL natural gas service in Delaware, but a proposed settlement in the pending base rate proceeding would defer the request for implementation until an implementation plan and a customer education plan are developed.

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 DPL to promote energy efficiency programs for its 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.

On February 1, 2011, the MPSC initiated proceedings for DPL and its affiliate Pepco, as well as unaffiliated utilities including 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. The MPSC has scheduled a legislative-style hearing on this matter

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in July 2011. An adjustment to remove revenues lost as a result of major storm outages is already included in the BSA for Pepco in the District of Columbia as approved by the District of Columbia Public Service Commission. The materiality of any such BSA modifications that may be made by the MPSC will depend on the duration and extent of any major storm outages.

Delaware

DPL makes an annual Gas Cost Rate (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 allowing DPL to place the new rates into effect on November 1, 2010, subject to refund and pending final DPSC approval. The effect of the proposed two-year amortization upon rates is an increase of 0.1% in the level of GCR. If the DPSC does not accept DPL’s proposal for a two-year amortization, the adjustment would result in an increase of 6.9% in the GCR.

In July 2010, DPL submitted an application with the DPSC to increase its natural gas distribution base rates. As subsequently amended in September 2010 (to replace test year data for the twelve months ended June 2010 with the actual data) and in October 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 return on equity (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 was placed into effect on February 2, 2011, in each case subject to refund and pending final DPSC approval. On February 9, 2011, DPL, DPSC staff, and the Attorney General of Delaware entered into a proposed settlement agreement, which provides for an annual rate increase of approximately $5.8 million, based on an ROE of 10%. In the settlement agreement, the parties agreed to defer the implementation of the MFVRD until an implementation plan and a customer education plan are developed. The proposed settlement agreement is subject to final review and approval by the DPSC. A decision is expected by the end of July 2011. The excess amount collected will be refunded to customers through a bill credit after final DPSC approval of a refund plan.

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.

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, environmental clean-up costs incurred by DPL would be included in its cost of service for ratemaking purposes.

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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 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 and therefore, costs incurred to resolve this matter are not expected to be material.

Indian River Oil Release

In 2001, DPL entered into a consent agreement with the Delaware Department of Natural Resources and Environmental Control for remediation, site restoration, natural resource damage compensatory projects and other costs associated with environmental contamination resulting from an oil release at the Indian River generating facility, which was sold in June 2001. As of March 31, 2011, 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 during the remainder of 2011.

(13) 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 three months ended March 31, 2011 and 2010 were approximately $31 million and $34 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:

Income (Expenses)	For the Three  Months Ended March 31,
	2011		2010
	(millions of dollars)
Purchased power under Default Electricity Supply contracts with Conectiv Energy Supply, Inc. (a)(c)	$	1	$	(19	)
Intercompany lease transactions (b)		1		2

(a) Included in purchased energy expense.

(b) Included in electric revenue.

(c) During 2010, PHI sold Conectiv Energy’s wholesale power generation business.

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As of March 31, 2011 and December 31, 2010, DPL had the following balances on its balance sheets due (to) from related parties:

(Liability) Asset	March 31, 2011			December 31, 2010
	(millions of dollars)
(Payable to) Receivable from Related Party (current) (a)
PHI Service Company	$	(16	)	$	(19	)
Conectiv Energy Supply, Inc.		—			(13	)
Pepco Energy Services, Inc. and its subsidiaries (Pepco Energy Services) (b)		(2	)		(2	)
Other		1			—
Total	$	(17	)	$	(34	)
Money Pool Balance with Pepco Holdings (included in cash and cash equivalents)	$	57		$	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.

(14) RESTRUCTURING CHARGE

With the ongoing wind down of the retail energy supply business of Pepco Energy Services and the disposition of Conectiv Energy, PHI repositioned itself as a regulated transmission and distribution company during 2010. In connection with this repositioning, PHI completed a comprehensive organizational review in 2010 that identified opportunities to streamline the organization and to achieve certain reductions in corporate overhead costs that are allocated to its operating segments, which resulted in the adoption of a restructuring plan. PHI began implementing the plan during 2010, identifying 164 employee positions that were eliminated. The plan also includes additional cost reduction opportunities that are being implemented through process improvements and operational efficiencies.

In connection with the restructuring plan, DPL recorded a pre-tax restructuring charge of $8 million in 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 at December 31, 2010.

A reconciliation of DPL’s accrued restructuring charges for the three months ended March 31, 2011 is as follows:

	Three Months Ended
	March 31, 2011
	(millions of dollars)
Beginning balance as of January 1, 2011	$	7
Restructuring charge		—
Cash payments		(5	)
Ending balance as of March 31, 2011	$	2

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ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME (LOSS)

(Unaudited)

	Three Months Ended March  31,
	2011			2010
	(millions of dollars)
Operating Revenue	$	315		$	317
Operating Expenses
Purchased energy		198			235
Other operation and maintenance		55			50
Depreciation and amortization		33			24
Other taxes		6			6
Deferred electric service costs		(3	)		(19	)
Total Operating Expenses		289			296
Operating Income		26			21
Other Income (Expenses)
Interest expense		(15	)		(16	)
Total Other Expenses		(15	)		(16	)
Income Before Income Tax Expense		11			5
Income Tax Expense		5			7
Net Income (Loss)		6			(2	)
Retained Earnings at Beginning of Period		161			143
Retained Earnings at End of Period	$	167			141

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

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ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31, 2011			December 31, 2010
	(millions of dollars)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	4		$	4
Restricted cash equivalents		13			11
Accounts receivable, less allowance for uncollectible accounts of $11 million and $11 million, respectively		195			212
Inventories		16			17
Prepayments of income taxes		56			55
Income taxes receivable		20			25
Prepaid expenses and other		11			9
Total Current Assets		315			333
INVESTMENTS AND OTHER ASSETS
Regulatory assets		647			667
Prepaid pension expense		78			51
Income taxes receivable		63			59
Restricted cash equivalents		6			5
Assets and accrued interest related to uncertain tax positions		36			38
Other		12			11
Total Investments and Other Assets		842			831
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		2,459			2,443
Accumulated depreciation		(740	)		(729	)
Net Property, Plant and Equipment		1,719			1,714
TOTAL ASSETS	$	2,876		$	2,878

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

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CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31, 2011		December 31, 2010
	(millions of dollars, except shares)
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Short-term debt	$	188	$	181
Current portion of long-term debt		36		35
Accounts payable and accrued liabilities		112		120
Accounts payable due to associated companies		14		29
Taxes accrued		17		7
Interest accrued		17		13
Other		40		41
Total Current Liabilities		424		426
DEFERRED CREDITS
Regulatory liabilities		65		71
Deferred income taxes, net		669		659
Investment tax credits		8		8
Other postretirement benefit obligations		28		27
Other		17		13
Total Deferred Credits		787		778
LONG-TERM LIABILITIES
Long-term debt		633		633
Transition Bonds issued by ACE Funding		323		332
Total Long-Term Liabilities		956		965
COMMITMENTS AND CONTINGENCIES (NOTE 11)
REDEEMABLE SERIAL PREFERRED STOCK		—		6
EQUITY
Common stock, $3.00 par value, 25,000,000 shares authorized, 8,546,017 shares outstanding		26		26
Premium on stock and other capital contributions		516		516
Retained earnings		167		161
Total Equity		709		703
TOTAL LIABILITIES AND EQUITY	$	2,876	$	2,878

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

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CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
	2011			2010
	(millions of dollars)
OPERATING ACTIVITIES
Net income (loss)	$	6		$	(2	)
Adjustments to reconcile net income (loss) to net cash from (used by) operating activities:
Depreciation and amortization		33			24
Deferred income taxes		9			3
Changes in:
Accounts receivable		16			15
Inventories		—			(2	)
Regulatory assets and liabilities, net		(3	)		(22	)
Accounts payable and accrued liabilities		(23	)		(49	)
Pension contribution		(30	)		—
Taxes accrued		12			15
Interest accrued		3			4
Other assets and liabilities		10			4
Net Cash From (Used By) Operating Activities		33			(10	)
INVESTING ACTIVITIES
Investment in property, plant and equipment		(22	)		(38	)
Department of Energy capital reimbursement awards received		1			—
Net other investing activities		(3	)		1
Net Cash Used By Investing Activities		(24	)		(37	)
FINANCING ACTIVITIES
Redemption of preferred stock		(6	)		—
Issuances of long-term debt		—			23
Reacquisitions of long-term debt		(9	)		(8	)
Issuances of short-term debt, net		7			31
Net other financing activities		(1	)		(2	)
Net Cash (Used by) From Financing Activities		(9	)		44
Net Decrease in Cash and Cash Equivalents		—			(3	)
Cash and Cash Equivalents at Beginning of Period		4			7
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	4		$	4
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash received for income taxes (includes payments from PHI for Federal income taxes)	$	6		$	—

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

Financial Statement Presentation

ACE’s unaudited Consolidated Financial Statements are prepared in conformity with accounting principles generally accepted in the United States of America (GAAP). Pursuant to the rules and regulations of the Securities and Exchange Commission, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been omitted. Therefore, these financial statements should be read along with the annual financial statements included in ACE’s Annual Report on Form 10-K for the year ended December 31, 2010. In the opinion of ACE’s management, the Consolidated Financial Statements contain all adjustments (which all are of a normal recurring nature) necessary to present fairly ACE’s financial condition as of March 31, 2011, in accordance with GAAP. The year-end December 31, 2010 Balance Sheet was derived from audited financial statements, but does not include all disclosures required by GAAP. Interim results for the three months ended March 31, 2011 may not be indicative of results that will be realized for the full year ending December 31, 2011 since the sales of electric energy are seasonal.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the Consolidated Financial Statements and accompanying notes. Although 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 it is probable that a loss has been incurred and the loss is reasonably estimable.

Network Service Transmission Rates

In May of every year, ACE provides its updated network service transmission rate to the Federal Energy Regulatory Commission (FERC) to be effective for June 1 of that year through May 31 of the following year. The updated network transmission rate includes an adjustment for costs incurred in the prior service year not yet reflected in rates charged to customers, that ACE accrues as an adjustment to transmission revenue prior to their inclusion in transmission rates. In the first quarter of 2011, ACE revised

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its fourth quarter 2010 estimate of the adjustment to be included in the transmission rates to be filed in May 2011 based on updated cost information from 2010, and recorded the change in the estimate as a transmission revenue adjustment. The revised estimate resulted in a $1 million increase in transmission revenues, which was recorded in the first quarter of 2011 for transmission service provided during the first ten months of the 2010-2011 service year. In the fourth quarter of 2010, ACE had estimated and recorded a $1 million decrease in revenues for transmission services provided during the first seven months of the 2010-2011 service year. In the second quarter of 2011, ACE will revise its first quarter 2011 estimate as needed to reflect the adjustment to be filed for transmission services provided during the entire 2010-2011 service year as part of the transmission service rates submitted to FERC for the 2011-2012 service year.

Consolidation of Variable Interest Entities

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 the three months ended March 31, 2011, ACE continues to be unable to obtain sufficient information to conduct the analysis required under Financial Accounting Standards Board (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 three months ended March 31, 2011 and 2010 were approximately $57 million and $72 million, respectively, of which approximately $53 million and $67 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 bonds (Transition Bonds). The proceeds of the sale of each series of Transition Bonds have been transferred to ACE in exchange for the transfer by ACE to ACE Funding of the right to collect non-bypassable transition bond charges (the Transition Bond Charges) from ACE customers pursuant to bondable stranded costs rate orders issued by the New Jersey Board of Public Utilities (NJBPU) in an amount sufficient to fund the principal and interest payments on the Transition Bonds and related taxes, expenses and fees (Bondable Transition Property). ACE collects the Transition Bond Charges from its customers on behalf of ACE Funding and the holders of the Transition Bonds. The assets of ACE Funding, including the Bondable Transition Property, and the Transition Bond Charges collected from ACE’s customers, are not available to creditors of ACE. The holders of the Transition Bonds have recourse only to the assets of ACE Funding. ACE owns 100 percent of the equity of ACE Funding and consolidates ACE Funding in its financial statements as ACE is the primary beneficiary of ACE Funding under the variable interest entity consolidation guidance.

