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, 2009

Commission File Number	Name of Registrant, State of Incorporation, Address of Principal Executive Offices, and Telephone Number	I.R.S. Employer Identification Number
001-31403	PEPCO HOLDINGS, INC. (Pepco Holdings or PHI), a Delaware corporation 701 Ninth Street, N.W. Washington, D.C. 20068 Telephone: (202)872-2000	52-2297449
001-01072	POTOMAC ELECTRIC POWER COMPANY (Pepco), a District of Columbia and Virginia corporation 701 Ninth Street, N.W. Washington, D.C. 20068 Telephone: (202)872-2000	53-0127880
001-01405	DELMARVA POWER & LIGHT COMPANY (DPL), a Delaware and Virginia corporation 800 King Street, P.O. Box 231 Wilmington, Delaware 19899 Telephone: (202)872-2000	51-0084283
001-03559	ATLANTIC CITY ELECTRIC COMPANY (ACE), a New Jersey corporation 800 King Street, P.O. Box 231 Wilmington, Delaware 19899 Telephone: (202)872-2000	21-0398280

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  ¨	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, 2009
Pepco Holdings	219,990,152 ($.01 par value)
Pepco	100 ($.01 par value) (a)
DPL	1,000 ($2.25 par value) (b)
ACE	8,546,017 ($3 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	104
Item 3.	- Quantitative and Qualitative Disclosures About Market Risk	160
Item 4.	- Controls and Procedures	163
Item 4T.	- Controls and Procedures	163
PART II	OTHER INFORMATION	165
Item 1.	- Legal Proceedings	165
Item 1A.	- Risk Factors	165
Item 2.	- Unregistered Sales of Equity Securities and Use of Proceeds	171
Item 3.	- Defaults Upon Senior Securities	171
Item 4.	- Submission of Matters to a Vote of Security Holders	171
Item 5.	- Other Information	171
Item 6.	- Exhibits	172
Signatures		173

GLOSSARY OF TERMS

Term	Definition
ACE	Atlantic City Electric Company
ACE Funding	Atlantic City Electric Transition Funding LLC
ADITC	Accumulated deferred investment tax credits
Ancillary services	Generally, electricity generation reserves and reliability services
APB	Accounting Principles Board
AOCL	Accumulated other comprehensive (losses) earnings
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)
BSA	Bill Stabilization Adjustment
CERCLA	Comprehensive Environmental Response, Compensation, and Liability Act of 1980
Citgo	Citgo Asphalt Refining Company
Conectiv	A wholly owned subsidiary of PHI and the parent of DPL and ACE
Competitive Energy	Competitive energy generation, marketing and supply
Conectiv Energy	Conectiv Energy Holding Company and its subsidiaries
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
DC OPC	District of Columbia Office of People’s Counsel
DCPSC	District of Columbia Public Service Commission
Default Electricity Supply	The supply of electricity by PHI’s electric utility subsidiaries at regulated rates to retail customers who do not elect to purchase electricity from a competitive supplier, and which, depending on the jurisdiction, is also known as SOS or BGS service
Default Supply Revenue	Revenue received for Default Electricity Supply
Delaware District Court	United States District Court for the District of Delaware
DPL	Delmarva Power & Light Company
DPSC	Delaware Public Service Commission
EBITDA	Earnings before interest, taxes, depreciation, and amortization
EDIT	Excess Deferred Income Taxes
EITF	Emerging Issues Task Force
EPA	U.S. Environmental Protection Agency
EPS	Earnings per share
EQR	Conectiv Energy’s Electric Quarterly Report filed with FERC
ERISA	Employee Retirement Income Security Act of 1974
Exchange Act	Securities Exchange Act of 1934, as amended
FAS	Financial Accounting Standards
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission

i

Term	Definition
FHACA	Flood Hazard Area Control Act
FIN	FASB Interpretation Number
FSP	FASB Staff Position
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
ISONE	Independent System Operator - New England
MAPP	Mid-Atlantic Power Pathway
Maryland OPC	Maryland Office of People’s Counsel
MDC	MDC Industries, Inc.
MFVRD	Modified fixed variable rate design
Mirant	Mirant Corporation
MSCG	Morgan Stanley Capital Group, Inc.
MPSC	Maryland Public Service Commission
New Jersey Societal Benefit Charge	Revenue ACE receives to recover certain costs incurred under various NJBPU - mandated social programs
NFA	No Further Action letter issued by the NJDEP
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
NYDEC	New York Department of Environmental Conservation
OTTI	Other-than-temporary impairment
Panda	Panda-Brandywine, L.P.
Panda PPA	PPA between Pepco and Panda
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 Parties	The PHI Retirement Plan, PHI and Conectiv, parties to cash balance plan litigation brought by three management employees of PHI Service Company
PHI Retirement Plan	PHI’s noncontributory retirement plan
PJM	PJM Interconnection, LLC
PJM RTO	PJM Regional Transmission Organization

ii

Term	Definition
Power Delivery	PHI’s Power Delivery Business
PPA	Power Purchase Agreement
PRP	Potentially responsible party
PUHCA 2005	Public Utility Holding Company Act of 2005, which became effective February 8, 2006
RECs	Renewable energy credits
RAR	IRS revenue agent’s report
RC Cape May	RC Cape May Holdings, LLC, an affiliate of Rockland Capital Energy Investments, LLC, and the purchaser of the B.L. England generating facility
Regulated T&D Electric Revenue	Revenue from the transmission and the delivery of electricity to PHI’s customers within its service territories at regulated rates
ROE	Return on equity
SEC	Securities and Exchange Commission
Sempra	Sempra Energy Trading LLC
SFAS	Statement of Financial Accounting Standards
SOS	Standard Offer Service (the supply of electricity by Pepco in the District of Columbia, by Pepco and DPL in Maryland and by DPL in Delaware to retail customers who have not elected to purchase electricity from a competitive supplier)
Spot	Commodities market in which goods are sold for cash and delivered immediately
Standard Offer Service revenue or SOS revenue	Revenue Pepco and DPL, respectively, receive for the procurement of energy for its SOS customers
Transition Bonds	Transition bonds issued by ACE Funding
TSA	Contract for terminal services between ACE and Citgo
VaR	Value at Risk

iii

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 Earnings	2	51	69	90
Consolidated Statements of Comprehensive Earnings	3	N/A	N/A	N/A
Consolidated Balance Sheets	4	52	70	91
Consolidated Statements of Cash Flows	6	54	72	93
Notes to Consolidated Financial Statements	7	55	73	94

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

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PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EARNINGS

(Unaudited)

	Three Months Ended March 31,
	2009			2008
	(in millions, except per share data)
Operating Revenue
Power Delivery	$	1,372		$	1,295
Competitive Energy		1,139			1,328
Other		9			18
Total Operating Revenue		2,520			2,641
Operating Expenses
Fuel and purchased energy		1,887			1,818
Other services cost of sales		96			180
Other operation and maintenance		236			219
Depreciation and amortization		96			91
Other taxes		91			88
Deferred electric service costs		(27	)		25
Effect of settlement of Mirant bankruptcy claims		(14	)		—
Gain on sale of assets		—			(3	)
Total Operating Expenses		2,365			2,418
Operating Income		155			223
Other Income (Expenses)
Interest and dividend income		1			7
Interest expense		(90	)		(81	)
Loss from equity investments		(1	)		(2	)
Other income		4			6
Other expenses		—			(1	)
Total Other Expenses		(86	)		(71	)
Income Before Income Tax Expense		69			152
Income Tax Expense		24			53
Net Income		45			99
Retained Earnings at Beginning of Period		1,271			1,193
Dividends Paid on Common Stock (Note 15)		(59	)		(54	)
Retained Earnings at End of Period	$	1,257		$	1,238
Basic and Diluted Share Information
Weighted average shares outstanding		219			201
Earnings per share of common stock	$	.21		$	.49

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

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PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSSES) EARNINGS

(Unaudited)

	Three Months Ended March 31,
	2009			2008
	(millions of dollars)
Net income	$	45		$	99
Other comprehensive (losses) earnings
(Losses) gains on commodity derivatives designated as cash flow hedges:
(Losses) gains arising during period		(256	)		212
Less: amount of (losses) gains reclassified into earnings		(104	)		15
Net (losses) gains on commodity derivatives		(152	)		197
Amortization of deferred hedging gains on terminated Treasury Rate Locks		1			2
Other comprehensive (losses) earnings, before taxes		(151	)		199
Income tax (benefit) expense		(62	)		79
Other comprehensive (losses) earnings, net of income taxes		(89	)		120
Comprehensive (losses) earnings	$	(44	)	$	219

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

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PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31, 2009			December 31, 2008
	(millions of dollars)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	580		$	384
Restricted cash equivalents		10			10
Accounts receivable, less allowance for uncollectible accounts of $41 million and $37 million, respectively		1,338			1,392
Inventories		273			333
Derivative assets		119			98
Prepayments of income taxes		192			294
Prepaid expenses and other		129			115
Total Current Assets		2,641			2,626
INVESTMENTS AND OTHER ASSETS
Goodwill		1,411			1,411
Regulatory assets		2,034			2,088
Investment in finance leases held in trust		1,349			1,335
Income taxes receivable		276			191
Restricted cash equivalents		68			108
Assets and accrued interest related to uncertain tax positions		143			178
Derivative assets		29			9
Other		207			215
Total Investments and Other Assets		5,517			5,535
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		13,098			12,926
Accumulated depreciation		(4,671	)		(4,612	)
Net Property, Plant and Equipment		8,427			8,314
TOTAL ASSETS	$	16,585		$	16,475

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

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PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31, 2009			December 31, 2008
	(millions of dollars, except shares)
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Short-term debt	$	705		$	465
Current maturities of long-term debt and project funding		51			85
Accounts payable and accrued liabilities		748			847
Capital lease obligations due within one year		6			6
Taxes accrued		87			62
Interest accrued		96			71
Liabilities and accrued interest related to uncertain tax positions		4			71
Derivative liabilities		166			144
Other		316			279
Total Current Liabilities		2,179			2,030
DEFERRED CREDITS
Regulatory liabilities		866			893
Deferred income taxes, net		2,242			2,269
Investment tax credits		39			40
Pension benefit obligation		633			626
Other postretirement benefit obligations		464			461
Income taxes payable		185			176
Liabilities and accrued interest related to uncertain tax positions		164			163
Derivative liabilities		97			59
Other		148			184
Total Deferred Credits		4,838			4,871
LONG-TERM LIABILITIES
Long-term debt		4,952			4,859
Transition bonds issued by ACE Funding		393			401
Long-term project funding		18			19
Capital lease obligations		99			99
Total Long-Term Liabilities		5,462			5,378
COMMITMENTS AND CONTINGENCIES (NOTE 15)
EQUITY
Common stock, $.01 par value, authorized 400,000,000 shares, 219,990,152 shares and 218,906,220 shares outstanding, respectively		2			2
Premium on stock and other capital contributions		3,192			3,179
Accumulated other comprehensive loss		(351	)		(262	)
Retained earnings		1,257			1,271
Total Shareholders’ Equity		4,100			4,190
Noncontrolling interest		6			6
Total Equity		4,106			4,196
TOTAL LIABILITIES AND EQUITY	$	16,585		$	16,475

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

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PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
	2009			2008
	(millions of dollars)
OPERATING ACTIVITIES
Net income	$	45		$	99
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		96			91
Gain on sale of assets		—			(3	)
Effect of settlement of Mirant bankruptcy claims		(14	)		—
Rents received from leveraged leases under income earned		(14	)		(19	)
Changes in restricted cash equivalents related to Mirant settlement		38			—
Deferred income taxes		39			65
Net unrealized losses (gains) on commodity derivatives accounted for at fair value		40			(28	)
Changes in:
Accounts receivable		147			(24	)
Inventories		28			21
Prepaid expenses		(27	)		9
Regulatory assets and liabilities		22			33
Accounts payable and accrued liabilities		(144	)		3
Cash collateral related to derivative activities		(258	)		118
Taxes accrued		96			(14	)
Interest accrued		25			10
Other changes in working capital		—			(3	)
Net other operating activities		7			(11	)
Net Cash From Operating Activities		126			347
INVESTING ACTIVITIES
Investment in property, plant and equipment		(180	)		(171	)
Proceeds from sale of assets		—			51
Changes in restricted cash equivalents		—			(14	)
Net other investing activities		—			2
Net Cash Used By Investing Activities		(180	)		(132	)
FINANCING ACTIVITIES
Dividends paid on common stock		(59	)		(54	)
Common stock issued for the Dividend Reinvestment Plan		7			7
Issuances of common stock		8			12
Issuances of long-term debt		110			400
Reacquisition of long-term debt		(58	)		(183	)
Issuances (repayments) of short-term debt, net		240			(102	)
Net other financing activities		2			(34	)
Net Cash From Financing Activities		250			46
Net Increase in Cash and Cash Equivalents		196			261
Cash and Cash Equivalents at Beginning of Period		384			55
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	580		$	316
NONCASH ACTIVITIES
Asset retirement obligations associated with removal costs transferred to (from) regulatory liabilities	$	4		$	(3	)
Recoverable pension/OPEB costs included in regulatory assets	$	(15	)	$	(4	)
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash received for income taxes, net	$	(98	)	$	(2	)

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

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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 diversified energy company that, through its operating subsidiaries, is engaged primarily in two businesses:

• the distribution, transmission and default supply of electricity and the delivery and supply of natural gas (Power Delivery), conducted through the following regulated public utility companies, each of which is a reporting company under the Securities Exchange Act of 1934, as amended:

• 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.