ACE Standard Offer Capacity Agreements

On April 28, 2011, ACE entered into three Standard Offer Capacity Agreements (SOCAs) by order of the NJBPU. The SOCAs were established as part of the Long-term Capacity Agreement Pilot Program (LCAPP) that was enacted in January 2011 under a New Jersey state law to promote the construction of qualified electric generation facilities in New Jersey. The SOCAs are 15-year, financially settled transactions approved by the NJBPU that would allow generators selected by the NJBPU to receive payments from or make payments to ACE and the other electric distribution companies in New Jersey based on the difference between the fixed price set by the NJBPU in the SOCAs and the market resource clearing price for capacity.

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The NJBPU awarded the SOCAs to three generation companies that would each construct a combined cycle, natural gas facility totaling an aggregate amount of capacity of 1,949 megawatts. ACE’s share of the payments under the SOCAs would be based on its proportion of load in New Jersey, which is approximately 15 percent, or 292 megawatts, of the aggregate capacity under the contracts. Payments would begin when the facilities are operational, which is currently estimated to be 2015 for two of the facilities and 2016 for the third facility. The NJBPU has approved full recovery from distribution customers of payments made by ACE when the SOCA price set by the NJBPU exceeds the market resource clearing price and ACE’s distribution customers would be entitled to any payments received when the market resource clearing price exceeds the SOCA price.

ACE and the other electric distribution companies in New Jersey entered into the SOCAs under protest and also requested that the NJBPU postpone implementation of the LCAPP and delay execution of the SOCAs based on concerns about the potential cost to distribution customers. The NJBPU denied that request and, on March 29, 2011, ordered the electric distribution companies in New Jersey, including ACE, to sign the SOCAs. ACE and the other electric distribution companies filed a joint motion for reconsideration of the order on April 8, 2011, which is pending review by the NJBPU.

ACE is currently assessing the appropriate accounting treatment for the SOCAs, including the applicability of FASB guidance on the consolidation of variable interest entities, leases and derivative instruments. ACE’s accounting review is expected to be completed in the second quarter of 2011.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in ACE’s gross revenues were $6 million for each of the three months ended March 31, 2011 and 2010.

Reclassifications and Adjustments

Certain prior period amounts have been reclassified in order to conform to current period presentation. The following adjustment has been recorded and is not considered material:

Income Tax Adjustments

During the first quarter of 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 quarter ended March 31, 2010. The adjustment represents the reversal of erroneously recorded interest income for state income tax purposes related to uncertain and effectively settled tax positions, including $2 million, $3 million and $1 million recorded in 2009, 2008 and 2007, respectively.

(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Fair Value Measurements and Disclosures (Accounting Standards Codification (ASC) 820)

The FASB issued new disclosure requirements that require significant items within the reconciliation of the Level 3 valuation category to be presented in separate categories for purchases, sales, issuances and settlements. The guidance is effective beginning with ACE’s March 31, 2011 financial statements. ACE has incorporated the new disclosure requirements in Note (10), “Fair Value Disclosures,” of its financial statements.

(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

There are no recently issued accounting standards that have not yet been adopted by ACE.

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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) PENSION AND OTHER POSTRETIREMENT BENEFITS

ACE accounts for its participation in the Pepco Holdings benefit plans as participation in a multi-employer plan. PHI’s pension and other postretirement net periodic benefit cost for the three months ended March 31, 2011 and 2010, before intercompany allocations from the PHI Service Company, were $27 million and $29 million, respectively. ACE’s allocated share was $6 million and $4 million, respectively, for the three months ended March 31, 2011 and 2010.

On March 14, 2011, ACE made a discretionary tax-deductible contribution to PHI’s noncontributory retirement plan of $30 million. ACE did not make a contribution to the PHI Retirement Plan in 2010.

(7) DEBT

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 credit facility is $1.5 billion, all or any portion of which may be used to obtain loans or to issue letters of credit. At the PHI level, the 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 collectively, at any given time, may not exceed $625 million.

At March 31, 2011 and December 31, 2010, the aggregate amount of cash, plus borrowing capacity under the $1.5 billion credit facility available to meet the future liquidity needs of PHI’s utility subsidiaries was $455 million and $462 million, respectively.

Financing Activities

In January 2011, ACE Funding made principal payments of $6 million on Series 2002-1 Bonds, Class A-2, and $2 million on Series 2003-1 Bonds, Class A-2.

Financing Activities Subsequent to March 31, 2011

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

(8) INCOME TAXES

ACE’s consolidated effective tax rates for the three months ended March 31, 2011 and 2010 were 45.5% and 140.0%, respectively. The decrease in the rate resulted from changes in estimates and interest related to uncertain and effectively settled tax positions primarily related to the reversal of $6 million of erroneously accrued interest income on uncertain and effectively settled state income tax positions in 2010 and the impact of certain permanent state tax differences as a percentage of pre-tax book income.

(9) PREFERRED STOCK

On February 25, 2011, ACE redeemed all of its outstanding cumulative preferred stock for approximately $6 million.

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(10) 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) that established a framework for measuring fair value and expanded disclosures about fair value measurements. As defined in the guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). ACE utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. Accordingly, ACE utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1) and the lowest priority to unobservable inputs (level 3). ACE classifies its fair value balances in the fair value hierarchy based on the observability of the inputs used in the fair value calculation as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 – Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using broker quotes in liquid markets and other observable data. Level 2 also includes those financial instruments that are valued using internally developed methodologies that have been corroborated by observable market data through correlation or by other means. Significant assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

The level 2 liability associated with the life insurance policies represents a deferred compensation obligation, the value of which is tracked via underlying insurance sub-accounts. The sub-accounts are designed to mirror existing mutual funds and money market funds that are observable and actively traded.

Level 3 – Pricing inputs include significant inputs that are generally less observable than those from objective sources. Level 3 includes those financial instruments 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 March 31, 2011 and December 31, 2010. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. ACE’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

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	Fair Value Measurements at March 31, 2011
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)(a)		Significant Other Observable Inputs (Level 2)(a)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Cash equivalents
Treasury Fund	$	19	$	19	$	—	$	—
	$	19	$	19	$	—	$	—
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, 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 of Debt and Equity Instruments

The estimated fair values of ACE’s issued debt and equity instruments at March 31, 2011 and December 31, 2010 are shown below:

	March 31, 2011				December 31, 2010
	(millions of dollars)
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	633	$	708	$	633	$	710
Transition Bonds issued by ACE Funding		359		394		367		406
Redeemable Serial Preferred Stock		—		—		6		5

The fair value of long-term debt issued by ACE was based on actual trade prices as of March 31, 2011 and December 31, 2010, 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 and validated by ACE because actual trade prices were not available.

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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.

(11) COMMITMENTS AND CONTINGENCIES

Regulatory and Other Matters

Rate Proceedings

Over the last several years, ACE has proposed the adoption of a mechanism to decouple retail distribution revenue from the amount of power delivered to retail customers in New Jersey. A bill stabilization adjustment (BSA) that had been proposed by ACE as part of a Phase 2 to its current base rate proceeding has not been included in a settlement filed on April 20, 2011, which is subject to NJBPU approval, and accordingly there is no BSA proposal currently pending. 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 ACE to promote energy efficiency programs for its 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 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.

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ACE believes that the B.L. England boiler slag sold to MDC was a valuable material with various industrial applications and, therefore, the sale was not an arrangement for the disposal or treatment of any hazardous substances as would be necessary to constitute a basis for liability under CERCLA. ACE intends to contest any claims to the contrary made by EPA. In a May 2009 decision arising under CERCLA, which did not involve ACE, the U.S. Supreme Court rejected an EPA argument that the sale of a useful product constituted an arrangement for disposal or treatment of hazardous substances. While this decision supports ACE’s position, at this time ACE cannot predict how EPA will proceed with respect to the Franklin Slag Pile site, or what portion, if any, of the Franklin Slag Pile site response costs EPA would seek to recover from ACE. Costs to resolve this matter are not expected to be material.

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 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 and therefore, costs incurred to resolve this matter are not expected to be material.

Price’s Pit Site. ACE owns a transmission and distribution right-of-way that traverses the Price’s Pit superfund site in Egg Harbor Township, New Jersey. EPA placed Price’s Pit on the NPL in 1983 and the New Jersey Department of Environmental Protection (NJDEP) undertook an environmental investigation to identify and implement remedial action at the site. NJDEP’s investigation revealed that landfill waste had been disposed on ACE’s right-of-way and NJDEP determined that ACE was a responsible party 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 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. The financial impact related to these amendments cannot be predicted at this time; however, based on current information, ACE does not believe these suits will have a material adverse effect on its financial condition, results of operations or cash flows.

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(12) 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 three months ended March 31, 2011 and 2010 were approximately $24 million and $26 million, respectively.

In addition to the PHI Service Company charges described above, ACE’s financial statements include the following related party transactions in the Consolidated Statements of Income:

	For the Three  Months Ended March 31,
Income (Expense)	2011			2010
	(millions of dollars)
Purchased power under Default Electricity Supply contracts with Conectiv Energy Supply, Inc. (a) (c)	$	—		$	(39	)
Meter reading services provided by Millennium Account Services LLC (b)		(1	)		(1	)

(a) Included in purchased energy expense.

(b) Included in other operation and maintenance expense.

(c) During 2010, PHI sold Conectiv Energy’s wholesale power generation business.

As of March 31, 2011 and December 31, 2010, ACE had the following balances on its balance sheets due to related parties:

Liability	March 31, 2011			December 31, 2010
	(millions of dollars)
Payable to Related Party (current) (a)
PHI Service Company	$	(11	)	$	(13	)
Conectiv Energy Supply, Inc.		(1	)		(14	)
Other		(2	)		(2	)
Total	$	(14	)	$	(29	)

(a) These amounts are included in the “Accounts payable due to associated companies” balance on the Consolidated Balance Sheets.

(13) RESTRUCTURING CHARGE

With the ongoing wind down of the retail energy supply business of Pepco Energy Services and the disposition of Conectiv Energy, PHI repositioned itself as a regulated transmission and distribution company during 2010. In connection with this repositioning, PHI completed a comprehensive organizational review in 2010 that identified opportunities to streamline the organization and to achieve certain reductions in corporate overhead costs that are allocated to its operating segments, which resulted in the adoption of a restructuring plan. PHI began implementation of the plan during 2010, identifying 164 employee positions that were eliminated. The plan also includes additional cost reduction opportunities that are being implemented through process improvements and operational efficiencies.

In connection with the restructuring plan, ACE recorded a pre-tax restructuring charge of $6 million in 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 at December 31, 2010.

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A reconciliation of ACE’s accrued restructuring charges for the three months ended March 31, 2011 is as follows:

	Three Months Ended March 31, 2011
	(millions of dollars)
Beginning balance as of January 1, 2011	$	6
Restructuring charge		—
Cash payments		(4	)
Ending balance as of March 31, 2011	$	2

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Item 2. 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		98
Pepco		123
DPL		132
ACE		142

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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. 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.

	Three Months Ended March 31,
	2011	2010
Percentage of Consolidated Operating Revenue
Power Delivery	76%		69%
Pepco Energy Services	23%		30%
Other Non-Regulated	1%		1%
Percentage of Consolidated Operating Income
Power Delivery	79%		71%
Pepco Energy Services	11%		19%
Other Non-Regulated	10%		10%
Percentage of Power Delivery Operating Revenue
Power Delivery Electric	92%		92%
Power Delivery Gas	8%		8%

Power Delivery

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 Offer Service in Delaware, the District of Columbia and Maryland, and Basic Generation Service in New Jersey. In this Form 10-Q, these supply service obligations are referred to generally as Default Electricity Supply.

Pepco, DPL and ACE are also responsible for the transmission of wholesale electricity into and across their service territories. The rates each company is permitted to charge for the wholesale transmission of electricity are regulated by the Federal Energy Regulatory Commission (FERC). Transmission rates are updated annually based on a FERC-approved formula methodology.

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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.

Pepco Energy Services

Pepco Energy Services is engaged in the following businesses:

• retail supply of electricity and natural gas under its remaining contractual obligations,

• 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, and

• 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 owns and operates two oil-fired generation facilities that are scheduled for deactivation in May 2012.

In December 2009, PHI announced the wind down of the retail energy supply component of the Pepco Energy Services business. Pepco Energy Services is implementing this wind down by not entering into any new supply contracts, while continuing to perform under its existing supply contracts through their expiration dates. The retail energy supply business has historically generated a substantial portion of the operating revenues and net income of the Pepco Energy Services segment. Operating revenues related to the retail energy supply business for the three months ended March 31, 2011 and 2010 were $305 million and $497 million, respectively, while operating income for the same periods was $12 million and $21 million, respectively.

In connection with the operation of the retail energy supply business, as of March 31, 2011, Pepco Energy Services provided letters of credit of $92 million and posted net cash collateral of $87 million. These collateral requirements, which are based on existing wholesale energy purchase and sale contracts and current market prices, will decrease as the contracts expire, with the collateral expected to be fully released by June 1, 2014. The energy services business will not be affected by the wind down of the retail energy supply business.

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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.

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 March 31, 2011 of approximately $1.4 billion. For a discussion of PHI’s cross-border energy lease investments, see Note (15), “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 I, Item 1 of this Form 10-Q.

Discontinued Operations

In April 2010, the Board of Directors of PHI approved a plan for the disposition of Conectiv Energy, which was 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 Corporation (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 Statements of Income for each of the three months ended March 31, 2011 and 2010. Accordingly, in this Management’s Discussion and Analysis of Financial Condition and Results of Operations, all references to continuing operations exclude the operations of the former Conectiv Energy segment.

Earnings Overview

PHI’s net income from continuing operations for the three months ended March 31, 2011 was $62 million, or $0.27 per share, compared to $28 million, or $0.13 per share, for the three months ended March 31, 2010.

PHI’s net income from discontinued operations for the three months ended March 31, 2011 was $2 million, or $.01 per share, compared to net income of $8 million, or $.03 per share, for the three months ended March 31, 2010.

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

	2011			2010			Change
Power Delivery	$	47		$	20		$	27
Pepco Energy Services		10			13			(3	)
Other Non-Regulated		6			4			2
Corporate and Other		(1	)		(9	)		8
Net Income from Continuing Operations		62			28			34
Discontinued Operations		2			8			(6	)
Total PHI Net Income	$	64		$	36		$	28

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PEPCO HOLDINGS

Discussion of Operating Segment Net Income Variances:

Power Delivery’s $27 million increase in earnings is primarily due to the following:

• $16 million increase from higher distribution revenue consisting of:

• $12 million increase due to distribution rate increases (Pepco in the District of Columbia effective March 2010 and July 2010, and in Maryland effective July 2010; DPL in Delaware effective April 2010; and ACE in New Jersey effective June 2010).

• $4 million increase due to higher distribution sales, primarily due to colder weather.

• $11 million increase from higher transmission revenue primarily attributable to higher rates effective June 1, 2010 that were primarily attributable to an increase in transmission plant investment.

• $7 million increase primarily due to unfavorable income tax adjustments in 2010.

• $3 million increase associated with higher Default Electricity Supply margins, primarily resulting from an approval by the DCPSC of an increase in Pepco’s cost recovery rate for providing Standard Offer Service (SOS) in the District of Columbia to provide for recovery of higher cash working capital costs incurred in prior periods.

• $15 million decrease due to higher operating and maintenance expenses primarily from increased system preventive maintenance and reliability activity.

Pepco Energy Services’ $3 million decrease in earnings is primarily due to the on-going wind down of the retail electricity and natural gas supply businesses, and lower capacity revenues from the generating facilities; partially offset by higher construction revenues.

Corporate and Other’s $8 million increase in earnings is primarily due to lower interest expense as the result of the reduction in outstanding debt due to the retirement of debt with the Conectiv Energy sale proceeds; partially offset by favorable income tax adjustments in 2010 from the release of certain deferred tax valuation allowances related to state net operating losses.

In 2011, earnings from discontinued operations decreased by $6 million primarily because the results for the first quarter of 2010 include the operations of Conectiv Energy prior to its disposition.

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PEPCO HOLDINGS

Consolidated Results of Operations

The following results of operations discussion is for the three months ended March 31, 2011, compared to the three months ended March 31, 2010. All amounts in the tables (except sales and customers) are in millions of dollars.

Continuing Operations

Operating Revenue

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

	2011			2010			Change
Power Delivery	$	1,249		$	1,262		$	(13	)
Pepco Energy Services		373			547			(174	)
Other Non-Regulated		14			13			1
Corporate and Other		(2	)		(3	)		1
Total Operating Revenue	$	1,634		$	1,819		$	(185	)

Power Delivery Business

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

	2011		2010		Change
Regulated T&D Electric Revenue	$	452	$	397	$	55
Default Electricity Supply Revenue		679		755		(76	)
Other Electric Revenue		16		15		1
Total Electric Operating Revenue		1,147		1,167		(20	)
Regulated Gas Revenue		91		87		4
Other Gas Revenue		11		8		3
Total Gas Operating Revenue		102		95		7
Total Power Delivery Operating Revenue	$	1,249	$	1,262	$	(13	)

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. Transmission rates are updated annually based on a FERC-approved formula methodology.

Default Electricity Supply Revenue is the revenue received from the supply of electricity by PHI’s utility subsidiaries at regulated rates to retail customers who do not elect to purchase electricity from a competitive energy supplier. 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).

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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

	2011		2010		Change
Regulated T&D Electric Revenue
Residential	$	168	$	149	$	19
Commercial and industrial		202		183		19
Other		82		65		17
Total Regulated T&D Electric Revenue	$	452	$	397	$	55

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

	2011		2010		Change
Regulated T&D Electric Sales (Gigawatt hours (GWh))
Residential		4,775		4,877		(102	)
Commercial and industrial		7,305		7,201		104
Other		68		68		—
Total Regulated T&D Electric Sales		12,148		12,146		2

	2011		2010		Change
Regulated T&D Electric Customers (in thousands)
Residential		1,638		1,630		8
Commercial and industrial		198		198		—
Other		2		2		—
Total Regulated T&D Electric Customers		1,838		1,830		8

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.

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Regulated T&D Electric Revenue increased by $55 million primarily due to:

• An increase of $21 million due to distribution rate increases (Pepco in the District of Columbia effective March 2010 and July 2010, and in Maryland effective July 2010; DPL in Delaware effective April 2010; and ACE in New Jersey effective June 2010).

• An increase of $19 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 $3 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).

The aggregate amount of these increases was partially offset by:

• A decrease of $6 million due to an ACE New Jersey Societal Benefit charge rate decrease that became effective in January 2011 (which is offset in Deferred Electric Service Costs).

Default Electricity Supply

	2011		2010		Change
Default Electricity Supply Revenue
Residential	$	469	$	521	$	(52	)
Commercial and industrial		168		179		(11	)
Other		42		55		(13	)
Total Default Electricity Supply Revenue	$	679	$	755	$	(76	)

Other Default Electricity Supply Revenue consists primarily of (i) revenue from the resale by ACE 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.

	2011		2010		Change
Default Electricity Supply Sales (GWh)
Residential		4,298		4,680		(382	)
Commercial and industrial		1,558		1,755		(197	)
Other		19		25		(6	)
Total Default Electricity Supply Sales		5,875		6,460		(585	)

	2011		2010		Change
Default Electricity Supply Customers (in thousands)
Residential		1,495		1,573		(78	)
Commercial and industrial		144		158		(14	)
Other		1		2		(1	)
Total Default Electricity Supply Customers		1,640		1,733		(93	)

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Default Electricity Supply Revenue decreased by $76 million primarily due to:

• A decrease of $52 million due to lower sales, primarily as a result of commercial and residential customer migration to competitive suppliers.

• A decrease of $9 million due to lower non-weather related average customer usage.

• A decrease of $8 million in wholesale energy and capacity resale revenues primarily due to the sale of lower volumes of electricity and capacity purchased from NUGs.

• A net decrease of $5 million as a result of lower Pepco and DPL Default Electricity Supply rates, partially offset by higher ACE rates.

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

The decrease in total Default Electricity Supply Revenue includes an increase of $4 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 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 three months ended March 31, 2011, BGS unbilled revenue increased by $4 million as compared to the three months ended March 31, 2010, which resulted in a $3 million increase in PHI’s net income. The increase was primarily due to ACE’s higher Default Electricity Supply rates during the unbilled revenue period at the end of the three months ended March 31, 2011 as compared to the corresponding period in 2010.

Regulated Gas

	2011		2010		Change
Regulated Gas Revenue
Residential	$	57	$	55	$	2
Commercial and industrial		31		30		1
Transportation and other		3		2		1
Total Regulated Gas Revenue	$	91	$	87	$	4

	2011		2010		Change
Regulated Gas Sales (billion cubic feet)
Residential		4		4		—
Commercial and industrial		2		2		—
Transportation and other		3		2		1
Total Regulated Gas Sales		9		8		1

	2011		2010		Change
Regulated Gas Customers (in thousands)
Residential		114		114		—
Commercial and industrial		10		9		1
Transportation and other		—		—		—
Total Regulated Gas Customers		124		123		1

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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 increased by $4 million primarily due to:

• An increase of $14 million due to higher sales as a result of colder weather.

• An increase of $1 million due to distribution rate increases effective August 2010 and February 2011.

The aggregate amount of these increases was partially offset by:

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

Other Gas Revenue

Other Gas Revenue increased by $3 million primarily due to higher volumes of revenue from off-system sales to electric generators and gas marketers.

Pepco Energy Services

Pepco Energy Services’ operating revenue decreased $174 million primarily due to:

• A decrease of $189 million due to lower retail energy supply sales volume primarily attributable to the ongoing wind down of the retail energy supply business.

• A decrease of $6 million due to lower capacity revenues from the generating facilities.

The aggregate amount of these decreases was partially offset by:

• An increase of $20 million due to increased energy services and high voltage construction activities.

Operating Expenses

Fuel and Purchased Energy and Other Services Cost of Sales

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

	2011		2010			Change
Power Delivery	$	706	$	817		$	(111	)
Pepco Energy Services		331		496			(165	)
Corporate and Other		1		(1	)		2
Total	$	1,038	$	1,312		$	(274	)

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Power Delivery Business

Power Delivery’s Fuel and Purchased Energy consists of the cost of electricity and natural gas purchased by its utility subsidiaries to fulfill their respective Default Electricity Supply and Regulated Gas obligations and, as such, is recoverable from customers in accordance with the terms of public service commission orders. It also includes the cost of natural gas purchased for off-system sales. Fuel and Purchased Energy expense decreased by $111 million primarily due to:

• A decrease of $71 million primarily due to customer migration to competitive suppliers.

• A decrease of $48 million due to lower average electricity costs under Default Electricity Supply contracts.

Pepco Energy Services

Pepco Energy Service’s Fuel and Purchased Energy and Other Services Cost of Sales decreased $165 million primarily due to:

• A decrease of $122 million due to lower volumes of electricity purchased to serve decreased retail electricity sales volume as a result of the ongoing wind down of the retail energy supply business.

• A decrease of $59 million due to lower volumes of gas purchased to serve decreased retail gas volumes as a result of the ongoing wind down of the retail energy supply business.

• A decrease of $2 million due to lower purchases of installed capacity and lower fuel usage associated with the generating facilities.

The aggregate amount of these decreases was partially offset by:

• An increase of $18 million due to increased high voltage and energy services construction activities.

Other Operation and Maintenance

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

	2011			2010			Change
Power Delivery	$	222		$	198		$	24
Pepco Energy Services		21			21			—
Corporate and Other		(9	)		(5	)		(4	)
Total	$	234		$	214		$	20

Other Operation and Maintenance expense for Power Delivery increased by $24 million; however, excluding an increase of $2 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 $22 million. The $22 million increase was primarily due to:

• An increase of $10 million primarily due to higher tree trimming and corrective and preventative maintenance costs.