• competitive energy generation, marketing and supply (Competitive Energy) conducted through subsidiaries of Conectiv Energy Holding Company (collectively Conectiv Energy) and Pepco Energy Services, Inc. and its subsidiaries (collectively, Pepco Energy Services).

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.

The following is a description of each of PHI’s two principal business operations:

Power Delivery

The largest component of PHI’s business is 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 either as transmission or distribution facilities. 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. Together the three companies constitute a single segment for financial reporting purposes.

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PEPCO HOLDINGS

Each company is responsible for the delivery 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 varies by jurisdiction as follows:

Delaware	Standard Offer Service (SOS)
District of Columbia	SOS
Maryland	SOS
New Jersey	Basic Generation Service (BGS)

In this Form 10-Q, these supply services are referred to generally as Default Electricity Supply.

Competitive Energy

The Competitive Energy business provides competitive generation, marketing and supply of electricity and gas, and related energy management services, primarily in the mid-Atlantic region. PHI’s Competitive Energy operations are conducted through Conectiv Energy and Pepco Energy Services, each of which is treated as a separate operating segment for financial reporting purposes.

Over the past several months, PHI has been conducting a strategic analysis of the retail energy supply business of Pepco Energy Services including an evaluation of potential alternative supply arrangements to reduce collateral requirements and a possible restructuring, sale or wind down of the business. Among the factors being considered in this analysis is the return PHI earns by investing capital in the retail energy supply business as compared to alternative investments. PHI expects the retail energy supply business to remain profitable based on its existing contract backlog and the variability of margins has been reduced by entering into corresponding wholesale energy purchase contracts. With the increased cost of capital associated with its collateral obligations factored into its retail pricing, Pepco Energy Services is experiencing reduced retail customer retention levels and reduced levels of new retail customer acquisitions. In March 2009, Pepco Energy Services entered into a credit intermediation arrangement with an investment banking firm, which is more fully described in Note (9), “Debt,” under the heading “Impact of the Recent Capital and Credit Market Disruptions – Collateral Requirements of the Competitive Energy Businesses.” The arrangement eliminates the collateral requirements with respect to a portion of Pepco Energy Services’ wholesale electricity supply contracts. PHI is continuing to evaluate other alternatives.

Other Business Operations

Through its subsidiary Potomac Capital Investment Corporation (PCI), PHI maintains a portfolio of cross-border energy sale-leaseback transactions, with a book value at March 31, 2009 of approximately $1.3 billion. This activity constitutes a fourth operating segment, for financial reporting purposes, which is designated as “Other Non-Regulated.”

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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, 2008. 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, 2009, in accordance with GAAP. The year-end balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP. Interim results for the three months ended March 31, 2009 may not be indicative of PHI’s results that will be realized for the full year ending December 31, 2009, since its Power Delivery and Competitive Energy businesses are seasonal.

Consolidation of Variable Interest Entities

In accordance with the provisions of Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46(R), “Consolidation of Variable Interest Entities” (FIN 46(R)), Pepco Holdings consolidates those variable interest entities where Pepco Holdings or a subsidiary has been determined to be the primary beneficiary. FIN 46(R) addresses conditions under which an entity should be consolidated based upon variable interests rather than voting interests. Subsidiaries of Pepco Holdings have power purchase agreements (PPAs) with a number of entities to which FIN 46(R) applies.

Pepco and ACE PPAs

Pepco Holdings, through its ACE subsidiary, is a party to three PPAs with unaffiliated, non-utility generators (NUGs). Due to a variable element in the pricing structure of the NUGs, Pepco Holdings potentially assumes the variability in the operations of the plants related to the NUGs and, therefore, has a variable interest in the counterparties. Despite continued efforts to obtain information from these three entities during the three months ended March 31, 2009, PHI was unable to obtain sufficient information to conduct the analysis required under FIN 46(R) to determine whether these three entities were variable interest entities or if the Pepco Holdings subsidiaries were the primary beneficiary. As a result, Pepco Holdings has applied the scope exemption from the application of FIN 46(R) 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, 2009 and 2008, were approximately $83 million and $88 million, respectively, of which approximately $72 million and $76 million, respectively, related to power purchases under the NUGs. Pepco Holdings does not have loss exposure under the NUGs because cost recovery will be achieved from ACE’s customers through regulated rates.

During the third quarter of 2008, Pepco transferred to Sempra Energy Trading LLP (Sempra) an agreement with Panda-Brandywine, L.P. (Panda) under which Pepco was obligated

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PEPCO HOLDINGS

to purchase from Panda 230 megawatts of capacity and energy annually through 2021 (Panda PPA). Net purchase activities under the Panda PPA for the three months ended March 31, 2008, were approximately $20 million.

DPL Onshore Wind Transactions

In 2008, PHI, through its DPL subsidiary, entered into three onshore wind PPAs. Under the contracts, DPL receives renewable energy credits (RECs) to help serve a portion of its requirements under the State of Delaware’s Renewable Energy Portfolio Standards Act, which requires that 20 percent of total load needed in Delaware be produced from renewable sources by 2019. The Delaware Public Service Commission (DPSC) has approved all three agreements, and payments under the agreements currently are expected to start in late 2009 for one contract and 2010 for the remaining two contracts.

DPL has exclusive rights to the energy and RECs in amounts up to a total between 120 and 150 megawatts. The lengths of the contracts range between 15 and 20 years. DPL is only obligated to purchase energy and RECs in amounts generated and delivered by the sellers at rates that are primarily fixed. Recent disruptions in the capital and credit markets could result in delays in the start dates for these PPAs. If the PPAs are not initiated by the specified dates, DPL has the right to terminate the PPAs. DPL’s exposure to loss under the PPAs is the extent to which the market prices for energy and RECs fall below the contractual purchase price.

DPL has concluded that two of the PPAs are leases in accordance with the guidance in Emerging Issues Task Force (EITF) Issue No. 01-8, “Determining Whether an Arrangement Contains a Lease” (EITF 01-8), but that DPL did not own the assets under the lease during construction in accordance with EITF Issue No. 97-10, “The Effect of Lessee Involvement in Asset Construction.” DPL concluded that consolidation is not required for any of these PPAs under FIN 46(R).

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 was allocated to Pepco Holdings’ Power Delivery reporting unit based on the aggregation of its components. Pepco Holdings tests its goodwill for impairment annually as of July 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 protracted decline in stock price causing market capitalization to fall below book value; an adverse regulatory action; or an impairment of long-lived assets in the reporting unit. PHI performed its annual impairment test as of July 1, 2008 and interim impairment tests as of December 31, 2008 and March 31, 2009. As described in Note (6), “Goodwill,” no impairment charge has been required to be recorded.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in Pepco Holdings’ gross revenues were $78 million and $74 million for the three months ended March 31, 2009 and 2008, respectively.

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Reclassifications and Adjustments

Certain prior period amounts have been reclassified in order to conform to current period presentation.

Gas Cost Rate Revenue

During the first quarter of 2009, DPL recorded additional revenue of $8 million related to the unbilled portion of the Gas Cost Rate (GCR) revenue, which was not previously recognized. Because the GCR revenue is deferred, an additional expense of $8 million has also been recorded in the first quarter of 2009. Consequently, there is no impact on consolidated net earnings as a result of this adjustment.

Income Tax Adjustments

During the first quarter of 2009, ACE recorded adjustments to correct certain income tax errors related to prior periods. The adjustments, which are not considered material, resulted in a decrease in income tax expense of $1 million for the quarter ended March 31, 2009.

(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Statement of Financial Accounting Standards (SFAS) No. 141(R), “Business Combinations—a Replacement of FASB Statement No. 141” (SFAS No. 141 (R))

SFAS No. 141(R) replaces FASB Statement No. 141, “Business Combinations,” and retains the fundamental requirements that the acquisition method of accounting be used for all business combinations and for an acquirer to be identified for each business combination. However, SFAS No. 141(R) expands the definition of a business and amends FASB Statement No. 109, “Accounting for Income Taxes,” to require the acquirer to recognize changes in the amount of its deferred tax benefits that are realizable because of a business combination either in income from continuing operations or directly in contributed capital, depending on the circumstances.

On April 1, 2009, the FASB issued FASB Staff Position (FSP) Financial Accounting Standards (FAS) 141(R)-1, “Accounting for Assets and Liabilities Assumed in a Business Combination that Arise from Contingencies” (FSP FAS 141(R)-1), to clarify the accounting for the initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. FSP FAS 141(R)-1 requires that assets acquired and liabilities assumed in a business combination that arise from contingencies be measured at fair value if the acquisition date fair value of that asset and liability can be determined during the measurement period in accordance with SFAS No. 157. If the acquisition date fair value cannot be determined, then the asset or liability would be measured in accordance with SFAS No. 5, “Accounting for Contingencies,” and FIN 14, “Reasonable Estimate of the Amount of Loss.”

SFAS No. 141(R) and the guidance provided in FSP FAS 141(R)-1 applies prospectively to business combinations for which the acquisition date is on or after January 1, 2009. PHI adopted SFAS No. 141(R) on January 1, 2009, and it did not have a material impact on PHI’s overall financial condition, results of operations, or cash flows.

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FSP 157-2, “Effective Date of FASB Statement No. 157” (FSP 157-2)

FSP 157-2 deferred the effective date of SFAS No. 157, “Fair Value Measurements,” for all nonrecurring fair value measurements of non-financial assets and non-financial liabilities until January 1, 2009 for PHI. The adoption of SFAS No. 157 did not have a material impact on the fair value measurements of PHI’s non-financial assets and non-financial liabilities.

SFAS No. 160, “Non-controlling Interests in Consolidated Financial Statements—an Amendment of ARB No. 51” (SFAS No. 160)

SFAS No. 160 establishes new accounting and reporting standards for a non-controlling interest (previously called minority interest) in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a non-controlling interest in a subsidiary is an ownership interest in the consolidated entity that should be separately reported in the consolidated financial statements.

SFAS No. 160 establishes accounting and reporting standards that require (i) the ownership interests and the related consolidated net income in subsidiaries held by parties other than the parent be clearly identified, labeled, and presented in the consolidated balance sheets within equity, but separate from the parent’s equity, and presented separately on the face of the consolidated statement of earnings, (ii) the changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for as equity transactions, and (iii) when a subsidiary is deconsolidated, any retained non-controlling equity investment in the former subsidiary must be initially measured at fair value.

SFAS No. 160 was effective prospectively for financial statement reporting periods beginning January 1, 2009 for PHI, except for the financial statement presentation and disclosure requirements which also apply to prior reporting periods presented. As of January 1, 2009, PHI has adopted the provisions of SFAS No. 160, and reclassified $6 million of non-controlling interests from the minority interest line item of its balance sheet to a component of equity. Otherwise, SFAS No. 160 did not have a material impact on PHI’s overall financial condition, results of operations, or cash flows.

SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities—an Amendment of FASB Statement No. 133” (SFAS No. 161)

SFAS No. 161 enhances the disclosure requirements for derivative instruments and hedging activities. Some of the new disclosures include derivative objectives and strategies, derivative volumes by product type, location and gross fair values of derivative assets and liabilities, location and amounts of gains and losses on derivatives and related hedged items, and credit-risk-related contingent features in derivatives.

SFAS No. 161 was effective for financial statement reporting periods beginning January 1, 2009 for PHI. SFAS No. 161 encourages but does not require disclosures for earlier periods presented for comparative purposes at initial adoption. PHI has adopted the provisions of SFAS No. 161 with comparative disclosures within Note (13), “Derivative Instruments and Hedging Activities.”