• An increase of $5 million in employee-related costs, primarily due to higher worker compensation, long-term disability and other benefit expenses.

• An increase of $3 million in regulatory expenses due to an expense reduction recorded in February 2010 for recoverable District of Columbia distribution rate case costs.

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Depreciation and Amortization

Depreciation and Amortization expense increased by $16 million to $105 million in 2011 from $89 million in 2010 primarily due to:

• An increase of $7 million in amortization of stranded costs as the result of higher revenue due to rate increases effective October 2010 for the ACE Transition Bond Charge and the Market Transition Charge Tax (partially offset in Default Electricity Supply Revenue).

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

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

• An increase of $1 million in amortization of deferred Demand Side Management expenses.

Other Taxes

Other Taxes increased by $19 million to $111 million in 2011 from $92 million in 2010. The increase was primarily due to rate increases in the Montgomery County, Maryland utility taxes that are collected and passed through by Pepco (substantially offset by a corresponding increase in Regulated T&D Electric Revenue).

Deferred Electric Service Costs

Deferred Electric Service Costs, which relate only to ACE, represent (i) the over or under recovery of electricity costs incurred by ACE to fulfill its Default Electricity Supply obligation and (ii) the over or under recovery of New Jersey Societal Benefit Program costs incurred by ACE. The cost of electricity purchased is reported under Fuel and Purchased Energy and the corresponding revenue is reported under Default Electricity Supply Revenue. The cost of New Jersey Societal Benefit Programs is reported under Other Operation and Maintenance and the corresponding revenue is reported under Regulated T&D Electric Revenue.

Deferred Electric Service Costs increased by $16 million, to an expense reduction of $3 million in 2011 as compared to an expense reduction of $19 million in 2010, primarily due to an increase in deferred electricity expense as a result of higher Default Electricity Supply revenue rates and lower electricity supply costs.

Other Income (Expenses)

Other Expenses (which are net of Other Income) decreased by $25 million primarily due to lower interest expense as a result of the reduction in outstanding long-term debt due to the retirement of debt in 2010 with the proceeds from the Conectiv Energy sale.

Income Tax Expense

PHI’s consolidated effective tax rates from continuing operations for the three months ended March 31, 2011 and 2010 were 35.4% and 47.2%, respectively. The reduction in the effective tax rate is partially due to changes in estimates and interest related to uncertain and effectively settled tax positions that had increased PHI’s effective tax rate for the three months ended March 31, 2010. The changes primarily related to a $2 million reversal of accrued interest income on state income tax positions that PHI no longer believes is more likely than not to be realized and the reversal of $6 million of erroneously accrued interest income on uncertain and effectively settled state income tax positions, each recorded in 2010.

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The decrease in the rate is further impacted by the 2010 change in taxation of the Medicare Part D subsidy enacted by the Patient Protection and Affordable Care Act (Patient Protection Act) that increased PHI’s effective tax rate for the three months ended March 31, 2010. PHI receives a tax-free federal subsidy for the costs it incurs for certain prescription drugs covered under its post-employment benefit plan. Prior to the Patient Protection Act, the costs incurred for those prescription drugs were also tax deductible. The Patient Protection Act includes a provision, effective beginning in 2013, which eliminates the tax deductibility of the prescription drug costs. As a result, PHI wrote off $5 million of deferred tax assets. Of this amount, $3 million was established as a regulatory asset, which PHI anticipates will be recoverable from its utility customers in the future. This change increased PHI’s first quarter 2010 tax expense by $4 million, which was partially offset through a reduction in Operating Expenses resulting in a $2 million decrease to net income.

The decrease in the rate between 2011 and 2010 is also affected by the 2010 release of $8 million of valuation allowances on deferred tax assets related to state net operating losses resulting from the planned restructuring of certain PHI subsidiaries. On April 1, 2010, as part of an ongoing effort to simplify PHI’s organizational structure, certain of PHI’s subsidiaries were converted to single member limited liability companies. In addition to increased organizational flexibility and reduced administrative costs, a consequence of converting these entities is to allow PHI to include income or losses in the former corporations in a single state income tax return, thus permitting the release of the valuation allowances.

Discontinued Operations

For the three months ended March 31, 2011, the $2 million income from discontinued operations, net of income taxes, includes after-tax income of $4 million arising from adjustments to certain accrued expenses for obligations associated with the sale of the wholesale power generation business to Calpine. These adjustments were made to reflect the actual amounts paid to Calpine during the first quarter of 2011. Offsetting these adjustments was an expense of approximately $1 million (after-tax) which was incurred in connection with the financial transaction entered into with a third party on January 6, 2011, 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 paid the third party $82 million, primarily representing the fair value of the derivatives at February 1, 2011, and an after-tax administrative fee of $1 million. No additional material gain or loss was recognized as a result of this transaction as the derivatives were previously marked to fair value through earnings in 2010.

Income from discontinued operations, net of income taxes for the three months ended March 31, 2010 represents earnings from power generation, load service and energy marketing activities of Conectiv Energy prior to the sale of the wholesale power generation business to Calpine and the liquidation of the remaining assets and liabilities of Conectiv Energy.

Capital Resources and Liquidity

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

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Working Capital

At March 31, 2011, Pepco Holdings’ current assets on a consolidated basis totaled $1.5 billion and its current liabilities totaled $1.7 billion. PHI expects the working capital deficit at March 31, 2011 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. At December 31, 2010, Pepco Holdings’ current assets on a consolidated basis totaled $1.8 billion and its current liabilities totaled $1.8 billion. The approximate $200 million decrease in working capital from December 31, 2010 to March 31, 2011 was due primarily to the decrease in prepayments of income taxes and deferred income tax assets in addition to a decrease in the current portion of Conectiv Energy assets held for sale.

At March 31, 2011, Pepco Holdings’ cash and cash equivalents totaled $18 million, which consisted of cash and uncollected funds. Current restricted cash equivalents (cash that is available to be used only for designated purposes) totaled $13 million. At December 31, 2010, Pepco Holdings’ cash and cash equivalents totaled $21 million, of which $1 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 current maturities of long-term debt and project funding balance follows:

	As of March 31, 2011
	(millions of dollars)
Type	PHI Parent		Pepco		DPL		ACE		ACE Funding		Pepco Energy Services		PHI Consolidated
Variable Rate Demand Bonds	$	—	$	—	$	105	$	23	$	—	$	18	$	146
Commercial Paper		256		—		—		165		—		—		421
Total Short-Term Debt	$	256	$	—	$	105	$	188	$	—	$	18	$	567
Current Maturities of Long-Term Debt and Project Funding	$	—	$	—	$	35	$	—	$	36	$	7	$	78

	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

Financing Activity During the Three Months Ended March 31, 2011

In January 2011, ACE Funding made principal payments of $6 million on Series 2002-1 Bonds, Class A-2, and $2 million on Series 2003-1 Bonds, Class A-2.

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Financing Activity Subsequent to March 31, 2011

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

On May 2, 2011, DPL repurchased, pursuant to a mandatory repurchase obligation, $35 million of 4.9% Delaware Economic Development Authority tax-exempt put bonds due May 1, 2026. DPL plans to remarket these bonds during the second quarter of 2011.

Credit Facilities

PHI, Pepco, DPL and ACE maintain an unsecured syndicated 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. At the PHI level, the 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.

PHI also maintains 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, results of operations or financial condition is not a condition to the availability of credit under the $1.5 billion facility or either credit agreement. Neither the facility nor either of the credit agreements includes any rating triggers.

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Cash and Credit Facilities Available as of March 31, 2011

	Consolidated PHI		PHI Parent		Utility Subsidiaries
	(millions of dollars)
Credit Facilities (Total Capacity)	$	1,700	$	1,075	$	625
Less: Letters of Credit issued		100		95		5
Commercial Paper outstanding		421		256		165
Remaining Credit Facilities Available		1,179		724		455
Cash Invested in Money Market Funds (a)		—		—		—
Total Cash and Credit Facilities Available	$	1,179	$	724	$	455

(a) Cash and cash equivalents reported on the Consolidated Balance Sheet total $18 million, all of which was held in cash and uncollected funds.

Collateral Requirements

At March 31, 2011 and December 31, 2010, the aggregate amount of cash, plus borrowing capacity under the credit facilities available to meet the combined future liquidity needs of Pepco Energy Services and Conectiv Energy totaled $724 million and $728 million, respectively.

Collateral Requirements of Pepco Energy Services

Pepco Energy Services, in the ordinary course of its retail energy supply business, enters into various contracts to buy and sell electricity, fuels and related products, including derivative instruments, designed to reduce its financial exposure to changes in the value of its assets and obligations due to energy price fluctuations. These contracts typically have collateral requirements. Depending on the contract terms, the collateral required to be posted by Pepco Energy Services can be of varying forms, including cash and letters of credit.

During periods of declining energy prices, Pepco Energy Services 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 three months ended March 31, 2011 and 2010, Pepco Energy Services recognized less than $1 million and approximately $2 million, respectively, of the fees in “Interest expense.”

As of March 31, 2011, Pepco Energy Services had posted net cash collateral of $87 million and provided letters of credit of $92 million. At December 31, 2010, Pepco Energy Services had posted net cash collateral of $117 million and provided letters of credit of $113 million. As its retail energy supply business is wound down, Pepco Energy Services’ collateral requirements will be further reduced.

Remaining Collateral Requirements of Conectiv Energy

As of March 31, 2011, Conectiv Energy had posted net cash collateral of less than $1 million and there were no outstanding letters of credit. At December 31, 2010, Conectiv Energy had posted net cash collateral of $104 million and there were no outstanding letters of credit.

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Pension and Postretirement Benefit Plans

Pension benefits are provided under PHI’s defined benefit pension plan (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.

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. Although PHI projects there will be no minimum funding requirement under the Pension Protection Act guidelines in 2011, PHI currently anticipates that it or its subsidiaries may make aggregate 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.

On March 14, 2011, Pepco, ACE and DPL made discretionary tax-deductible contributions to the PHI Retirement Plan in the amounts of $40 million, $30 million and $40 million, respectively. During 2010, PHI Service Company made discretionary tax-deductible contributions totaling $100 million to the PHI Retirement Plan, which brought plan assets to the funding target level for 2010 under the Pension Protection Act. Pepco, ACE and DPL did not make contributions to the PHI Retirement Plan in 2010.

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 and 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 the 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.

Cash Flow Activity

PHI’s cash flows for the three months ended March 31, 2011 and 2010 are summarized below:

	Cash (Use) Source
	2011			2010			Change
	(millions of dollars)
Operating Activities	$	197		$	67		$	130
Investing Activities		(164	)		(207	)		43
Financing Activities		(36	)		132			(168	)
Net decrease in cash and cash equivalents	$	(3	)	$	(8	)	$	5

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Operating Activities

Cash flows from operating activities during the three months ended March 31, 2011 and 2010 are summarized below:

	Cash (Use) Source
	2011			2010			Change
	(millions of dollars)
Net income from continuing operations	$	62		$	28		$	34
Non-cash adjustments to net income		87			73			14
Pension contributions		(110	)		—			(110	)
Changes in cash collateral related to derivative activities		31			(77	)		108
Changes in other assets and liabilities		96			72			24
Changes in Conectiv Energy net assets held for sale		31			(29	)		60
Net cash from operating activities	$	197		$	67		$	130

Net cash from operating activities was $130 million higher for the three months ended March 31, 2011, compared to the same period in 2010. In addition to the increase in cash arising from the increase in net income from continuing operations, portions of the increase in cash are attributable to a decrease in collateral requirements as a result of the wind down of Pepco Energy Services retail energy supply business, changes in non-cash adjustments to net income due to an increase in depreciation and amortization, partially offset by pension plan contributions. The increase 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 (16), “Discontinued Operations.”

Investing Activities

Cash flows from investing activities during the three months ended March 31, 2011 and 2010 are summarized below:

	Cash (Use) Source
	2011			2010			Change
	(millions of dollars)
Investment in property, plant and equipment	$	(171	)	$	(159	)	$	(12	)
DOE capital reimbursement awards received		9			—			9
Changes in restricted cash equivalents		(2	)		2			(4	)
Net other investing activities		—			(1	)		1
Investment in property, plant and equipment associated with Conectiv Energy assets held for sale		—			(49	)		49
Net cash used by investing activities	$	(164	)	$	(207	)	$	43

Net cash used by investing activities decreased $43 million for the three months ended March 31, 2011 compared to the same period in 2010. The decrease was due primarily to reduced investment in property, plant and equipment associated with the discontinued Conectiv Energy business.

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Financing Activities

Cash flows from financing activities during the three months ended March 31, 2011 and 2010 are summarized below:

	Cash (Use) Source
	2011			2010			Change
	(millions of dollars)
Dividends paid on common stock	$	(61	)	$	(60	)	$	(1	)
Common stock issued for the Dividend Reinvestment Plan and employee-related compensation		14			15			(1	)
Redemption of preferred stock of subsidiaries		(6	)		—			(6	)
Issuances of long-term debt		—			23			(23	)
Reacquisition of long-term debt		(9	)		(24	)		15
Issuances of short-term debt, net		33			197			(164	)
Net other financing activities		(7	)		(21	)		14
Net financing activities associated with Conectiv Energy assets held for sale		—			2			(2	)
Net cash (used by) from financing activities	$	(36	)	$	132		$	(168	)

Net cash related to financing activities decreased $168 million for the three months ended March 31, 2011, compared to the same period in 2010 primarily due to changes in outstanding long-term and short-term debt.

Redemption of Preferred Stock

On February 25, 2011, ACE redeemed all of its outstanding cumulative preferred stock for approximately $6 million.

Changes in Outstanding Long-Term Debt

Cash flows from the issuance and reacquisitions of long-term debt for the three months ended March 31, 2011 and 2010 are summarized in the charts below:

	2011		2010
Issuances	(millions of dollars)
ACE
4.875% Tax-exempt bonds due 2029 (a)	$	—	$	23
	$	—	$	23

(a) 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 in respect of the ACE Bonds satisfies the corresponding payment obligations on the senior notes and collateral first mortgage bonds.

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		2011		2010
Reacquisitions		(millions of dollars)
Pepco
	5.75% Tax-exempt bonds due 2010 (a)	$	—	$	16
			—		16
ACE
	Securitization bonds due 2010-2011		9		8
			9		8
		$	9	$	24

(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 was deemed to be a redemption of the collateral first mortgage bonds.

Changes in Short-Term Debt

Cash flows from the issuance of short-term debt, net of repayments, decreased during the three months ended March 31, 2011 as compared to the same period in 2010 as a result of decreased collateral requirements of Pepco Energy Services and Conectiv Energy, and the use of the proceeds from the sale of Conectiv Energy’s wholesale generation business to reduce PHI’s outstanding debt.

Capital Requirements

Capital Expenditures

Pepco Holdings’ total capital expenditures for the three months ended March 31, 2011 totaled $171 million, of which $97 million was incurred by Pepco, $41 million was incurred by DPL and $22 million was incurred by ACE. The remainder was incurred primarily by the PHI Service Company. The Power Delivery expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission.

In its Form 10-K for the year ended December 31, 2010, PHI presented the projected capital expenditures for each of PHI’s financial reporting segments for the five-year period 2011 through 2015. There have been no changes in PHI’s projected capital expenditures from those presented in the Form 10-K, except with respect to the Mid-Atlantic Power Pathway (MAPP) project as discussed below.

Pepco Holdings and its subsidiaries expect to incur significant capital expenditures in connection with the following primary initiatives:

Reliability Enhancement Plans

During 2010, Pepco announced Comprehensive Reliability Enhancement Plans for Maryland and the District of Columbia. Each plan advances work on existing programs and initiates new activities for customers in the respective jurisdictions. These programs include enhanced vegetation management, identification and upgrading of underperforming feeder lines, addition of new facilities to support load growth, installation of distribution automation systems, underground residential cable replacement, substation supply line improvements and selective undergrounding of existing above-ground service lines. By focusing on these 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, which is primarily capitalizable, is estimated to be $100 million in the Maryland service territory and $90 million in the District of Columbia service territory. The total amount of the expenditures may change when anticipated regulations imposing reliability standards are promulgated in Maryland or if the reliability standards currently imposed in the District of Columbia are modified.

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Blueprint for the Future

Each of PHI’s three utilities are participating in a PHI initiative referred to as “Blueprint for the Future,” which is designed to meet the challenges of rising energy costs, concerns about the environment, improved reliability and government energy reduction goals. 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 its 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 business customers to use more energy-efficient equipment, such as improved lighting, heating, ventilation and air-conditioning systems.

• The installation of advanced meters for electric customers and DPL’s natural gas customers as part of an Advanced Metering Infrastructure (AMI). Advanced meters allow the utilities, among other capabilities, to remotely read meters, significantly reduce the use of 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 financial incentives through bill credits or 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:

• Advanced meters:

• Pepco in the District of Columbia: The District of Columbia Public Service Commission (DCPSC) approved the implementation of AMI in December 2009, with cost recovery mechanisms. Full scale implementation of advanced meters began in October 2010 and is expected to be completed in late 2011.

• Pepco in Maryland: The Maryland Public Service Commission (MPSC) approved full scale implementation of AMI in August 2010, with deployment and installation of advanced meters to begin in June 2011 following the implementation 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 Delaware Public Service Commission (DPSC) approved implementation of AMI in September 2008, including cost recovery mechanisms. Implementation of advanced meters began in 2009 and is expected to be completed in 2011.

• ACE: The New Jersey Board of Public Utilities (NJBPU) is not expected to approve ACE’s proposal for implementation of advanced meters in the near term.

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• 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 installation of switches for air conditioners commenced in 2009, and the recovery of costs through a surcharge was approved in January 2010. The recovery of costs for smart thermostats through a surcharge is still in progress. The installation of smart thermostats was temporarily suspended by the MPSC pending resolution of a technical issue. This issue has been resolved and the stay on installations was lifted in March 2011.

• 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 was temporarily suspended by the MPSC pending resolution of a technical issue. This issue has been resolved and the stay on installations was lifted in March 2011.

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

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

Stimulus Funds Related to Blueprint for the Future

During the three months ended March 31, 2011, Pepco and ACE received $8 million and $2 million, respectively, in stimulus funds awarded by the United States Department of Energy (DOE) under the American Recovery and Reinvestment Act of 2009. Through March 31, 2011, Pepco and ACE have received $23 million and $4 million, respectively, of the $149 million and $19 million, respectively, that DOE has agreed to award the companies to fund Blueprint for the Future and other capital expenditures and certain expenses associated with the implementation of direct load control, distribution automation and communication infrastructure in their respective service territories.

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 MAPP, as part of PJM’s regional transmission expansion plan to address the reliability objectives of the PJM Regional Transmission Organization (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 152 miles in length originating at the Possum Point substation in Virginia and ending at the Indian River substation in Delaware. The cost of the MAPP project is currently estimated to be $1.2 billion and the planned in-service date is June 1, 2015.

PJM currently is in its annual process of evaluating the region’s overall transmission needs. The evaluation is expected to take into account changes in demand response, generation retirements and additions, as well as a revised load forecast for the PJM region that is lower than the load that was forecast in prior PJM studies. PJM has stated that it expects to complete this evaluation in August 2011. The outcome of the evaluation could result in a delay of the in-service date for all or a portion of the MAPP project beyond the currently planned in-service date of June 1, 2015.

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The construction of MAPP requires various permits and approvals, including the approval of the MPSC. On April 27, 2011, Pepco and DPL, applicants in the filing pending before the MPSC seeking approval to build the MAPP project, requested a six-month delay to the procedural schedule to allow for the completion of the ongoing PJM review. The request is supported, or not opposed, by most of the parties to the case. The proposed revision to the schedule calls for direct testimony of the parties to be filed in December 2011 and evidentiary hearings to be held in March 2012.

Because the impact of the PJM review on the in-service date for MAPP will not be known until August 2011, PHI anticipates that $90 million to $110 million of the currently projected 2011 MAPP capital expenditures of $163 million will be deferred to later years.

MAPP/DOE Loan Program

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

Third Party Guarantees, Indemnifications, Obligations and Off-Balance Sheet Arrangements

For a discussion of PHI’s third party guarantees, indemnifications, obligations and off-balance sheet arrangements, see Note (15), “Commitments and Contingencies,” to the Consolidated Financial Statements of PHI included as Part I, Item 1, in this

Form 10-Q.

Dividends

On April 28, 2011, Pepco Holdings’ Board of Directors declared a dividend on common stock of 27 cents per share payable June 30, 2011 to shareholders of record on June 10, 2011. PHI had approximately $1,062 million and $1,059 million of retained earnings free of restrictions at March 31, 2011 and December 31, 2010, respectively.

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 three months ended March 31, 2011. The balances in the table are pre-tax and the derivative assets and liabilities reflect netting by counterparty before the impact of collateral.

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	Energy Commodity Activities (a)
	(millions of dollars)
Total Fair Value of Energy Contract Net Liabilities at December 31, 2010	$	(218	)
Current period unrealized gains		—
Effective portion of changes in fair value – recorded in Accumulated Other Comprehensive Loss		(1	)
Cash flow hedge ineffectiveness – recorded in income		—
Recognition of realized losses on settlement of contracts		24
Derivative activity associated with Conectiv Energy		83
Total Fair Value of Energy Contract Net Liabilities at March 31, 2011	$	(112	)
Detail of Fair Value of Energy Contract Net Liabilities at March 31, 2011 (see above)
Derivative assets (current assets)	$	17
Derivative assets (non-current assets)		—
Total Fair Value of Energy Contract Assets		17
Derivative liabilities (current liabilities)		(121	)
Derivative liabilities (non-current liabilities)		(8	)
Total Fair Value of Energy Contract Liabilities		(129	)
Total Fair Value of Energy Contract Net Liabilities	$	(112	)

(a) Includes all hedging and trading activities recorded at fair value through Accumulated Other Comprehensive Loss (AOCL) or trading activities recorded at fair value in the Consolidated Statements of Income, as required.

The $112 million net liability on energy contracts at March 31, 2011 was attributable to losses on power swaps and natural gas futures and swaps held by Pepco Energy Services. Effective February 1, 2011, Conectiv Energy transferred its derivatives to an unaffiliated third party, which significantly contributed to the reduction in PHI’s overall losses on derivatives from $218 million at December 31, 2010 to $112 million at March 31, 2011. Pepco Energy Services’ net liability decreased to $112 million at March 31, 2011 from $135 million at December 31, 2010 primarily due to settlements of the derivatives. PHI expects that when the energy contracts of Pepco Energy Services’ settle, the related realized gains or losses will be largely offset by the realized loss or gain on future energy purchases that will be used to settle Pepco Energy Services’ sales obligations to its customers.

PHI uses its best estimates to determine the fair value of Pepco Energy Services’ commodity derivative contracts. The fair values in each category presented below reflect forward prices and volatility factors as of March 31, 2011 and are subject to change as a result of changes in these factors.

	Fair Value of Contracts at March 31, 2011 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	$	(33	)	$	(17	)	$	(5	)	$	(1	)	$	(56	)
Prices provided by other external sources (b)		(30	)		(21	)		(5	)		—			(56	)
Total	$	(63	)	$	(38	)	$	(10	)	$	(1	)	$	(112	)

(a) Includes all effective hedging activities recorded at fair value through AOCL and hedge ineffectiveness and trading activities on the Consolidated 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.