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EITF Issue No. 03-6-1, “Determining whether Instruments Granted in Share-Based Payment Transactions are Participating Securities” (FSP EITF 03-6-1)

In June 2008, the FASB issued FSP EITF 03-6-1, which addresses when unvested instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation in computing earnings per share (EPS) under the two-class method described in SFAS No. 128, “Earnings per Share.”

FSP EITF 03-6-1 was effective for financial reporting periods beginning January 1, 2009 for PHI. All prior period earnings per share data presented must be adjusted retrospectively to conform with the provisions of FSP EITF 03-6-1. As of January 1, 2009, PHI has adopted the provisions of FSP EITF 03-6-1 in the presentation of earnings per share data for the first quarter of 2009 and the first quarter of 2008 in the consolidated statements of earnings and Note (12), “Earnings Per Share.” The adoption did not result in a change to previously reported EPS for the first quarter of 2008.

EITF Issue No. 08-5, “Issuer’s Accounting for Liabilities Measured at Fair Value with a Third Party Credit Enhancement” (EITF 08-5)

In September 2008, the FASB issued EITF 08-5 to provide guidelines for the determination of the unit of accounting for a liability issued with an inseparable third-party credit enhancement when it is measured or disclosed at fair value on a recurring basis. EITF 08-5 applies to entities that incur liabilities with inseparable third-party credit enhancements or guarantees that are recognized or disclosed at fair value. This would include guaranteed debt obligations, derivatives, and other instruments that are guaranteed by third parties.

The effect of the credit enhancement may not be included in the fair value measurement of the liability, even if the liability is an inseparable third-party credit enhancement. The issuer is required to disclose the existence of the inseparable third-party credit enhancement on the issued liability.

EITF 08-5 was effective on a prospective basis for reporting periods beginning on and after January 1, 2009 for PHI. As of January 1, 2009, PHI has adopted the provisions of EITF 08-5, and it did not have a material impact on PHI’s overall financial condition, results of operations, or cash flows.

EITF Issue No. 08-6, “Equity Method Investment Accounting Consideration” (EITF 08-6)

In November 2008, the FASB issued EITF 08-6 to address the accounting for equity method investments including: (i) how an equity method investment should initially be measured, (ii) how it should be tested for impairment, and (iii) how an equity method investee’s issuance of shares should be accounted for. The EITF provides that the initial carrying value of an equity method investment can be determined using the accumulation model in SFAS 141(R), and other-than-temporary impairments should be recognized in accordance with paragraph 19(h) of Accounting Principles Board Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.”

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This EITF was effective for PHI beginning January 1, 2009. As of January 1, 2009, PHI has adopted the provisions of EITF 08-6, and it did not have a material impact on PHI’s overall financial condition, results of operations, or cash flows in the first quarter.

(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

FSP FAS 107-1 and Accounting Principles Board (APB) 28-1, “Interim Disclosures about Fair Value of Financial Instruments” (FSP FAS 107-1 and APB 28-1)

On April 9, 2009, the FASB issued FSP FAS 107-1 and APB 28-1, which requires quarterly disclosures of the fair value of financial instruments beginning with the second quarter of 2009. Prior to FSP FAS 107-1 and APB 28-1, these disclosures were only required on an annual basis. The disclosures for prior reporting periods are required after initial adoption.

FSP FAS 107-1 and APB 28-1 are effective for interim reporting periods ending after June 15, 2009 with the option to early adopt for interim periods ending after March 15, 2009. PHI elected not to early adopt; therefore, the disclosure requirements will be reflected in PHI’s second quarter 2009 Form 10-Q. The primary impact of the new standard will be the quarterly disclosure of the fair value of debt issued by PHI and its utilities.

FSP FAS 157-4, “Determining Whether a Market is Not Active and a Transaction is Not Distressed” (FSP FAS 157-4)

On April 9, 2009, the FASB issued FSP FAS 157-4, which outlines a two-step test to identify inactive and distressed markets and provides a fair value application example for financial instruments when both conditions are met. The FSP is designed to improve application of fair value in illiquid or inactive markets.

FSP FAS 157-4 is effective for interim reporting periods ending after June 15, 2009 with the option to early adopt for interim periods ending after March 15, 2009. PHI did not elect to early adopt. The new requirement would affect PHI’s valuation of derivative instruments if they are valued using information from inactive and distressed markets. PHI is currently evaluating whether FSP 157-4 will have a material impact on PHI’s overall financial condition, results of operations, or cash flows.

FSP FAS 115-2 and FAS 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments” (FSP FAS 115-2 and FAS 124-2)

On April 9, 2009, the FASB issued FSP FAS 115-2 and FAS 124-2, which provided additional guidance on other-than-temporary impairment (OTTI) of debt and equity securities. It requires disclosure of information about the credit and noncredit component of an OTTI event and when an OTTI event has occurred. The FSP requires separate display on the statements of earnings, of losses related to credit deterioration and losses related to other market factors. Market-related losses will be recorded in accumulated other comprehensive (losses) earnings if it is not likely that the investor will have to sell the security prior to recovery.

FSP 115-2 and FAS 124-2 are effective for interim reporting periods ending after June 15, 2009, with the option to early adopt for interim periods ending after March 15, 2009. PHI elected not to early adopt. PHI does not anticipate the adoption of FSP 115-2 and FAS 124-2 to have a material impact on PHI’s overall financial condition, results of operations, or cash flows.

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FSP FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets” (FSP FAS 132(R)-1)

In December 2008, the FASB issued FSP FAS 132(R)-1 to provide guidance on an employer’s disclosures about plan assets of a defined benefit pension or other postretirement plan. The required disclosures under this FSP would expand current disclosures under SFAS No. 132(R), “Employers’ Disclosures about Pensions and Other Postretirement Benefits—an amendment of FASB Statements No. 87, 88, and 106,” to be in line with SFAS No. 157 required disclosures.

The disclosures are to provide users an understanding of: (i) the investment allocation decisions made, (ii) factors used in the investment policies and strategies, (iii) plan assets by major investment types, (iv) inputs and valuation techniques used to measure fair value of plan assets, (v) significant concentration of risk within the plan, and (vi) the effects of fair value measurement using significant unobservable inputs (Level 3 as defined in SFAS No. 157) on changes in the value of plan assets for the period.

The new disclosures are required starting with financial statement reporting periods ending December 31, 2009 for PHI, with earlier application permitted. Comparative disclosures under this provision are not required for earlier periods presented. PHI is evaluating the impact that FAS 132 (R)-1 will have on PHI’s overall financial condition, results of operations, and footnote disclosures for year end reporting.

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(5) SEGMENT INFORMATION

Based on the provisions of SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information,” Pepco Holdings’ management has identified its operating segments at March 31, 2009 as Power Delivery, Conectiv Energy, Pepco Energy Services, and Other Non-Regulated. Segment financial information for the three months ended March 31, 2009 and 2008, is as follows:

	Three Months Ended March 31, 2009
	(millions of dollars)
				Competitive Energy Segments
	Power Delivery			Conectiv Energy			Pepco Energy Services		Other Non- Regulated			Corp. & Other (a)			PHI Cons.
Operating Revenue	$	1,372		$	575	(b)	$	657	$	13		$	(97	)	$	2,520
Operating Expense (c)		1,258	(b)(d)		561			642		1			(97	)		2,365
Operating Income		114			14			15		12			—			155
Interest Income		1			—			—		1			(1	)		1
Interest Expense		53			8			4		4			21			90
Other Income (Expense)		3			—			1		(1	)		—			3
Preferred Stock Dividends		—			—			—		1			(1	)		—
Income Taxes		23			2			4		1			(6	)		24
Net Income (Loss)		42			4			8		6			(15	)		45
Total Assets		10,313			1,991			868		1,477			1,936			16,585
Construction Expenditures	$	132		$	41		$	3	$	—		$	4		$	180

Notes:

(a) Includes unallocated Pepco Holdings’ (parent company) capital costs, such as acquisition financing costs, and the depreciation and amortization related to purchase accounting adjustments for the fair value for Conectiv assets and liabilities as of the August 1, 2002 acquisition date. Additionally, the Total Assets line item in this column includes Pepco Holdings’ goodwill balance. Included in Corp. & Other are intercompany amounts of $(97) million for Operating Revenue, $(94) million for Operating Expense, $(24) million for Interest Income, $(23) million for Interest Expense, and $(1) million for Preferred Stock Dividends.

(b) Power Delivery purchased electric energy and capacity and natural gas from Conectiv Energy in the amount of $83 million for the three months ended March 31, 2009.

(c) Includes depreciation and amortization of $96 million, consisting of $79 million for Power Delivery, $9 million for Conectiv Energy, $4 million for Pepco Energy Services, $1 million for Other Non-Regulated, and $3 million for Corp. & Other.

(d) Includes $14 million ($8 million after-tax) gain related to settlement of Mirant bankruptcy claims.

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	Three Months Ended March 31, 2008
	(millions of dollars)
				Competitive Energy Segments
	Power Delivery			Conectiv Energy			Pepco Energy Services		Other Non- Regulated			Corp. & Other (a)			PHI Cons.
Operating Revenue	$	1,295		$	823	(b)	$	621	$	18		$	(116	)	$	2,641
Operating Expense (c)		1,191	(b)		736			607		1			(117	)		2,418
Operating Income		104			87			14		17			1			223
Interest Income		6			—			—		1			—			7
Interest Expense		48			6			1		4			22			81
Other Income (Expense)		4			—			1		(2	)		—			3
Preferred Stock Dividends		—			—			—		1			(1	)		—
Income Taxes		19			33			5		1			(5	)		53
Net Income (Loss)		47			48			9		10			(15	)		99
Total Assets		9,885			1,982			698		1,443			1,585			15,593
Construction Expenditures	$	148		$	16		$	5	$	—		$	2		$	171

Notes:

(a) Includes unallocated Pepco Holdings’ (parent company) capital costs, such as acquisition financing costs, and the depreciation and amortization related to purchase accounting adjustments for the fair value for Conectiv assets and liabilities as of the August 1, 2002 acquisition date. Additionally, the Total Assets line item in this column includes Pepco Holdings’ goodwill balance. Included in Corp. & Other are intercompany amounts of $(117) million for Operating Revenue, $(115) million for Operating Expense, $(16) million for Interest Income, $(15) million for Interest Expense, and $(1) million for Preferred Stock Dividends.

(b) Power Delivery purchased electric energy and capacity and natural gas from Conectiv Energy in the amount of $98 million for the three months ended March 31, 2008.

(c) Includes depreciation and amortization of $91 million, consisting of $76 million for Power Delivery, $9 million for Conectiv Energy, $3 million for Pepco Energy Services, $1 million for Other Non-Regulated, and $2 million for Corp. & Other.

(6) GOODWILL

PHI’s goodwill balance of $1.4 billion was unchanged during the three month period ended March 31, 2009. Substantially all of PHI’s goodwill was generated by Pepco’s acquisition of Conectiv in 2002 and is allocated to the Power Delivery reporting unit for purposes of assessing impairment under SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS No. 142). PHI’s July 1, 2008 annual impairment test indicated that its goodwill was not impaired. PHI performed an interim impairment test as of December 31, 2008 and March 31, 2009 as its market capitalization was below book value at December 31, 2008 and declined further to a level of 33% below book value at March 31, 2009. As a result of these impairment tests, the Company has concluded that its goodwill was not impaired at both December 31, 2008 and March 31, 2009.

In order to estimate the fair value of its Power Delivery reporting unit, PHI reviews the results from two discounted cash flow models. The models differ in the method used to calculate the terminal value of the reporting unit. One model estimates terminal value based on a constant annual cash flow growth rate that is consistent with Power Delivery’s long-term view of the business, and the other model estimates terminal value based on a multiple of earnings before interest, taxes, depreciation, and amortization (EBITDA) that management believes is consistent with EBITDA multiples for comparable utilities. The models use a cost of capital appropriate for a regulated utility as the discount rate for the estimated cash flows associated with the reporting unit. PHI has consistently used this valuation approach to estimate the fair value of Power Delivery since the adoption of SFAS No. 142.

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The estimation of fair value is dependent on a number of factors that are sourced from the Power Delivery reporting unit’s business forecast, including but not limited to interest rates, growth assumptions, returns on rate base, operating and capital expenditure requirements, and other factors, changes in which could materially impact the results of impairment testing. Assumptions and methodologies used in the models were consistent with historical experience, including assumptions concerning the recovery of operating costs and capital expenditures. Sensitive, interrelated and uncertain variables that could decrease the estimated fair value of the Power Delivery reporting unit include utility sector market performance, sustained adverse business conditions, changes in forecasted revenues, higher operating and capital expenditure requirements, a significant increase in the cost of capital and other factors.

In addition to estimating the fair value of its Power Delivery reporting unit, PHI estimated the fair value of its other business segments (Conectiv Energy, Pepco Energy Services, Other Non-Regulated, and Corporate & Other) at March 31, 2009. The sum of the fair value of all business segments was reconciled to PHI’s market capitalization at March 31, 2009 to further substantiate the estimated fair value of the Power Delivery reporting unit.

The sum of the estimated fair values of all segments exceeded the market capitalization of PHI at March 31, 2009. PHI believes that the excess of the estimated fair value of PHI’s segments as compared to PHI’s market capitalization reflects a reasonable control premium that is comparable to control premiums observed in historical acquisitions in the utility industry during various economic environments. Given the lack of a fundamental change in the Power Delivery reporting unit’s business, PHI does not believe the recent decline in its stock price is indicative of a commensurate decline in the fair value of PHI’s Power Delivery reporting unit. PHI’s Power Delivery reporting unit consists of regulated companies with regulated recovery rates and approved rates of return allowing for generally predictable and steady streams of revenues and cash flows over an extended period of time.

With the current volatile general market conditions, the sustained period of time that PHI’s stock price is below its book value, and the disruptions in the credit and capital markets, PHI will continue to closely monitor for indicators of goodwill impairment.

(7) LEASING ACTIVITIES

Investment in Finance Leases Held in Trust

As of March 31, 2009 and December 31, 2008, Pepco Holdings had cross-border energy lease investments of $1.3 billion, consisting of hydroelectric generation and coal-fired electric generation facilities and natural gas distribution networks located outside of the United States.

As further discussed in Note (15), “Commitments and Contingencies—PHI’s Cross-Border Energy Lease Investments,” during the second quarter of 2008, PHI reassessed the sustainability of its tax position and revised its assumptions regarding the estimated timing of tax benefits generated from its cross-border energy lease investments. Based on this reassessment, PHI for the quarter ended June 30, 2008, recorded a reduction in its cross-border energy lease investments of $124 million. No further charges were considered necessary in 2008 or in the first quarter of 2009.

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The components of the cross-border energy lease investments at March 31, 2009 and at December 31, 2008 (reflecting the effects of recording this charge) are summarized below:

	March 31, 2009			December 31, 2008
	(millions of dollars)
Scheduled lease payments, net of non-recourse debt	$	2,281		$	2,281
Less: Unearned and deferred income		(932	)		(946	)
Investment in finance leases held in trust		1,349			1,335
Less: Deferred income taxes		(679	)		(679	)
Net investment in finance leases held in trust	$	670		$	656

Income recognized from cross-border energy lease investments was comprised of the following for the three months ended March 31, 2009 and 2008:

	2009		2008
	(millions of dollars)
Pre-tax earnings from PHI’s cross-border energy lease investments (included in “Other Revenue”)	$	14	$	19
Income tax expense		4		5
Net income from PHI’s cross-border energy lease investments	$	10	$	14

(8) PENSIONS AND OTHER POSTRETIREMENT BENEFITS

The following Pepco Holdings information is for the three months ended March 31, 2009 and 2008:

	Pension Benefits						Other Postretirement Benefits
	2009			2008			2009			2008
	(millions of dollars)
Service cost	$	9		$	10		$	2		$	2
Interest cost		28			25			10			9
Expected return on plan assets		(28	)		(33	)		(4	)		(2	)
Prior service credit component		—			—			(1	)		(1	)
Gain component		12			3			3			3
Net periodic benefit cost	$	21		$	5		$	10		$	11

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Pension

The pension net periodic benefit cost for the three months ended March 31, 2009, of $21 million includes $5 million for Pepco, $2 million for ACE and $3 million for DPL before intercompany allocations from the PHI Service Company. The three utility subsidiaries are generally responsible for approximately 80% to 85% of total PHI net periodic benefit cost. Historically, a portion of the net periodic benefit cost is capitalized as part of the cost of labor for internal construction projects. The pension net periodic benefit cost for the three months ended March 31, 2008, of $5 million includes $2 million for Pepco, $1 million for ACE and $(1) million for DPL before intercompany allocations.

Pension Contributions

PHI’s funding policy with regard to PHI’s non contributory retirement plan (the PHI Retirement Plan) is to maintain a funding level that is in excess of 100% of its accumulated benefit obligation and that is at least equal to the funding target as defined under the Pension Protection Act of 2006. PHI expects to make discretionary tax-deductible contributions totaling approximately $300 million to bring its plan assets to at least the funding target level for 2009 under the Pension Protection Act. During the quarters ended March 31, 2009 and 2008, neither PHI nor its subsidiaries made contributions to the PHI Retirement Plan. Pepco contributed $100 million to the plan on April 1, 2009.

Other Postretirement Benefits

The other postretirement net periodic benefit cost for the three months ended March 31, 2009, of $10 million includes $3 million for Pepco, $2 million for ACE and $2 million for DPL before intercompany allocations from the PHI Service Company. The other postretirement net periodic benefit cost for the three months ended March 31, 2008, of $11 million includes $4 million for Pepco, $2 million for ACE and $2 million for DPL before intercompany allocations.

(9) DEBT

PHI’s primary 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 and consists of commitments from 17 lenders, no one of which is responsible for more than 8.5% of the total $1.5 billion commitment. PHI’s credit limit under the facility is $875 million. The credit limit of each of Pepco, DPL and ACE is the lesser of $500 million and the maximum amount of debt the company is permitted to have outstanding by its regulatory authorities, except that the aggregate amount of credit used by Pepco, DPL and ACE at any given time collectively may not exceed $625 million.

In November 2008, PHI entered into a second credit facility in the amount of $400 million with a syndicate of nine lenders. Under the facility, PHI may obtain revolving loans and swingline loans over the term of the facility, which expires on November 6, 2009. The facility does not provide for the issuance of letters of credit. All indebtedness incurred under the facility is unsecured.

These two facilities are referred to collectively as PHI’s “primary credit facilities.”

PHI and its utility subsidiaries historically have issued commercial paper to meet their short-term working capital requirements. As a result of the recent disruptions in the commercial

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paper market, the companies borrowed under the $1.5 billion credit facility to create a cash reserve for future short-term operating needs. At March 31, 2009, PHI had an outstanding loan of $150 million, and Pepco had an outstanding loan of $100 million, which was repaid by Pepco at maturity in April 2009.

In January 2009, ACE Funding made principal payments of $5.7 million on Series 2002-1 Bonds, Class A-2, and $2.1 million on Series 2003-1 Bonds, Class A-1.

In January 2009, Pepco redeemed $50 million of 6.25% medium-term notes at maturity.

In March 2009, Pepco resold $110 million of Pollution Control Revenue Refunding Bonds, which previously had been issued for the benefit of Pepco by the Maryland Economic Development Corporation. Pepco purchased the bonds in 2008 in response to disruptions in the municipal auction rate securities market that made it difficult for the remarketing agent to successfully remarket the bonds. As the owner of the bonds, Pepco received the proceeds of the sale, which it intends to use for general corporate purposes.

In April 2009, ACE Funding made principal payments of $5.3 million on Series 2002-1 Bonds, Class A-2, and $2.1 million on Series 2003-1 Bonds, Class A-1.

In April 2009, Pepco repaid, prior to maturity, a $25 million short-term loan.

In April 2009, DPL resold $9 million of its Pollution Control Revenue Refunding bonds issued by the Delaware Economic Development Authority. These bonds were repurchased by DPL in November 2008 in response to disruption in the tax-exempt bond market that made it difficult for the remarketing agent to successfully remarket the bonds. As the owner of the bonds, DPL received the proceeds of the sale and intends to use the proceeds for general corporate purposes.

In May 2009, DPL repaid, prior to maturity, $50 million of its $150 million short-term loan which matures in July 2009.

In May 2009, PHI entered into a $50 million, 18 month bi-lateral credit agreement, which can only be used for the purpose of obtaining letters of credit.

The continued disruptions in the capital and credit markets, combined with the volatility of energy prices, have had an impact on the borrowing capacity and liquidity of PHI and its subsidiaries. To address the challenges posed by the current capital and credit market environment and to ensure that PHI and its subsidiaries will continue to have sufficient access to cash to meet their liquidity needs, PHI and its subsidiaries, since the third quarter of 2008, have issued various debt and equity instruments, secured an additional $450 million in new credit facilities and entered into a credit intermediation arrangement (as discussed below).

At March 31, 2009, the amount of cash, plus borrowing capacity under PHI’s syndicated credit facilities available to meet the future liquidity needs of PHI on a consolidated basis totaled $1.7 billion, of which $1.0 billion consisted of the combined cash and borrowing capacity of PHI’s utility subsidiaries. At December 31, 2008, the amount of cash, plus borrowing capacity

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under the syndicated credit facilities available to meet the liquidity needs of PHI on a consolidated basis totaled $1.5 billion, of which $843 million consisted of the combined cash and borrowing capacity of PHI’s utility subsidiaries.

Collateral Requirements of the Competitive Energy Businesses

In conducting its retail energy sales business, Pepco Energy Services, during periods of declining energy prices, has been exposed to the asymmetrical risk of having to post collateral under its wholesale purchase contracts without receiving a corresponding amount of collateral from its retail customers. To partially address these asymmetrical collateral obligations, Pepco Energy Services, in the first quarter of 2009, entered into a credit intermediation arrangement with Morgan Stanley Capital Group, Inc. (MSCG). Under this arrangement, MSCG, in consideration for the payment to MSCG of certain fees, (i) has assumed by novation certain electricity purchase obligations of Pepco Energy Services in years 2009 through 2011 under several wholesale purchase contracts and (ii) has agreed to supply electricity to Pepco Energy Services on the same terms as the novated transactions, but without imposing on Pepco Energy Services any associated collateral obligations. As of March 31, 2009, approximately 39% of Pepco Energy Services’ wholesale electricity purchase obligations (measured in megawatt hours) were covered by this credit intermediation arrangement with MSCG. The fees incurred by Pepco Energy Services in the amount of $25 million are being amortized in declining amounts over the life of the arrangement based on the fair value of the underlying contracts at the time of novation.

In addition to Pepco Energy Service’s retail energy sales business, Conectiv Energy and Pepco Energy Services in the ordinary course of business enter into various other contracts to buy and sell electricity, fuels and related products, including derivative instruments, designed to reduce their financial exposure to changes in the value of their assets and obligations due to energy price fluctuations. These contracts also typically have collateral requirements.

Depending on the contract terms, the collateral required to be posted by Pepco Energy Services and Conectiv Energy can be of varying forms, including cash and letters of credit. As of March 31, 2009, the Competitive Energy businesses (including Pepco Energy Service’s retail energy sales business) had posted net cash collateral of $581 million and letters of credit of $296 million. At December 31, 2008, the Competitive Energy businesses had posted net cash collateral of $331 million and letters of credit of $558 million.

At March 31, 2009 and December 31, 2008, the amount of cash, plus borrowing capacity under PHI’s primary credit facilities available to meet the future liquidity needs of the Competitive Energy businesses totaled $732 million and $684 million, respectively.

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(10) INCOME TAXES

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

	For the Three Months Ended March 31,
	2009		2008
Federal statutory rate	35.0	%	35.0	%
Increases (decreases) resulting from:
Depreciation	2.2		.5
State income taxes, net of federal effect	5.8		5.4
Tax credits	(1.6	)	(.7	)
Leveraged leases	(1.9	)	(1.2	)
Change in estimates and interest related to uncertain and effectively settled tax positions	(3.5	)	(4.6	)
Other, net	(1.2	)	.2
Consolidated Effective Income Tax Rate	34.8	%	34.6	%

PHI’s effective tax rates for the three months ended March 31, 2009 and 2008 were 34.8% and 34.6%, respectively. While the effective rate was consistent between the periods, there were differences in specific items comprising the rate. An increase in the rate resulted from a change in the flow-through of certain book / tax depreciation differences, and changes in estimates and interest related to uncertain and effectively settled tax positions. The increase in the change in estimates and interest related to uncertain and effectively settled tax positions is primarily due to the non-recurring impact of a tax claim filed with the Internal Revenue Service (IRS) in March 2008. The claim was for the treatment of casualty losses as current deductions (as opposed to being depreciated over their tax lives) on prior year returns currently under audit. These increases were offset by other changes, primarily related to adjustments to prior years’ taxes and tax credits.