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Contractual Arrangements with Credit Rating Triggers or Margining Rights

Under certain contractual arrangements entered into by PHI’s subsidiaries, the subsidiary may be required to provide cash collateral or letters of credit as security for its contractual obligations if the credit ratings of PHI or the subsidiary are downgraded. In the event of a downgrade, the amount required to be posted would depend on the amount of the underlying contractual obligation existing at the time of the downgrade. Based on contractual provisions in effect at March 31, 2011, a downgrade in the unsecured debt credit ratings of PHI and each of its rated subsidiaries to below “investment grade” would increase the collateral obligation of PHI and its subsidiaries by up to $295 million, $3 million of which is related to discontinued operations of Conectiv Energy, and $182 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 (13), “Derivative Instruments and Hedging Activities” to the Consolidated Financial Statements of PHI set forth in Part I, Item 1 of this Form 10-Q. The remaining $110 million of the collateral obligation that would be incurred in the event PHI was 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 March 31, 2011, Pepco Energy Services provided net cash collateral in the amount of $87 million and Conectiv Energy provided net cash collateral in the amount of less than $1 million in connection with these activities.

Regulatory And Other Matters

For a discussion of material pending matters such as regulatory and legal proceedings, and other commitments and contingencies, see Note (15), “Commitments and Contingencies,” to the Consolidated Financial Statements of PHI set forth in Part I, Item 1 of this Form 10-Q.

Critical Accounting Policies

For a discussion of Pepco Holdings’ critical accounting policies, please refer to Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations in Pepco Holdings’ Annual Report on Form 10-K for the year ended December 31, 2010. There have been no material changes to PHI’s critical accounting policies as disclosed in the Form 10-K.

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 I, Item 1 of this Form 10-Q.

Forward-Looking Statements

Some of the statements contained in this Quarterly Report on Form 10-Q 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

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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;

• 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 Quarterly Report on Form 10-Q 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 such factors, nor can Pepco Holdings assess the impact of any such factor on Pepco Holdings’ 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 H to the Form 10-Q, and accordingly information otherwise required under this Item has been omitted.

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 March 31, 2011, approximately 58% of delivered electricity sales were to Maryland customers and approximately 42% were to 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 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.

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 three months ended March 31, 2011 to the three months ended March 31, 2010. All amounts in the tables (except sales and customers) are in millions of dollars.

Operating Revenue

	2011		2010		Change
Regulated T&D Electric Revenue	$	258	$	219	$	39
Default Electricity Supply Revenue		268		324		(56	)
Other Electric Revenue		8		9		(1	)
Total Operating Revenue	$	534	$	552	$	(18	)

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 SOS. The costs related to Default Electricity Supply are included in Purchased Energy. Default Electricity Supply Revenue also includes revenue in the form of 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

	2011		2010		Change
Regulated T&D Electric Revenue
Residential	$	78	$	62	$	16
Commercial and industrial		147		130		17
Other		33		27		6
Total Regulated T&D Electric Revenue	$	258	$	219	$	39

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

	2011		2010		Change
Regulated T&D Electric Sales (Gigawatt hours (GWh))
Residential		2,177		2,252		(75	)
Commercial and industrial		4,384		4,344		40
Other		44		44		—
Total Regulated T&D Electric Sales		6,605		6,640		(35	)
	2011		2010		Change
Regulated T&D Electric Customers (in thousands)
Residential		715		709		6
Commercial and industrial		74		74		—
Other		—		—		—
Total Regulated T&D Electric Customers		789		783		6

Regulated T&D Electric Revenue increased by $39 million primarily due to:

• An increase of $19 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 $11 million due to distribution rate increases in the District of Columbia effective March 2010 and July 2010; and in Maryland effective July 2010.

• An increase of $6 million in transmission revenue primarily attributable to higher rates effective June 1, 2010 related to an increase in transmission plant investment.

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

Default Electricity Supply

	2011		2010		Change
Default Electricity Supply Revenue
Residential	$	199	$	240	$	(41	)
Commercial and industrial		67		80		(13	)
Other		2		4		(2	)
Total Default Electricity Supply Revenue	$	268	$	324	$	(56	)
	2011		2010		Change
Default Electricity Supply Sales (GWh)
Residential		1,892		2,087		(195	)
Commercial and industrial		694		777		(83	)
Other		2		3		(1	)
Total Default Electricity Supply Sales		2,588		2,867		(279	)

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	2011		2010		Change
Default Electricity Supply Customers (in thousands)
Residential		633		660		(27	)
Commercial and industrial		47		50		(3	)
Other		—		—		—
Total Default Electricity Supply Customers		680		710		(30	)

Default Electricity Supply Revenue decreased by $56 million primarily due to:

• A decrease of $27 million as a result of lower Default Electricity Supply rates.

• A decrease of $22 million due to lower sales, primarily as a result of customer migration to competitive suppliers.

• A decrease of $7 million due to lower non-weather related average customer usage.

• A decrease of $3 million due to lower sales as a result of milder weather during the 2011 winter months as compared to 2010.

The aggregate amount of these decreases was partially offset by:

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

The following table shows the percentages of Pepco’s total distribution sales by jurisdiction that are derived from customers receiving Default Electricity Supply from Pepco. Amounts are for the three months ended March 31.

	2011			2010
Sales to District of Columbia customers		29	%		31	%
Sales to Maryland customers		47	%		52	%

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 $60 million to $255 million in 2011 from $315 million in 2010 primarily due to:

• A decrease of $28 million primarily due to customer migration to competitive suppliers.

• A decrease of $28 million due to lower average electricity costs under Default Electricity Supply contracts.

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Other Operation and Maintenance

Other Operation and Maintenance increased by $14 million to $102 million in 2011 from $88 million in 2010 primarily due to:

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

• An increase of $5 million primarily due to higher tree trimming and corrective and preventative maintenance costs.

• An increase of $3 million in regulatory expenses due to an expense reduction recorded in February 2010 for recoverable District of Columbia distribution rate case costs.

Depreciation and Amortization

Depreciation and Amortization expense increased by $4 million to $42 million in 2011 from $38 million in 2010 primarily due to:

• An increase of $2 million in amortization of regulatory assets primarily associated with the EmPower Maryland surcharge that became effective in March 2010 (which is substantially offset by a corresponding increase in Regulated T&D Electric Revenue).

• An increase of $1 million due to utility plant additions.

• An increase of $1 million in amortization of deferred Demand Side Management expenses.

Other Taxes

Other Taxes increased by $17 million to $92 million in 2011 from $75 million in 2010. The increase was primarily due to rate increases in the Montgomery County, Maryland utility taxes that are collected and passed through by Pepco (substantially offset by a corresponding increase in Regulated T&D Electric Revenue).

Other Income (Expenses)

Other Expenses (which are net of Other Income) decreased by $4 million to a net expense of $18 million in 2011 from a net expense of $22 million in 2010. The decrease was primarily due to:

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

• An increase of $1 million in other income related to the debt portion of Allowance for Funds Used During Construction that is applied to capital projects.

Income Tax Expense

Pepco’s effective tax rates for the three months ended March 31, 2011 and 2010 were 28.0% and 42.9%, respectively. The decrease in the effective tax rate primarily resulted from changes in estimates and interest relating to uncertain and effectively settled tax positions, permanent differences related to deferred compensation funding and depreciation.

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In March of 2011, Pepco accrued $3 million related to estimated proceeds from life insurance policies on a former executive. This income is not taxable and is included in the permanent differences related to deferred compensation funding.

Capital Requirements

Capital Expenditures

Pepco’s capital expenditures for the three months ended March 31, 2011, totaled $97 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.

In its Form 10-K for the year ended December 31, 2010, Pepco presented its projected capital expenditures for the five-year period 2011 through 2015. There have been no changes in Pepco’s projected capital expenditures from those presented in the Form 10-K, except with respect to the Mid-Atlantic Power Pathway (MAPP) project as discussed below.

Pepco expects to incur significant capital expenditures in connection with the following primary initiatives:

Reliability Enhancement Plans

During 2010, Pepco announced Comprehensive Reliability Enhancement Plans for Maryland and the District of Columbia. Each plan advances work on existing programs and initiates new activities for customers in the respective jurisdictions. These programs include enhanced vegetation management, identification and upgrading of underperforming feeder lines, addition of new facilities to support load growth, installation of distribution automation systems, underground residential cable replacement, substation supply line improvements and selective undergrounding of existing above-ground service lines. By focusing on these 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, which is primarily capitalizable, is estimated to be $100 million in the Maryland service territory and $90 million in the District of Columbia service territory. The total amount of the expenditures may change when anticipated regulations imposing reliability standards are promulgated in Maryland or if the reliability standards currently imposed in the District of Columbia are modified.

Blueprint for the Future

Pepco is participating in a PHI initiative referred to as “Blueprint for the Future,” which is designed to meet the challenges of rising energy costs, concerns about the environment, improved reliability and government energy reduction goals. 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 its 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 business customers to use more energy-efficient equipment, such as improved lighting, heating, ventilation and air-conditioning systems.

• The installation of advanced meters for electric customers as part of an Advanced Metering Infrastructure (AMI). Advanced meters allow Pepco, among other capabilities, to remotely read meters, significantly reduce the use of estimated bills, improve outage management, and provide customers with more detailed information about their energy consumption.

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• 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 financial incentives through bill credits or 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:

• Advanced meters:

• Pepco in the District of Columbia: The District of Columbia Public Service Commission (DCPSC) approved the implementation of AMI in December 2009, with cost recovery mechanisms. Full scale implementation of advanced meters began in October 2010 and is expected to be completed in late 2011.

• Pepco in Maryland: The MPSC approved full scale implementation of AMI in August 2010, with deployment and installation of advanced meters to begin in June 2011 following the implementation of a customer education plan.

• 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 installation of switches for air conditioners commenced in 2009, and the recovery of costs through a surcharge was approved in January 2010. The recovery of costs for smart thermostats through a surcharge is still in progress. The installation of smart thermostats was temporarily suspended by the MPSC pending resolution of a technical issue. This issue has been resolved and the stay on installations was lifted in March 2011.

Stimulus Funds Related to Blueprint for the Future

During the three months ended March 31, 2011, Pepco received $8 million in stimulus funds awarded by the United States Department of Energy (DOE) under the American Recovery and Reinvestment Act of 2009. Through March 31, 2011, Pepco received $23 million of the $149 million that DOE has agreed to award the company to fund Blueprint for the Future and other capital expenditures and certain expenses associated with the implementation of direct load control, distribution automation and communication infrastructure in their respective service territories.

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 MAPP, as part of PJM’s regional transmission expansion plan to address the reliability objectives of the PJM Regional Transmission Organization (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 152 miles in length originating at the Possum Point substation in Virginia and ending at the Indian River substation in Delaware. The cost of the MAPP project is currently estimated to be $1.2 billion and the planned in-service date is June 1, 2015.

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PJM currently is in its annual process of evaluating the region’s overall transmission needs. The evaluation is expected to take into account changes in demand response, generation retirements and additions, as well as a revised load forecast for the PJM region that is lower than the load that was forecast in prior PJM studies. PJM has stated that it expects to complete this evaluation in August 2011. The outcome of the evaluation could result in a delay of the in-service date for all or a portion of the MAPP project beyond the currently planned in-service date of June 1, 2015.

The construction of MAPP requires various permits and approvals, including the approval of the MPSC. On April 27, 2011, Pepco and its affiliate Delmarva Power & Light Company, applicants in the filing pending before the MPSC seeking approval to build the MAPP project, requested a six-month delay to the procedural schedule to allow for the completion of the ongoing PJM review. The request is supported, or not opposed, by most of the parties to the case. The proposed revision to the schedule calls for direct testimony of the parties to be filed in December 2011 and evidentiary hearings to be held in March 2012.

Because the impact of the PJM review on the in-service date for MAPP will not be known until August 2011, Pepco anticipates that $65 million to $79 million of the currently projected 2011 MAPP capital expenditures of $112 million will be deferred to later years.

MAPP/DOE Loan Program

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

Forward-Looking Statements

Some of the statements contained in this Quarterly Report on Form 10-Q 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.

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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

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

Any forward-looking statements speak only as to the date of this Quarterly Report on Form 10-Q 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 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.

131

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 H to the Form 10-Q, and accordingly information otherwise required under this Item has been omitted.