In March 2009, the IRS issued its Revenue Agent’s Report (RAR) for the audit of PHI’s consolidated federal income tax returns for the calendar years 2003 to 2005. The IRS has proposed adjustments to PHI’s tax returns, including adjustments to the Company’s deductions related to cross-border energy lease investments, the capitalization of overhead costs for tax purposes and the deductibility of certain casualty losses. PHI is taking steps to appeal certain of the proposed adjustments and believes it has adequately reserved for the adjustments included in the RAR.

During the first quarter of 2009, primarily as a result of the RAR, PHI reduced uncertain tax benefits by $57 million ($38 million as a result of settlements with taxing authorities and $19 million as adjustments to prior year tax positions).

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(11) STOCK-BASED COMPENSATION

There were no stock options granted in the three months ended March 31, 2009.

There were no options exercised under all share-based payment arrangements for the three months end March 31, 2009.

(12) EARNINGS PER SHARE

Reconciliations of the numerator and denominator for basic and diluted EPS of common stock calculations are shown below:

	For the Three Months Ended March 31,
	2009		2008
	(In millions, except per share data)
Income (Numerator):
Earnings Applicable to Common Stock	$	45	$	99
Shares (Denominator) (a):
Weighted average shares outstanding for basic computation:
Average shares outstanding		219		201
Adjustment to shares outstanding		—		—
Weighted Average Shares Outstanding for Computation of Basic Earnings Per Share of Common Stock		219		201
Net effect of potentially dilutive shares		—		—
Weighted Average Shares Outstanding for Computation of Diluted Earnings Per Share of Common Stock		219		201
Basic earnings per share of common stock	$	.21	$	.49
Diluted earnings per share of common stock	$	.21	$	.49

(a) The number of options to purchase shares of common stock that were excluded from the calculation of diluted EPS as they are considered to be anti-dilutive were 363,366 and 5,000 for the three months ended March 31, 2009 and 2008, respectively.

(13) DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

PHI accounts for its derivative activities in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133) as amended by subsequent pronouncements.

PHI’s Competitive Energy businesses use derivative instruments primarily to reduce their financial exposure to changes in the value of their assets and obligations due to commodity price fluctuations. The derivative instruments used by the Competitive Energy businesses include forward contracts, futures, swaps, and exchange-traded and over-the-counter options. The Competitive Energy businesses also manage commodity risk with contracts that are not classified and not accounted for as derivatives. The two primary risk management objectives are (i) to manage the spread between the cost of fuel used to operate electric generation plants and the revenue received from the sale of the power produced by those plants, and (ii) to manage the spread between retail sales commitments and the cost of supply used to service those commitments to ensure stable cash flows, and lock in favorable prices and margins when they become available.

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Conectiv Energy purchases 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 purchases 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 delivery to requirements-load customers. Conectiv Energy sells electricity swaps, options and forward contracts to hedge price risk in connection with electric output from its generation fleet. Conectiv Energy accounts for most of its futures, swaps and certain forward contracts as cash flow hedges of forecasted transactions. Derivative contracts purchased or sold in excess of probable amounts of forecasted hedge transactions are marked-to-market through current earnings. All option contracts are marked-to-market through current earnings. Certain natural gas and oil futures and swaps are used as fair value hedges to protect physical fuel inventory. Some forward contracts are accounted for using standard accrual accounting since these contracts meet the requirements for normal purchase and sale accounting under SFAS No. 133.

Pepco Energy Services purchases energy commodity contracts in the form of 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 delivery to customers. Pepco Energy Services accounts for its futures and swap contracts as cash flow hedges of forecasted transactions. Certain commodity contracts that do not qualify as cash flow hedges of forecasted transactions or do not meet the requirements for normal purchase and sale accounting are marked-to-market through current earnings. Forward contracts are accounted for using standard accrual accounting since these contracts meet the requirements for normal purchase and sale accounting under SFAS No. 133.

In the Power Delivery business, DPL uses derivative instruments in the form of forward contracts, futures, swaps, and exchange-traded and over-the-counter options primarily to reduce gas commodity price volatility and limit its customers’ exposure to increases in the market price of gas. DPL also manages commodity risk with physical natural gas and capacity contracts that are not classified as derivatives. All premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all gains and losses related to hedging activities, are deferred under SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” until recovered based on the fuel adjustment clause approved by the DPSC.

PHI and its subsidiaries also use derivative instruments from time to time to mitigate the effects of fluctuating interest rates on debt incurred in connection with the operation of their businesses. In June 2002, PHI entered into several treasury rate lock transactions in anticipation of the issuance of several series of fixed-rate debt commencing in July 2002.

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The tables below identify the balance sheet location and fair values of derivative instruments as of March 31, 2009 and December 31, 2008:

	As of March 31, 2009
	(millions of dollars)
Balance Sheet Caption	Derivatives Designated as Hedging Instruments			Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting			Net Derivative Instruments
Derivative Assets (current assets)	$	353		$	2,394		$	2,747		$	(2,628	)	$	119
Derivative Assets (non-current assets)		127			117			244			(215	)		29
Total Derivative Assets		480			2,511			2,991			(2,843	)		148
Derivative Liabilities (current liabilities)		(890	)		(2,360	)		(3,250	)		3,084			(166	)
Derivative Liabilities (non-current liabilities)		(165	)		(151	)		(316	)		219			(97	)
Total Derivative Liabilities		(1,055	)		(2,511	)		(3,566	)		3,303			(263	)
Net Derivative (Liability) Asset	$	(575	)	$	—		$	(575	)	$	460		$	(115	)
	As of December 31, 2008
	(millions of dollars)
Balance Sheet Caption	Derivatives Designated as Hedging Instruments			Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting			Net Derivative Instruments
Derivative Assets (current assets)	$	314		$	1,736		$	2,050		$	(1,952	)	$	98
Derivative Assets (non-current assets)		86			87			173			(164	)		9
Total Derivative Assets		400			1,823			2,223			(2,116	)		107
Derivative Liabilities (current liabilities)		(698	)		(1,670	)		(2,368	)		2,224			(144	)
Derivative Liabilities (non-current liabilities)		(113	)		(112	)		(225	)		166			(59	)
Total Derivative Liabilities		(811	)		(1,782	)		(2,593	)		2,390			(203	)
Net Derivative (Liability) Asset	$	(411	)	$	41		$	(370	)	$	274		$	(96	)

Under FSP FIN 39-1, 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, 2009			December 31, 2008
	(millions of dollars)
Cash collateral pledged to counterparties with the right to reclaim (a)	$	485		$	326
Cash collateral received from counterparties with the obligation to return		(25	)		(52	)

(a) Includes cash deposits on commodity brokerage accounts

As of March 31, 2009 and December 31, 2008, PHI had no cash collateral pledged or received related to derivatives accounted for at fair value that it was not entitled to offset under master netting agreements.

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Derivatives Designated as Hedging Instruments

Cash Flow Hedges

Competitive Energy

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 accumulated other comprehensive (losses) earnings (AOCL) and is reclassified into earnings in the same period or periods during which the hedged transactions affect earnings. Gains and losses on the derivative representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. This information for the activity during the three months ended March 31, 2009 and 2008, is provided in the table below:

	Three Months Ended March 31, 2009			Three Months Ended March 31, 2008
	(millions of dollars)
Amount of (losses) gains arising during the period included in accumulated other comprehensive (losses) earnings (a)	$	(256	)	$	212
Amount of (loss) gain reclassified into earnings:
Effective portion:
Competitive Energy Revenue		4			18
Fuel and Purchased Energy		(102	)		(6	)
Total		(98	)		12
Ineffective portion:
Competitive Energy Revenue		(1	)		(3	)
Fuel and Purchased Energy		(5	)		6
Total		(6	)		3
Total (loss) gain reclassified into earnings		(104	)		15
Net (losses) gains on commodity derivatives	$	(152	)	$	197

(a) Included in the $(256) million loss is a $(4) million loss previously realized but not yet recognized.

Included in the above table are a loss of $2 million and a gain of less than $1 million for the three months ended March 31, 2009 and 2008, respectively, which were reclassified from AOCL to earnings because the forecasted hedged transactions were deemed no longer probable.

As of March 31, 2009 and December 31, 2008, PHI’s Competitive Energy businesses had the following types and volumes of energy commodity contracts employed as cash flow hedges of forecasted purchases and forecasted sales.

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	Quantities
Commodity	March 31, 2009	December 31, 2008
Forecasted Purchases Hedges
Coal (Tons)	120,000	120,000
Natural gas (MMBtu)	91,782,000	85,034,233
Electricity (MWh)	28,578,607	27,856,037
Electric capacity (MW-Days)	869,400	1,400,400
Heating oil (Barrels)	174,000	128,000
Forecasted Sales Hedges
Electricity (MWh)	18,128,625	19,808,191
Electric capacity (MW-Days)	265,020	308,220

Power Delivery

As described above, all premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all gains and losses related to hedging activities, are deferred under SFAS No. 71 until recovered based on the fuel adjustment clause approved by the DPSC. The following table indicates the amounts deferred as regulatory assets or liabilities and the location in the consolidated statements of earnings of amounts reclassified to earnings through the fuel adjustment clause for the three months ended March 31, 2009 and March 31, 2008:

Type of Derivative	Gain (Loss) Deferred as a Regulatory Asset/Liability				Gain (Loss) Reclassified from Regulatory Asset/Liability to Earnings						Location of Gain (Loss) in Statements of Consolidated Earnings for amounts Reclassified from Regulatory Asset/Liability to Earnings
	2009		2008		2009			2008
	(millions of dollars)
Energy Commodity Contracts	$	—	$	6	$	(16	)	$	(1	)	Fuel and Purchased Energy

As of March 31, 2009 and December 31, 2008, Power Delivery had the following outstanding commodity forward contracts that were entered into to hedge forecasted transactions:

	Quantities
Commodity	March 31, 2009	December 31, 2008
Forecasted Purchases Hedges:
Natural Gas (MMBtu)	8,850,000	10,805,000

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Cash Flow Hedges Included in Accumulated Other Comprehensive Loss

The table below provides detail on effective cash flow hedges under SFAS No. 133 included in PHI’s consolidated balance sheet as of March 31, 2009. Under SFAS No. 133, cash flow hedges are marked-to-market on the balance sheet with corresponding adjustments to AOCL. The data in the table indicate the cumulative gains (losses) after-tax on effective cash flow hedges by contract type in AOCL, the portion of AOCL expected to be reclassified to earnings during the next 12 months, and the maximum hedge or deferral term:

Contracts	Accumulated Other Comprehensive Loss After-tax (a)			Portion Expected to be Reclassified to Earnings during the Next 12 Months			Maximum Term
	(millions of dollars)
Energy Commodity (b)	$	(317	)	$	(225	)	62 months
Interest Rate		(25	)		(3	)	281 months
Total	$	(342	)	$	(228	)

(a) Accumulated Other Comprehensive Loss on PHI’s consolidated balance sheet as of March 31, 2009, includes a $9 million balance related to minimum pension liability. This balance is not included in this table as it is not a cash flow hedge.

(b) The large unrealized derivative losses recorded in Accumulated Other Comprehensive Loss are substantially offset by wholesale and retail load service sales contracts in gain positions that are subject to accrual accounting. These forward sales contracts to commercial and industrial customers, utilities, municipalities, and electric cooperatives are exempted from mark-to-market accounting because they either qualify as normal sales under SFAS No. 133 Paragraph 10b, or they are not derivative contracts at all. Under accrual accounting, no asset is recorded on the balance sheet for these contracts, and revenue is not recognized until the period of delivery.

Fair Value Hedges

In connection with their energy commodity activities, the Competitive Energy businesses designate certain derivatives as fair value hedges. For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative as well as the offsetting gain or loss on the hedged item attributable to the hedged risk are recognized in current earnings. For the three months ended March 31, 2009 and 2008, the amount of the derivative gain (loss) recognized by statement of earnings line item for hedges is as follows:

Type of Derivative	Location of Gain (Loss) Recognized in Earnings on Derivatives	Gain (Loss) on Derivatives Recognized in Earnings					Gain (Loss) on Hedged Items Recognized in Earnings
		2009		2008			2009			2008
		(millions of dollars)
Energy Commodity Contracts	Competitive Energy Revenue	$	—	$	(8	)	$	—		$	8
Energy Commodity Contracts	Fuel and Purchased Energy		2		(3	)		(2	)		3
Total		$	2	$	(11	)	$	(2	)	$	11

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As of March 31, 2009 and December 31, 2008, PHI’s Competitive Energy businesses had the following outstanding commodity forward contracts volumes and net position on derivatives that were accounted for as fair value hedges of fuel inventory and natural gas transportation:

Commodity	March 31, 2009		December 31, 2008
	Quantity	Net Position	Quantity	Net Position
Natural Gas Basis (MMBtu)	1,850,000	Long	1,800,000	Short
Oil (Barrels)	—	—	466,000	Short

Other Derivative Activity

Competitive Energy Businesses

In connection with their energy commodity activities, the Competitive Energy businesses hold certain derivatives that do not qualify as hedges. Under SFAS No. 133, these derivatives are recorded at fair value through earnings with corresponding adjustments on the balance sheet.

For the three months ended March 31, 2009 and 2008, the amount of the derivative gain (loss) in the Competitive Energy businesses recognized in earnings is provided in the table below:

	Three Months Ended March 31, 2009
	Competitive Energy Revenue			Fuel and Purchased Energy Expense			Total
	(millions of dollars)
Realized mark-to-market gains (losses)	$	63		$	(16	)	$	47
Unrealized mark-to-market gains (losses)		(40	)		—			(40	)
Total net mark-to-market gains (losses)	$	23		$	(16	)	$	7

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	Three Months Ended March 31, 2008
	Competitive Energy Revenue		Fuel and Purchased Energy Expense			Total
	(millions of dollars)
Realized mark-to-market gains (losses)	$	63	$	(45	)	$	18
Unrealized mark-to-market gains (losses)		28		—			28
Total net mark-to-market gains (losses)	$	91	$	(45	)	$	46

As of March 31, 2009 and December 31, 2008, PHI’s Competitive Energy businesses had the following net outstanding commodity forward contract volumes and net position on derivatives that did not qualify for hedge accounting:

	March 31, 2009		December 31, 2008
Commodity	Quantity	Net Position	Quantity	Net Position
Coal (Tons)	175,000	Long	30,000	Short
Natural gas (MMBtu)	6,627,781	Long	578,443	Short
Natural gas basis (MMBtu)	16,520,000	Long	18,300,000	Long
Heating oil (Barrels)	451,000	Short	556,000	Short
#6 Oil (Barrels)	25,000	Short	—	—
LSW crude oil (Barrels)	—	Flat	361,988	Short
RBOB UL gasoline (Barrels)	50,000	Short	67,000	Short
Electricity (MWh)	419,348	Short	287,159	Short
Financial transmission rights (MWh)	380,952	Short	3,986,759	Long

Power Delivery

DPL holds certain derivatives that do not qualify as hedges. Under SFAS No. 133, these derivatives are recorded at fair value on the balance sheet with the gain or loss recorded in earnings. In accordance with SFAS No. 71, offsetting regulatory assets or regulatory liabilities are recorded on the balance sheet and the recognition of the gain or recovery of the loss is deferred. For the three months ended March 31, 2009 and March 31, 2008, the amount of the derivative gain (loss) recognized by line item in the consolidated statements of earnings is provided in the table below:

Type of Derivative	Gain (Loss) Deferred as a Regulatory Asset/Liability						Gain (Loss) Reclassified from Regulatory Asset/Liability					Location of Gain (Loss) in Consolidated Statements of Earnings Reclassified from Regulatory Asset/Liability
	2009			2008			2009			2008
	(millions of dollars)
Energy Commodity Contracts	$	(14	)	$	(4	)	$	(3	)	$	—	Fuel and Purchased Energy

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As of March 31, 2009 and December 31, 2008, DPL had the following net outstanding natural gas commodity forward contracts that did not qualify for hedge accounting:

	March 31, 2009		December 31, 2008
Commodity	Quantity	Net Position	Quantity	Net Position
Natural Gas (MMBtu)	11,159,796	Long	8,928,750	Long

Contingent Credit Risk Features

The primary contracts used by the Competitive Energy and Power Delivery businesses 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 (“the exposed party”) may declare an early termination and liquidation of all transactions entered into under the ISDA, including foreclosure against any collateral security. In addition, some of the ISDAs have cross default provisions under which a default by a party under another commodity or derivative contract, or the breach by a party of another borrowing obligation in excess of a specified threshold, is a breach under the ISDA.

The collateral requirements under the ISDA or similar agreements generally work as follows. The parties establish a dollar amount 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 unsecured credit varies according to the senior, unsecured debt rating of either the party directly, or a guarantor of the party’s obligations. The fair values of all transactions are netted under the master netting provisions. Transactions include derivatives accounted for on-balance sheet as well as normal purchases and sales that are accounted for off-balance sheet under SFAS No. 133. If the aggregate fair value of the transactions in a net loss position exceeds the unsecured credit amount, then collateral is required equal to the amount by which the unsecured credit amount is exceeded. The obligations of the Competitive Energy businesses 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

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unsecured credit amount would typically be set at zero and collateral would be required for the entire net loss position. Exchange traded contracts do not contain this contingent credit risk feature related to credit rating as they are fully collateralized.

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, 2009, was $891 million. As of that date, PHI had posted cash collateral of $56 million in the normal course of business against the gross derivative liability resulting in a net liability of $835 million before giving effect to offsetting transactions that are encompassed within master netting agreements that would reduce this amount. PHI’s net settlement amount in the event of a downgrade of PHI and DPL below “investment grade” as of March 31, 2009, would have been approximately $399 million after taking into consideration the master netting agreements. The offsetting transactions or collateral that would reduce PHI’s obligation to the net settlement amount include derivatives and normal purchase and sale contracts in a gain position as well as letters of credit already posted as collateral.

PHI’s primary sources for posting cash collateral or letters of credit are its syndicated credit facilities. At March 31, 2009, the aggregate amount of cash plus borrowing capacity under its primary credit facilities available to meet the future liquidity needs of PHI totaled $1.7 billion, of which $732 million was available for the Competitive Energy businesses.

(14) FAIR VALUE DISCLOSURES

Effective January 1, 2008, PHI adopted SFAS No. 157 which established a framework for measuring fair value and expands disclosures about fair value measurements.

As defined in SFAS No. 157, 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. PHI is able to classify fair value balances based on the observability of those inputs. SFAS No. 157 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 measurement) and the lowest priority to unobservable inputs (level 3 measurement). The three levels of the fair value hierarchy defined by SFAS No. 157 are 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.

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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 pricing 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, 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. Level 3 instruments classified as derivative liabilities are primarily natural gas options. 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. Some of the options do not expire until December 2011. All of the options are part of the natural gas hedging program approved by the Delaware Public Service Commission.

Level 3 instruments classified as executive deferred compensation plan assets and liabilities are life insurance policies that are valued using the cash surrender value of the policies. Since these values do not represent a quoted price in an active market they are considered Level 3.

The following tables set forth by level within the fair value hierarchy PHI’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2009 and December 31, 2008. As required by SFAS No. 157, 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.

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	Fair Value Measurements at March 31, 2009
	(millions of dollars)
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
ASSETS
Derivative instruments	$	147	$	23	$	105	(a)	$	19
Cash equivalents		619		619		—			—
Executive deferred compensation plan assets		68		11		39			18
	$	834	$	653	$	144		$	37
LIABILITIES
Derivative instruments	$	722	$	270	$	403		$	49
Executive deferred compensation plan liabilities		30		—		30			—
	$	752	$	270	$	433		$	49

(a) Includes a contra-asset balance of $7 million related to the impact of netting certain counterparties across the levels of the fair value hierarchy.

	Fair Value Measurements at December 31, 2008
	(millions of dollars)
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
ASSETS
Derivative instruments	$	139	$	53	$	79	$	7
Cash equivalents		460		460		—		—
Executive deferred compensation plan assets		70		11		41		18
	$	669	$	524	$	120	$	25
LIABILITIES
Derivative instruments	$	509	$	184	$	296	$	29
Executive deferred compensation plan liabilities		31		—		31		—
	$	540	$	184	$	327	$	29

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, 2009 and March 31, 2008 are shown below:

	Three Months Ended March 31, 2009
	Net Derivative Instruments Liability			Deferred Compensation Plan Assets
	(millions of dollars)
Beginning balance as of January 1, 2009	$	(22	)	$	18
Total gains or (losses) (realized and unrealized)
Included in earnings		1			1
Included in accumulated other comprehensive (losses) earnings		6			—
Included in regulatory liabilities		(17	)		—
Purchases and issuances		—			(1	)
Settlements		2			—
Transfers in and/or out of Level 3		—			—
Ending balance as of March 31, 2009	$	(30	)	$	18

	Operating Revenue		Other Operation and Maintenance Expense
	(millions of dollars)
Gains or (losses) (realized and unrealized) included in earnings for the period above are reported in Operating Revenue and Other Operation and Maintenance Expense as follows:
Total gains (losses) included in earnings for the period above	$	1	$	1
Change in unrealized gains (losses) relating to assets still held at reporting date	$	1	$	1

	Three Months Ended March 31, 2008
	Net Derivative Instruments			Deferred Compensation Plan Assets
	(millions of dollars)
Beginning balance as of January 1, 2008	$	(3	)	$	17
Total gains or (losses) (realized and unrealized)
Included in earnings		(2	)		1
Included in accumulated other comprehensive (losses) earnings		36			—
Included in regulatory liabilities		4			—
Purchases and issuances		3			(1	)
Settlements		—			—
Transfers in and/or out of Level 3		—			—
Ending balance as of March 31, 2008	$	38		$	17
	Operating Revenue			Other Operation and Maintenance Expense
	(millions of dollars)
Gains or (losses) (realized and unrealized) included in earnings for the period above are reported in Operating Revenue and Other Operation and Maintenance Expense as follows:
Total gains (losses) included in earnings for the period above	$	(2	)	$	1
Change in unrealized gains (losses) relating to assets still held at reporting date	$	(2	)	$	1

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(15) COMMITMENTS AND CONTINGENCIES

Regulatory and Other Matters

Proceeds from Settlement of Mirant Bankruptcy Claims

In 2000, Pepco sold substantially all of its electricity generating assets to Mirant Corporation (Mirant). As part of the sale, Pepco and Mirant entered into a “back-to-back” arrangement, whereby Mirant agreed to purchase from Pepco the 230 megawatts of electricity and capacity that Pepco was obligated to purchase annually through 2021 from Panda under the Panda PPA at the purchase price Pepco was obligated to pay to Panda. In 2003, Mirant commenced a voluntary bankruptcy proceeding in which it sought to reject certain obligations that it had undertaken in connection with the asset sale. As part of the settlement of Pepco’s claims against Mirant arising from the bankruptcy, Pepco agreed not to contest the rejection by Mirant of its obligations under the “back-to-back” arrangement in exchange for the payment by Mirant of damages corresponding to the estimated amount by which the purchase price that Pepco was obligated to pay Panda for the energy and capacity exceeded the market price. In 2007, Pepco received as damages $414 million in net proceeds from the sale of shares of Mirant common stock issued to it by Mirant. In September 2008, Pepco transferred the Panda PPA to Sempra, along with a payment to Sempra, thereby terminating all further rights, obligations and liabilities of Pepco under the Panda PPA. In November 2008, Pepco filed with the District of Columbia Public Service Commission (DCPSC) and the Maryland Public Service Commission (MPSC) proposals to share with customers the remaining balance of proceeds from the Mirant settlement in accordance with divestiture sharing formulas previously approved by the respective commissions.

On March 5, 2009, the DCPSC issued an order approving Pepco’s sharing proposal. Under the order and Pepco’s compliance filing tariff, which was deemed effective on March 20, 2009, approximately $24 million has been reflected in customers’ April 2009 bills as a one-time credit. As a result of this decision, Pepco recorded a pre-tax gain of approximately $14 million for the quarter ended March 31, 2009.

On February 17, 2009, Pepco, the Maryland Office of People’s Counsel (the Maryland OPC) and the MPSC staff filed a settlement agreement with the MPSC, which, among other things, provides that Pepco would distribute $39 million of the remaining balance of the Mirant settlement to its Maryland customers through a one-time billing credit. If the settlement is approved by the MPSC, Pepco currently estimates that it would result in a pre-tax gain in the range of $15 million to $25 million, which would be recorded when the MPSC issues its final order approving the settlement. A hearing before the MPSC on the settlement is scheduled for May 14, 2009.

Pending the final disposition of these funds in Maryland, as of March 31, 2009, approximately $64 million in remaining proceeds from the Mirant settlement is being accounted for as restricted cash and approximately $88 million is being accounted for as a regulatory liability. The regulatory liability is comprised of approximately $64 million awaiting final regulatory resolution and approximately $24 million relating to the one-time customer credit approved by the DCPSC.