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 March 31, 2011, approximately 64% of delivered electricity sales were to Delaware customers and approximately 36% 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 electric 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.

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 three months ended March 31, 2011 to the three months ended March 31, 2010. All amounts in the tables (except sales and customers) are in millions of dollars.

Electric Operating Revenue

	2011		2010		Change
Regulated T&D Electric Revenue	$	104	$	87	$	17
Default Electricity Supply Revenue		190		208		(18	)
Other Electric Revenue		4		4		—
Total Electric Operating Revenue	$	298	$	299	$	(1	)

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 SOS. The costs related to Default Electricity Supply are included in Purchased Energy. Default Electricity Supply Revenue also includes transmission enhancement credits that DPL receives as a transmission owner from PJM for approved regional transmission expansion plan costs.

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

Regulated T&D Electric

	2011		2010		Change
Regulated T&D Electric Revenue
Residential	$	52	$	48	$	4
Commercial and industrial		27		24		3
Other		25		15		10
Total Regulated T&D Electric Revenue	$	104	$	87	$	17

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

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	2011		2010		Change
Regulated T&D Electric Sales (Gigawatt hours (GWh))
Residential		1,520		1,528		(8	)
Commercial and industrial		1,744		1,683		61
Other		12		12		—
Total Regulated T&D Electric Sales		3,276		3,223		53
	2011		2010		Change
Regulated T&D Electric Customers (in thousands)
Residential		441		439		2
Commercial and industrial		59		59		—
Other		1		1		—
Total Regulated T&D Electric Customers		501		499		2

Regulated T&D Electric Revenue increased by $17 million primarily due to:

• An increase of $10 million in transmission revenue primarily attributable to higher rates effective June 1, 2010 related to an increase in transmission plant investment.

• An increase of $5 million due to a distribution rate increase in Delaware effective April 2010.

Default Electricity Supply

	2011		2010		Change
Default Electricity Supply Revenue
Residential	$	147	$	161	$	(14	)
Commercial and industrial		40		44		(4	)
Other		3		3		—
Total Default Electricity Supply Revenue	$	190	$	208	$	(18	)
	2011		2010		Change
Default Electricity Supply Sales (GWh)
Residential		1,429		1,496		(67	)
Commercial and industrial		480		465		15
Other		7		10		(3	)
Total Default Electricity Supply Sales		1,916		1,971		(55	)
	2011		2010		Change
Default Electricity Supply Customers (in thousands)
Residential		419		431		(12	)
Commercial and industrial		44		47		(3	)
Other		1		1		—
Total Default Electricity Supply Customers		464		479		(15	)

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Default Electricity Supply Revenue decreased by $18 million primarily due to:

• A decrease of $10 million as a result of lower Default Electricity Supply rates.

• A decrease of $9 million due to lower sales, primarily as a result of Maryland customer migration to competitive suppliers.

The following table shows the percentages of DPL’s total distribution sales by jurisdictions that are derived from customers receiving Default Electricity Supply from DPL. Amounts are for the three months ended March 31:

	2011			2010
Sales to Delaware customers		55	%		56	%
Sales to Maryland customers		64	%		70	%

Natural Gas Operating Revenue

	2011		2010		Change
Regulated Gas Revenue	$	91	$	87	$	4
Other Gas Revenue		11		8		3
Total Natural Gas Operating Revenue	$	102	$	95	$	7

The table above shows the amounts of Natural Gas Operating Revenue from sources that are subject to price regulation (Regulated Gas Revenue) and those that generally are not subject to price regulation (Other Gas Revenue). Regulated Gas Revenue includes the revenue DPL receives from on-system natural gas delivered sales and the transportation of natural gas for customers within its service territory at regulated rates. Other Gas Revenue includes off-system natural gas sales and the short-term release of interstate pipeline transportation and storage capacity not needed to serve customers. Off-system sales are made possible when low demand for natural gas by regulated customers creates excess pipeline capacity.

Regulated Gas

	2011		2010		Change
Regulated Gas Revenue
Residential	$	57	$	55	$	2
Commercial and industrial		31		30		1
Transportation and other		3		2		1
Total Regulated Gas Revenue	$	91	$	87	$	4
	2011		2010		Change
Regulated Gas Sales (billion cubic feet)
Residential		4		4		—
Commercial and industrial		2		2		—
Transportation and other		3		2		1
Total Regulated Gas Sales		9		8		1

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	2011		2010		Change
Regulated Gas Customers (in thousands)
Residential		114		114		—
Commercial and industrial		10		9		1
Transportation and other		—		—		—
Total Regulated Gas Customers		124		123		1

Regulated Gas Revenue increased by $4 million primarily due to:

• An increase of $14 million due to higher sales as a result of colder weather.

• An increase of $1 million due to distribution rate increases effective August 2010 and February 2011.

The aggregate amount of these increases was partially offset by:

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

Other Gas Revenue

Other Gas Revenue increased by $3 million primarily due to higher volumes of revenue from off-system sales to electric generators and gas marketers.

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 $19 million to $182 million in 2011 from $201 million in 2010 primarily due to:

• A decrease of $16 million due to lower average electricity costs under Default Electricity Supply contracts.

• A decrease of $5 million primarily due to customer migration to competitive suppliers.

The aggregate amount of these decreases was partially offset by:

• An increase of $3 million in deferred electricity expense primarily due to lower average electricity costs under Default Electricity Supply contracts, which resulted in a higher rate of recovery of Default Electricity Supply costs.

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Gas Purchased

Gas Purchased consists of the cost of gas purchased by DPL to fulfill its obligation to regulated gas customers and, as such, is recoverable from customers in accordance with the terms of public service commission orders. It also includes the cost of gas purchased for off-system sales. Total Gas Purchased increased by $5 million to $71 million in 2011 from $66 million in 2010 primarily due to:

• An increase of $9 million in deferred gas expense as a result of a higher rate of recovery of natural gas supply costs.

• An increase of $3 million in the cost of gas purchases for off-system sales as a result of higher volumes purchased.

The aggregate amount of these increases was partially offset by:

• A decrease of $7 million in the cost of gas purchases for on-system sales as a result of lower average gas prices.

Other Operation and Maintenance

Other Operation and Maintenance increased by $4 million to $65 million in 2011 from $61 million in 2010 primarily due to:

• An increase of $3 million primarily due to higher tree trimming and corrective and preventative maintenance costs.

• An increase of $3 million in employee-related costs, primarily due to higher long-term disability and other benefit expenses.

The aggregate amount of these increases was partially offset by:

• A decrease of $2 million in emergency restoration costs primarily due to the February 2010 severe winter storms.

Depreciation and Amortization

Depreciation and Amortization expense increased by $2 million to $22 million in 2011 from $20 million in 2010 primarily due to:

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

• An increase of $1 million due to utility plant additions.

Income Tax Expense

DPL’s effective tax rates for the three months ended March 31, 2011 and 2010 were 42.5% and 48.2%, respectively. The decrease in the rate primarily resulted from a decrease in changes in estimates and interest related to uncertain and effectively settled tax positions, primarily related to a 2010 reversal of $2 million of accrued interest income on state income tax positions that DPL no longer believes is more likely than not to be realized.

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Capital Requirements

Capital Expenditures

DPL’s capital expenditures for the three months ended March 31, 2011, totaled $41 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.

In its Form 10-K for the year ended December 31, 2010, DPL presented the projected capital expenditures for the five-year period 2011 through 2015. There have been no changes in DPL’s projected capital expenditures from those presented in the Form 10-K, except with respect to the Mid-Atlantic Power Pathway (MAPP) project as discussed below.

DPL expects to incur significant capital expenditures in connection with the following primary initiatives:

Blueprint for the Future

DPL is participating in a PHI initiative referred to as “Blueprint for the Future,” which is designed to meet the challenges of rising energy costs, concerns about the environment, improved reliability and government energy reduction goals. 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 its 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 business customers to use more energy-efficient equipment, such as improved lighting, heating, ventilation and air-conditioning systems.

• The installation of advanced meters for electric customers and DPL’s natural gas customers as part of an Advanced Metering Infrastructure (AMI). Advanced meters allow DPL, among other capabilities, to remotely read meters, significantly reduce the use of 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 financial incentives through bill credits or 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:

• Advanced meters:

• DPL in Maryland: Final approval of the Maryland Public Service Commission (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 Delaware Public Service Commission (DPSC) approved implementation of AMI in September 2008, including cost recovery mechanisms. Implementation of advanced meters began in 2009 and is expected to be completed in 2011.

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• Direct load control programs:

• 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 was temporarily suspended by the MPSC pending resolution of a technical issue. This issue has been resolved and the stay on installations was lifted in March 2011.

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

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 MAPP, as part of PJM’s regional transmission expansion plan to address the reliability objectives of the PJM Regional Transmission Organization (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 152 miles in length originating at the Possum Point substation in Virginia and ending at the Indian River substation in Delaware. The cost of the MAPP project is currently estimated to be $1.2 billion and the planned in-service date is June 1, 2015.

PJM currently is in its annual process of evaluating the region’s overall transmission needs. The evaluation is expected to take into account changes in demand response, generation retirements and additions, as well as a revised load forecast for the PJM region that is lower than the load that was forecast in prior PJM studies. PJM has stated that it expects to complete this evaluation in August 2011. The outcome of the evaluation could result in a delay of the in-service date for all or a portion of the MAPP project beyond the currently planned in-service date of June 1, 2015.

The construction of MAPP requires various permits and approvals, including the approval of the MPSC. On April 27, 2011, DPL and its affiliate Potomac Electric Power Company, applicants in the filing pending before the MPSC seeking approval to build the MAPP project, requested a six-month delay to the procedural schedule to allow for the completion of the ongoing PJM review. The request is supported, or not opposed, by most of the parties to the case. The proposed revision to the schedule calls for direct testimony of the parties to be filed in December 2011 and evidentiary hearings to be held in March 2012.

Because the impact of the PJM review on the in-service date for MAPP will not be known until August 2011, DPL anticipates that $25 million to $31 million of the currently projected 2011 MAPP capital expenditures of $51 million will be deferred to later years.

MAPP/DOE Loan Program

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

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Forward-Looking Statements

Some of the statements contained in this Quarterly Report on Form 10-Q 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.

Any forward-looking statements speak only as to the date of this Quarterly Report on Form 10-Q 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

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unanticipated events. New factors emerge from time to time, and it is not possible for DPL to predict all 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.

141

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 H to the Form 10-Q, and accordingly information otherwise required under this Item has been omitted.

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.

Results Of Operations

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

Operating Revenue

	2011		2010		Change
Regulated T&D Electric Revenue	$	90	$	91	$	(1	)
Default Electricity Supply Revenue		221		223		(2	)
Other Electric Revenue		4		3		1
Total Operating Revenue	$	315	$	317	$	(2	)

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 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

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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

	2011		2010		Change
Regulated T&D Electric Revenue
Residential	$	38	$	39	$	(1	)
Commercial and industrial		28		29		(1	)
Other		24		23		1
Total Regulated T&D Electric Revenue	$	90	$	91	$	(1	)

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

	2011		2010		Change
Regulated T&D Electric Sales (Gigawatt hours (GWh))
Residential		1,078		1,097		(19	)
Commercial and industrial		1,177		1,174		3
Other		12		12		—
Total Regulated T&D Electric Sales		2,267		2,283		(16	)
	2011		2010		Change
Regulated T&D Electric Customers (in thousands)
Residential		482		482		—
Commercial and industrial		65		65		—
Other		1		1		—
Total Regulated T&D Electric Customers		548		548		—

Regulated T&D Electric Revenue decreased by $1 million primarily due to:

• A decrease of $6 million due to a New Jersey Societal Benefit Charge rate decrease that became effective in January 2011 (which is offset in Deferred Electric Service Costs).

The decrease was partially offset by:

• An increase of $5 million due to a distribution rate increase that became effective in June 2010.

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Default Electricity Supply

	2011		2010		Change
Default Electricity Supply Revenue
Residential	$	123	$	120	$	3
Commercial and industrial		61		55		6
Other		37		48		(11	)
Total Default Electricity Supply Revenue	$	221	$	223	$	(2	)

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.

	2011		2010		Change
Default Electricity Supply Sales (GWh)
Residential		977		1,097		(120	)
Commercial and industrial		384		513		(129	)
Other		10		12		(2	)
Total Default Electricity Supply Sales		1,371		1,622		(251	)
	2011		2010		Change
Default Electricity Supply Customers (in thousands)
Residential		443		482		(39	)
Commercial and industrial		53		61		(8	)
Other		—		1		(1	)
Total Default Electricity Supply Customers		496		544		(48	)

Default Electricity Supply Revenue decreased by $2 million primarily due to:

• A decrease of $21 million due to lower sales, primarily as a result of commercial and residential customer migration to competitive suppliers.

• A decrease of $8 million in wholesale energy and capacity resale revenues primarily due to the sale of lower volumes of electricity and capacity purchased from NUGs.

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

• A decrease of $3 million due to lower non-weather related average customer usage.

The aggregate amount of these decreases was partially offset by:

• An increase of $32 million as a result of higher Default Electricity Supply rates driven by a higher NUG charge which became effective January 1, 2011.

The decrease in total Default Electricity Supply Revenue includes an increase of $4 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 is not included in the deferral calculation, and therefore has an

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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 three months ended March 31, 2011, BGS unbilled revenue increased by $4 million as compared to the three months ended March 31, 2010, which resulted in a $3 million increase in ACE’s net income. The increase was primarily due to higher Default Electricity Supply rates during the unbilled revenue period at the end of the three months ended March 31, 2011 as compared to the corresponding period in 2010.

For the three months ended March 31, 2011 and 2010, the percentages of ACE’s total distribution sales that are derived from customers receiving Default Electricity Supply are 60% and 71%, respectively.

Operating Expenses

Purchased Energy

Purchased Energy consists of the cost of electricity purchased by ACE to fulfill its Default Electricity Supply obligation and, as such, is recoverable from customers in accordance with the terms of public service commission orders. Purchased Energy decreased by $37 million to $198 million in 2011 from $235 million in 2010 primarily due to commercial and residential customer migration to competitive suppliers.

Other Operation and Maintenance

Other Operation and Maintenance increased by $5 million to $55 million in 2011 from $50 million in 2010. Excluding an increase of $2 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 $3 million. The $3 million increase was primarily due to:

• An increase of $3 million primarily due to higher tree trimming and corrective and preventative maintenance costs.

• An increase of $2 million in employee-related costs, primarily due to higher accrued vacation and worker compensation adjustments.

• An increase of $1 million in costs related to customer requested work.

The aggregate amount of these increases was partially offset by:

• A decrease of $3 million in emergency restoration costs primarily due to the February 2010 severe winter storms.

Depreciation and Amortization

Depreciation and Amortization expenses increased by $9 million to $33 million in 2011, from $24 million in 2010 primarily due to:

• An increase of $7 million in amortization of stranded costs as the result of higher revenue due to rate increases effective October 2010 for the Transition Bond Charge and Market Transition Charge Tax (partially offset in Default Electricity Supply Revenue).

• An increase of $2 million due to utility plant additions.

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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 $16 million, to an expense reduction of $3 million in 2011 as compared to an expense reduction of $19 million in 2010, primarily due to an increase in deferred electricity expense as a result of higher Default Electricity Supply revenue rates and lower electricity supply costs.

Income Tax Expense

ACE’s consolidated effective tax rates for the three months ended March 31, 2011 and 2010 were 45.5% and 140.0%, respectively. The decrease in the rate resulted from changes in estimates and interest related to uncertain and effectively settled tax positions primarily related to the reversal of $6 million of erroneously accrued interest income on uncertain and effectively settled state income tax positions in 2010 and the impact of certain permanent state tax differences as a percentage of pre-tax book income.

Capital Requirements

Capital Expenditures

ACE’s capital expenditures for the three months ended March 31, 2011, totaled $22 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.

In its Form 10-K for the year ended December 31, 2010, ACE presented the projected capital expenditures for the five-year period 2011 through 2015.

ACE expects to incur significant capital expenditures in connection with the following primary initiatives:

Blueprint for the Future

ACE is participating in a PHI initiative referred to as “Blueprint for the Future,” which is designed to meet the challenges of rising energy costs, concerns about the environment, improved reliability and government energy reduction goals. 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 its 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 business customers to use more energy-efficient equipment, such as improved lighting, heating, ventilation and air-conditioning systems.

• The installation of advanced meters for electric customers as part of an Advanced Metering Infrastructure (AMI). Advanced meters allow ACE, among other capabilities, to remotely read meters, significantly reduce the use of estimated bills, improve outage management, and provide customers with more detailed information about their energy consumption.

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• 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 financial incentives through bill credits or 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:

• Advanced meters:

• The New Jersey Board of Public Utilities (NJBPU) is not expected to approve ACE’s proposal for implementation of advanced meters in the near term.

• Direct load control programs:

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

Stimulus Funds Related to Blueprint for the Future

During the three months ended March 31, 2011, ACE received $2 million in stimulus funds awarded by the United States Department of Energy (DOE) under the American Recovery and Reinvestment Act of 2009. Through March 31, 2011, ACE received $4 million of the $19 million that DOE has agreed to award the company to fund Blueprint for the Future and other capital expenditures and certain expenses associated with the implementation of direct load control, distribution automation and communication infrastructure in their respective service territories.

Forward-Looking Statements

Some of the statements contained in this Quarterly Report on Form 10-Q 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;

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• 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.

Any forward-looking statements speak only as to the date of this Quarterly Report on Form 10-Q 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 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.

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Item 3. 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,” and Note (15), “Derivative Instruments and Hedging Activities,” of the Consolidated Financial Statements of PHI included in its Annual Report on Form 10-K for the year ended December 31, 2010 and Item 7A “Quantitative and Qualitative Disclosures About Market Risk” of PHI’s Annual Report on Form 10-K for the year ended December 31, 2010.

Pepco Holdings, Inc.

Commodity Price Risk

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

PHI’s risk management policies place oversight at the senior management level through the 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. PHI also uses other measures to limit and monitor risk in its energy commodity activities, including limits on the nominal size of positions and periodic loss limits. VaR represents the potential fair value loss on energy contracts or portfolios due to changes in market prices for a specified time period and confidence level. PHI uses a delta-gamma VaR estimation model. The other parameters include a 95 percent, one-tailed confidence level and a one-day holding period. Since VaR is an estimate, it is not necessarily indicative of actual results that may occur.

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

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

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

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

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

Rating	Exposure Before Credit Collateral (b)		Credit Collateral (c)		Net Exposure		Number of Counterparties Greater Than 10% (d)		Net Exposure of Counterparties Greater Than 10%
Investment Grade (a)	$	2		—	$	2		1	$	1
Non-Investment Grade		6		—		6		—		—
No External Ratings		1		—		1		1		1
Credit reserves						—

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

(b) Exposure before credit collateral - includes the marked to market (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 gas reserves).

(d) Using a percentage of the total exposure.

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For additional information concerning market risk, please refer to Item 3, “Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk” and “Credit and Nonperformance Risk,” and for information regarding “Interest Rate Risk,” please refer to Item 7A, “Quantitative and Qualitative Disclosures About Market Risk,” in Pepco Holdings’ Annual Report on Form 10-K for the year ended December 31, 2010.

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

Item 4. 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 March 31, 2011, 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.

Changes in Internal Control Over Financial Reporting

During the three months ended March 31, 2011, 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.

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 March 31, 2011, 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.

Changes in Internal Control Over Financial Reporting

During the three months ended March 31, 2011, 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.

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

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disclosure controls and procedures as of March 31, 2011, 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.

Changes in Internal Control Over Financial Reporting

During the three months ended March 31, 2011, 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 March 31, 2011, 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 subsidiaries that is required to be disclosed in reports filed with, or submitted to, the SEC under the Exchange Act (i) is recorded, processed, summarized and reported within the time periods specified by the SEC rules and forms and (ii) is accumulated and communicated to management, including its chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

During the three months ended March 31, 2011, 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.

Part II OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

Pepco Holdings

Other than ordinary routine litigation incidental to its and its subsidiaries’ business, PHI is not a party to, and its subsidiaries’ property is not subject to, any material pending legal proceedings except as described in Note (15), “Commitments and Contingencies—Legal Proceedings,” to the Consolidated Financial Statements of PHI included herein.

Pepco

Other than ordinary routine 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 (10), “Commitments and Contingencies—Legal Proceedings,” to the Financial Statements of Pepco included herein.

DPL

Other than ordinary routine 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 (12), “Commitments and Contingencies—Legal Proceedings,” to the Financial Statements of DPL included herein.

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ACE

Other than ordinary routine 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 (11), “Commitments and Contingencies—Legal Proceedings,” to the Consolidated Financial Statements of ACE included herein.

Item 1A. RISK FACTORS

Pepco Holdings

For a discussion of the risk factors applicable to Pepco Holdings, Pepco, DPL and ACE, please refer to Item 1A “Risk Factors” in Pepco Holdings’ Annual Report on Form 10-K for the year ended December 31, 2010. There have been no material changes to Pepco Holdings’ risk factors as disclosed in the 10-K, except that each of the following risk factors supersedes the risk factor with the same heading in the Form 10-K. Except as otherwise noted, each risk factor set forth below applies to each of Pepco Holdings, Pepco, DPL and ACE.

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. In this regard, in April 2011, Maryland adopted legislation under which electric utilities operating in Maryland, including Pepco and DPL, could be subject to fines for failure to meet minimum service quality and reliability standards to be developed by the MPSC.

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.

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.

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The Energy Services business of Pepco Energy Services is highly competitive. Under its energy savings performance contracts, Pepco Energy Services may be liable for performance guarantees many years after an installation of a project is completed. (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.

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

Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Pepco Holdings

None.

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

Item 3. DEFAULTS UPON SENIOR SECURITIES

Pepco Holdings

None.

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

Item 4. RESERVED

Item 5. OTHER INFORMATION

Pepco Holdings

None.

Pepco

None.

DPL

None.

ACE

None.

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Item 6. EXHIBITS

The documents listed below are being filed, furnished or submitted on behalf of Pepco Holdings, Inc. (PHI), Potomac Electric Power Company (Pepco), Delmarva Power & Light Company (DPL), and Atlantic City Electric Company (ACE).

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
4	ACE	Indenture Supplemental to Mortgage and Deed of Trust, dated as of March 29, 2011	Exhibit 4.2 to ACE’s Form 8-K, 4/1/2010
12.1	PHI	Statements Re: Computation of Ratios	Filed herewith.
12.2	Pepco	Statements Re: Computation of Ratios	Filed herewith.
12.3	DPL	Statements Re: Computation of Ratios	Filed herewith.
12.4	ACE	Statements Re: Computation of Ratios	Filed herewith.
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.
32.1	PHI	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	Furnished herewith.
32.2	Pepco	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	Furnished herewith.
32.3	DPL	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	Furnished herewith.
32.4	ACE	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	Furnished 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.

155

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. (PHI) POTOMAC ELECTRIC POWER COMPANY (Pepco) DELMARVA POWER & LIGHT COMPANY (DPL) ATLANTIC CITY ELECTRIC COMPANY (ACE)         (Registrants)
May 6, 2011	By	/s/ A.J. KAMERICK
		Anthony J. Kamerick
		Senior Vice President and Chief Financial Officer, PHI, Pepco and DPL Chief Financial Officer, ACE

156

INDEX TO EXHIBITS FILED HEREWITH

Exhibit No.	Registrant(s)	Description of Exhibit
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
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
101.INS	PHI, Pepco, DPL, ACE	XBRL Instance Document
101.SCH	PHI, Pepco, DPL, ACE	XBRL Taxonomy Extension Schema Document
101.CAL	PHI, Pepco, DPL, ACE	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	PHI, Pepco, DPL, ACE	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	PHI, Pepco, DPL, ACE	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	PHI, Pepco, DPL, ACE	XBRL Taxonomy Extension Presentation Linkbase Document