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Rate Proceedings

In the most recent electric service distribution base rate cases filed by Pepco in the District of Columbia and Maryland and by DPL in Maryland, and in a natural gas distribution case filed by DPL in Delaware, Pepco and DPL proposed the adoption of a bill stabilization adjustment mechanism (BSA) for retail customers. In addition, in February 2009, ACE included a BSA proposal in a filing with the New Jersey Board of Public Utilities (NJBPU). As more fully discussed below, the implementation of a BSA has been approved for both Pepco and DPL electric service in Maryland and remains pending for Pepco in the District of Columbia and ACE in New Jersey. A method of revenue decoupling similar to a BSA, referred to as a modified fixed variable rate design (MFVRD), has been adopted for DPL electric and natural gas service in Delaware, which will be implemented in the context of DPL’s next Delaware base rate case.

Under the BSA, customer delivery rates are subject to adjustment (through a surcharge or credit mechanism), depending on whether actual distribution revenue per customer exceeds or falls short of the approved revenue-per-customer amount. The BSA increases rates if actual distribution revenues fall below the level approved by the applicable commission 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 deliveries. As a consequence, a BSA “decouples” revenue from unit sales consumption and ties the growth in 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 utility 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 delivery revenues. The MFVRD adopted in Delaware relies primarily upon 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 believes that the MFVRD can serve as an appropriate revenue decoupling mechanism.

Delaware

On August 29, 2008, DPL submitted its 2008 GCR filing to the DPSC, requesting a 14.8% increase in the level of GCR. On September 16, 2008, the DPSC issued an initial order approving the requested increase, which became effective on November 1, 2008, subject to refund pending final DPSC approval after evidentiary hearings.

Due to a significant decrease in wholesale gas prices, on January 26, 2009, DPL submitted to the DPSC an interim GCR filing, requesting a 6.6% decrease in the level of GCR. On February 5, 2009, the DPSC issued an initial order approving the requested decrease, which became effective on March 1, 2009, subject to refund pending final DPSC approval after evidentiary hearings. A hearing is scheduled for May 27, 2009.

District of Columbia

In December 2006, Pepco submitted an application to the DCPSC to increase electric distribution base rates, including a proposed BSA. In January 2008, the DCPSC approved, effective February 20, 2008, a revenue requirement increase of approximately $28 million, based

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on an authorized return on rate base of 7.96%, including a 10% return on equity (ROE). This increase did not include a BSA mechanism. While finding a BSA to be an appropriate ratemaking concept, the DCPSC cited potential statutory problems in its authority to implement the BSA. In February 2008, the DCPSC established a Phase II proceeding to consider these implementation issues. In August 2008, the DCPSC issued an order concluding that it has the necessary statutory authority to implement the BSA proposal and that further evidentiary proceedings are warranted to determine whether the BSA is just and reasonable. On January 2, 2009, the DCPSC issued an order designating the issues and establishing a procedural schedule for the BSA proceeding. Hearings are scheduled for May 12 and 13, 2009.

In June 2008, the District of Columbia Office of People’s Counsel (the DC OPC), citing alleged errors by the DCPSC, filed with the DCPSC a motion for reconsideration of the January 2008 order granting Pepco’s rate increase. The DC OPC’s motion was denied by the DCPSC and, in August 2008, the DC OPC filed with the District of Columbia Court of Appeals a petition for review of the DCPSC’s order of denial. The District of Columbia Court of Appeals granted the petition; briefs have been filed by the parties and oral argument was held on March 23, 2009. Pepco expects a decision by the end of the second quarter 2009.

Maryland

In July 2007, the MPSC issued orders in the electric service distribution rate cases filed by DPL and Pepco, each of which included approval of a BSA. The DPL order approved an annual increase in distribution rates of approximately $15 million (including a decrease in annual depreciation expense of approximately $1 million). The Pepco order approved an annual increase in distribution rates of approximately $11 million (including a decrease in annual depreciation expense of approximately $31 million). In each case, the approved distribution rate reflects an ROE of 10%. The rate increases were effective as of June 16, 2007, and remained in effect for an initial period until July 19, 2008, pending a Phase II proceeding in which the MPSC considered the results of audits of each company’s cost allocation manual, as filed with the MPSC, to determine whether a further adjustment to the rates was required. In July 2008, the MPSC issued one order covering the Phase II proceedings for both DPL and Pepco, denying any further adjustment to the rates for each company, thus making permanent the rate increases approved in the July 2007 orders. The MPSC also issued an order in August 2008, further explaining its July 2008 order.

DPL and Pepco each appealed the MPSC’s July 2007, July 2008 and August 2008 orders. The case currently is pending before the Circuit Court for Baltimore City, which issued an order consolidating the appeals on January 27, 2009. In a consolidated brief filed on March 9, 2009, Pepco and DPL each contend that the MPSC erred in failing to implement permanent rates in accordance with Maryland law, and in its denial of their respective rights to recover an increased share of the PHI Service Company costs and the costs of performing a MPSC-mandated management audit. The MPSC and OPC filed briefs on April 23, 2009 and a hearing is scheduled for May 12, 2009.

New Jersey

On February 20, 2009, ACE filed an application with the NJBPU (supplemented on February 23, 2009), which included a proposal for the implementation of a BSA similar to the BSA approved for Pepco and DPL customers in Maryland and Pepco customers in the District of

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Columbia. Applicable New Jersey law requires that the NJBPU approve, modify or deny the application within 180 days. The NJBPU has advised ACE that the 180-day period commenced on February 23, 2009 and, therefore, ACE anticipates that NJBPU will act on ACE’s application, including the BSA request, by late August 2009.

Divestiture Cases

District of Columbia

In June 2000, the DCPSC approved a divestiture settlement under which Pepco is required to share with its District of Columbia customers the net proceeds realized by Pepco from the sale of its generation-related assets. An unresolved issue relating to the application filed with the DCPSC by Pepco to implement the divestiture settlement is 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. As of March 31, 2009, the District of Columbia allocated portions of EDIT and ADITC associated with the divested generating assets were approximately $6 million each. Other issues in the divestiture proceeding deal with the treatment of internal costs and cost allocations as deductions from the gross proceeds of the divestiture.

Pepco believes that a sharing of EDIT and ADITC would violate the IRS normalization rules. Under these rules, Pepco could not transfer the EDIT and the ADITC benefit to customers more quickly than on a straight line basis over the book life of the related assets. Since the assets are no longer owned by Pepco, there is no book life over which the EDIT and ADITC can be returned. If Pepco were required to share EDIT and ADITC and, as a result, the normalization rules were violated, Pepco would be unable to use accelerated depreciation on District of Columbia allocated or assigned property. In addition to sharing with customers the generation-related EDIT and ADITC balances, Pepco would have to pay to the IRS an amount equal to Pepco’s District of Columbia jurisdictional generation-related ADITC balance ($6 million as of March 31, 2009), as well as its District of Columbia jurisdictional transmission and distribution-related ADITC balance ($3 million as of March 31, 2009) in each case as those balances exist as of the later of the date a DCPSC order is issued and all rights to appeal have been exhausted or lapsed, or the date the DCPSC order becomes operative.

In March 2008, the IRS approved final regulations, effective March 20, 2008, which allow utilities whose assets cease to be utility property (whether by disposition, deregulation or otherwise) to return to its utility customers the normalization reserve for EDIT and part or all of the normalization reserve for ADITC. This ruling applies to assets divested after December 21, 2005. For utility property divested on or before December 21, 2005, the IRS stated that it would continue to follow the holdings set forth in private letter rulings prohibiting the flow through of EDIT and ADITC associated with the divested assets. Pepco made a filing in April 2008, advising the DCPSC of the adoption of the final regulations and requesting that the DCPSC issue an order consistent with the IRS position. If the DCPSC issues the requested order, no accounting adjustments to the gain recorded in 2000 would be required.

As part of the proposal filed with the DCPSC in November 2008 concerning the sharing of the proceeds of the Mirant settlement, as discussed above under “Proceeds from Settlement of Mirant Bankruptcy Claims,” Pepco again requested that the DCPSC rule on all of the issues

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related to the divestiture of Pepco’s generating assets that remain outstanding. On March 5, 2009, the DCPSC issued an order approving Pepco’s proposal for sharing the remaining balance of the proceeds from the Mirant settlement; however, the DCPSC did not rule on the other outstanding issues concerning the divestiture of Pepco’s generating assets.

Pepco believes that its calculation of the District of Columbia customers’ share of divestiture proceeds is correct. However, depending on the ultimate outcome of this proceeding, Pepco could be required to make additional gain-sharing payments to District of Columbia customers, including the payments described above related to EDIT and ADITC. Such additional payments (which, other than the EDIT and ADITC related payments, cannot be estimated) would be charged to expense in the quarter and year in which a final decision is rendered and could have a material adverse effect on Pepco’s and PHI’s results of operations for those periods. However, neither PHI nor Pepco believes that additional gain-sharing payments, if any, or the ADITC-related payments to the IRS, if required, would have a material adverse impact on its financial position or cash flows.

Maryland

Pepco filed its divestiture proceeds plan application with the MPSC in April 2001. The principal issue in the Maryland case is the same EDIT and ADITC sharing issue that has been raised in the District of Columbia case. See the discussion above under “Divestiture Cases — District of Columbia.” As of March 31, 2009, the Maryland allocated portions of EDIT and ADITC associated with the divested generating assets were approximately $9 million and $10 million, respectively. Other issues deal with the treatment of certain costs as deductions from the gross proceeds of the divestiture. In November 2003, the Hearing Examiner in the Maryland proceeding issued a proposed order with respect to the application that concluded that Pepco’s Maryland divestiture settlement agreement provided for a sharing between Pepco and customers of the EDIT and ADITC associated with the sold assets. Pepco believes that such a sharing would violate the normalization rules (as discussed above) and would result in Pepco’s inability to use accelerated depreciation on Maryland allocated or assigned property. If the proposed order is affirmed, Pepco would have to share with its Maryland customers, on an approximately  ⁵⁰/50 basis, the Maryland allocated portion of the generation-related EDIT ($9 million as of March 31, 2009), and the Maryland-allocated portion of generation-related ADITC. Furthermore, Pepco would have to pay to the IRS an amount equal to Pepco’s Maryland jurisdictional generation-related ADITC balance ($10 million as of March 31, 2009), as well as its Maryland retail jurisdictional ADITC transmission and distribution-related balance ($6 million as of March 31, 2009), in each case as those balances exist as of the later of the date a MPSC order is issued and all rights to appeal have been exhausted or lapsed, or the date the MPSC order becomes operative. The Hearing Examiner decided all other issues in favor of Pepco, except for the determination that only one-half of the severance payments that Pepco included in its calculation of corporate reorganization costs should be deducted from the sales proceeds before sharing of the net gain between Pepco and customers.

In December 2003, Pepco appealed the Hearing Examiner’s decision to the MPSC as it relates to the treatment of EDIT and ADITC and corporate reorganization costs. The MPSC has not issued any ruling on the appeal, pending completion of the IRS rulemaking regarding sharing of EDIT and ADITC related to divested assets. Pepco made a filing in April 2008, advising the MPSC of the adoption of the final IRS normalization regulations (described above under “Divestiture Cases — District of Columbia”) and requesting that the MPSC issue a ruling on the appeal consistent with the IRS position.

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As part of the proposal filed with the MPSC in November 2008 concerning the sharing of the proceeds of the Mirant settlement, as discussed above under “Proceeds from Settlement of Mirant Bankruptcy Claims,” Pepco again requested that the MPSC rule on all of the issues related to the divestiture of Pepco’s generating assets that remain outstanding.

On February 17, 2009, Pepco, the Maryland OPC and the MPSC staff filed a settlement agreement with the MPSC with respect to all of the open divesture plan issues. The settlement agreement, among other things, provides that Pepco would be allowed to retain the EDIT and ADITC reserves associated with Pepco’s divested generating assets and that none of those amounts would be available for sharing with Pepco’s Maryland customers. A hearing before the MPSC on the settlement is scheduled for May 14, 2009. If the settlement is approved, no accounting adjustments to the gain recorded in 2000 would be required.

ACE Sale of B.L. England Generating Facility

In February 2007, ACE completed the sale of the B.L. England generating facility to RC Cape May Holdings, LLC (RC Cape May), an affiliate of Rockland Capital Energy Investments, LLC. In July 2007, ACE received a claim for indemnification from RC Cape May under the purchase agreement in the amount of $25 million. RC Cape May contends that one of the assets it purchased, a contract for terminal services (TSA) between ACE and Citgo Asphalt Refining Co. (Citgo), has been declared by Citgo to have been terminated due to a failure by ACE to renew the contract in a timely manner. RC Cape May has commenced an arbitration proceeding against Citgo seeking a determination that the TSA remains in effect and has notified ACE of the proceeding. The claim for indemnification seeks payment from ACE in the event the TSA is held not to be enforceable against Citgo. While ACE believes that it has defenses to the indemnification claim, should the arbitrator rule that the TSA has terminated, the outcome of this matter is uncertain. The arbitration hearings were conducted in November 2008 and the parties filed post-hearing memoranda in the first quarter of 2009. A decision is expected late in the second quarter of 2009.

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

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plaintiff or by the court. As of March 31, 2009, there are approximately 180 cases still pending against Pepco in the State Courts of Maryland, of which approximately 90 cases were filed after December 19, 2000, and were tendered to Mirant for defense and indemnification pursuant to the terms of the Asset Purchase and Sale Agreement between Pepco and Mirant under which Pepco sold its generation assets to Mirant in 2000.

While the aggregate amount of monetary damages sought in the remaining suits (excluding those tendered to Mirant) is approximately $360 million, PHI and Pepco believe the amounts claimed by the remaining plaintiffs are greatly exaggerated. The amount of total liability, if any, and any related insurance recovery cannot be determined at this time; however, based on information and relevant circumstances known at this time, neither PHI nor Pepco believes these suits will have a material adverse effect on its financial position, 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 position, results of operations or cash flows.

Cash Balance Plan Litigation

In 1999, Conectiv established a cash balance retirement plan to replace defined benefit retirement plans then maintained by ACE and DPL. Following the acquisition by Pepco of Conectiv, this plan became the Conectiv Cash Balance Sub-Plan within the PHI Retirement Plan. In September 2005, three management employees of PHI Service Company filed suit in the U.S. District Court for the District of Delaware (the Delaware District Court) against the PHI Retirement Plan, PHI and Conectiv (the PHI Parties), alleging violations of the Employee Retirement Income Security Act of 1974 (ERISA), on behalf of a class of management employees who did not have enough age and service when the Cash Balance Sub-Plan was implemented in 1999 to assure that their accrued benefits would be calculated pursuant to the terms of the predecessor plans sponsored by ACE and DPL. A fourth plaintiff was added to the case to represent DPL-legacy employees who were not eligible for grandfathered benefits.

The plaintiffs challenged the design of the Cash Balance Sub-Plan and sought a declaratory judgment that the Cash Balance Sub-Plan was invalid and that the accrued benefits of each member of the class should be calculated pursuant to the terms of the predecessor plans. Specifically, the complaint alleged that the use of a variable rate to compute the plaintiffs’ accrued benefit under the Cash Balance Sub-Plan resulted in reductions in the accrued benefits that violated ERISA. The complaint also alleged that the benefit accrual rates and the minimal accrual requirements of the Cash Balance Sub-Plan violated ERISA as did the notice that was given to plan participants upon implementation of the Cash Balance Sub-Plan.

In September 2007, the Delaware District Court issued an order granting summary judgment in favor of the PHI Parties. In October 2007, the plaintiffs filed an appeal of the decision to the U.S. Court of Appeals for the Third Circuit (the Third Circuit). In November 2008, the Third Circuit affirmed the Delaware District Court ruling. On December 16, 2008, the Third Circuit denied a petition for rehearing filed by the plaintiffs. Plaintiffs had until March 23, 2009, to petition the U.S. Supreme Court for review of the Third Circuit decision, but did not file such petition; therefore the Third Circuit decision is final.

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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.

Delilah Road Landfill Site. In 1991, the New Jersey Department of Environmental Protection (NJDEP) identified ACE as a potentially responsible party (PRP) at the Delilah Road Landfill site in Egg Harbor Township, New Jersey. In 1993, ACE, along with two other PRPs, signed an administrative consent order with NJDEP to remediate the site. The soil cap remedy for the site has been implemented and in August 2006, NJDEP issued a No Further Action Letter (NFA) and Covenant Not to Sue for the site. Among other things, the NFA requires the PRPs to monitor the effectiveness of institutional (deed restriction) and engineering (cap) controls at the site every two years. In September 2007, NJDEP approved the PRP group’s petition to conduct semi-annual, rather than quarterly, ground water monitoring for two years and deferred until the end of the two-year period a decision on the PRP group’s request for annual groundwater monitoring thereafter. In August 2007, the PRP group agreed to reimburse the costs of the U.S. Environmental Protection Agency (EPA) in the amount of $81,400 in full satisfaction of EPA’s claims for all past and future response costs relating to the site (of which ACE’s share is one-third). Effective April 2008, EPA and the PRP group entered into a settlement agreement which will allow EPA to reopen the settlement in the event of new information or unknown conditions at the site. Based on information currently available, ACE anticipates that its share of additional cost associated with this site for post-remedy operation and maintenance will be approximately $555,000 to $600,000. On November 23, 2008, Lenox, Inc., a member of the PRP group, filed a bankruptcy petition under Chapter 11 of the U.S. Bankruptcy Code. ACE filed a proof of claim in the Lenox bankruptcy case in February 2009. ACE believes that its liability for post-remedy operation and maintenance costs will not have a material adverse effect on its financial position, results of operations or cash flows regardless of the impact of the Lenox bankruptcy.

Frontier Chemical Site. In June 2007, ACE received a letter from the New York Department of Environmental Conservation (NYDEC) identifying ACE as a PRP at the Frontier Chemical Waste Processing Company site in Niagara Falls, N.Y. based on hazardous waste manifests indicating that ACE sent in excess of 7,500 gallons of manifested hazardous waste to the site. ACE has entered into an agreement with the other parties identified as PRPs to form a PRP group and has informed NYDEC that it has entered into good faith negotiations with the PRP group to address ACE’s responsibility at the site. ACE believes that its responsibility at the site will not have a material adverse effect on its financial position, results of operations or cash flows.

Franklin Slag Pile Superfund Site. On November 26, 2008, ACE received a general notice letter from EPA concerning the Franklin Slag Pile Superfund Site in Philadelphia,

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Pennsylvania, asserting that ACE is a 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. The EPA’s claims are based on ACE’s sale of boiler slag from the B.L. England generating facility to MDC Industries, Inc. (MDC) during the period June 1978 to May 1983 (ACE owned B.L. England at that time and MDC formerly operated the Franklin Slag Pile Site). EPA further 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’s letter also states that to date its expenditures for response measures at the site exceed $6 million. EPA estimates approximately $6 million as the cost for future response measures it recommends. ACE understands that the 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, such 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 such claims made by the EPA. At this time ACE cannot predict how EPA will proceed or what portion, if any, of the Franklin Slag Pile Site response costs EPA would seek to recover from ACE.

Deepwater Generating Station Revocation Order. In December 2005, NJDEP issued a Title V operating permit (the 2005 Permit) to Deepwater Generating Station (Deepwater) owned by Conectiv Energy. Conectiv Energy appealed several provisions of the 2005 Permit and a revised Title V operating permit issued in 2008 (the 2008 Permit). Administrative litigation concerning the provisions of both operating permits has been ongoing.

In February 2008, NJDEP issued an Administrative Order of Revocation and Notice of Civil Administrative Penalty Assessment (the First Revocation Order) revoking the Deepwater operating permit. The First Revocation Order is based on the NJDEP’s contention that Deepwater Unit 6/8 operated in violation of its emission limit for hydrogen chloride (HCl) and total suspended particles (TSP) during a December 2007 stack test. The First Revocation Order also assessed a $20,000 penalty for the HCl incident and a $10,000 penalty for the TSP incident. Conectiv Energy has filed an appeal of the First Revocation Order with the Office of Administrative Law. Subsequent stack tests have confirmed that Unit 6/8 complies with its TSP emission limit and on January 14, 2009, Conectiv Energy and NJDEP entered into a settlement agreement that resolves the $10,000 penalty for TSP from the First Revocation Order. Under the terms of the settlement agreement, NJDEP agreed to not assess an additional $16,000 administrative penalty for an alleged violation of the TSP limit during an April 4, 2008 stack test and Conectiv Energy agreed to pay a $20,800 penalty. The appeal of the penalty for the HCl incident remains pending.

In July 2008, NJDEP issued an Administrative Order of Revocation and Notice of Civil Administrative Penalty Assessment (the Second Revocation Order) revoking the Deepwater operating permit. The Second Revocation Order is based on the NJDEP’s contention that Deepwater Unit 6/8 operated in violation of its emission limit for particulate matter less than 10 microns (PM-10) during the December 2007 stack test. The Second Revocation Order also assessed a penalty for the incident in the amount of $10,000. Conectiv Energy has filed an appeal of the Second Revocation Order with the Office of Administrative Law. NJDEP has

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issued a letter stating that elevated PM-10 levels indicated during the July 2008 stack test were the result of laboratory error. Subsequent stack testing has shown that Unit 6/8 complies with its PM-10 emission limit.

In September 2008, NJDEP issued an Administrative Order of Revocation and Notice of Civil Administrative Penalty Assessment (the Third Revocation Order) requiring Conectiv Energy to operate Deepwater Unit 6/8 in compliance with its HCl limit or in the alternative revoking Unit 6/8’s operating permit effective October 21, 2008. The Third Revocation Order is based on the NJDEP’s contention that Unit 6/8 violated the HCl limit on 106 days between December 5, 2007 and April 24, 2008 stack tests. The Third Revocation Order assessed a penalty of approximately $5 million. Conectiv Energy has appealed the Third Revocation Order with the Office of Administrative Law. The effectiveness of each of the three revocation orders has been stayed by the NJDEP through May 28, 2009.

Conectiv Energy is operating Deepwater 6/8 while firing coal at a reduced load, or at full load with lime injection, to comply with the challenged HCl permit limit at all potential coal chloride contents. Operation with lime injection was authorized by the Environmental Improvement Pilot Test permit issued by NJDEP in September 2008, which facilitates assessment of the feasibility and practicality of hydrated lime injection technology in controlling HCl emissions from Unit 6/8 at full load without significantly impacting boiler operations. Testing indicates that hydrated lime injection technology effectively controls HCl emissions without significantly impacting boiler operations and without affecting Conectiv Energy’s ability to meet emissions limits for other parameters. Conectiv Energy has not yet determined the costs of converting the hydrated lime injection from a temporary pollution control device to a permanent pollution control device.

Conectiv Energy believes that it has strong legal arguments that NJDEP cannot revoke the permit prior to an administrative hearing and believes that the probability of a complete shut-down of the unit is low because the unit appears to be in compliance with the HCl limit. In addition, Conectiv Energy believes that its appeal asserts strong arguments against the assessment of this penalty.

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, which took effect November 5, 2007, 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 that was previously unregulated under the FHACA and that is otherwise regulated under a number of other state and federal programs. ACE filed an appeal of these regulations with the Appellate Division of the Superior Court of New Jersey on November 3, 2008.

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

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commonly referred to as a sale-in/lease-out or SILO transaction. PHI’s annual tax benefits from these eight cross-border energy lease investments are approximately $56 million. As of March 31, 2009, PHI’s equity investment in its cross-border energy leases was approximately $1.3 billion which included the impact of the reassessment discussed below. During the open tax periods under audit from January 1, 2001 to March 31, 2009, PHI has derived approximately $475 million in federal income tax benefits from the depreciation and interest deductions in excess of rental income with respect to these cross-border energy lease investments, which includes the effect of the reassessment discussed below.

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 RAR issued in June 2006 in connection with the audit of PHI’s 2001 and 2002 income tax returns, the IRS disallowed the depreciation and interest deductions in excess of rental income claimed by PHI with respect to six of its cross-border energy lease investments. In addition, the IRS has sought to recharacterize the six leases as loan transactions as to which PHI would be subject to original issue discount income. PHI is protesting the IRS adjustments and the unresolved audit issues have been forwarded to the Appeals Office. PHI is in the early stages of discussions with the Appeals Office. If these discussions are unsuccessful, PHI currently intends to pursue litigation proceedings against the IRS to defend its tax position. On March 31, 2009, the IRS issued its RAR for the calendar years 2003 to 2005 which proposes to disallow the depreciation and interest deductions in excess of rental income claimed by PHI with respect to all eight of its cross-border energy lease investments and recharacterize the eight leases as loan transactions as to which PHI would be subject to original issue discount income. PHI plans to file a protest with respect to these proposed adjustments.

In the last several years, IRS challenges to certain cross-border lease transactions have been the subject of litigation. This litigation has resulted in several decisions in favor of the IRS, including two decisions in the second quarter of 2008. In one of the cases decided in the second quarter relating to a lease-in/lease-out transaction, a United States Court of Appeals upheld a lower court decision in favor of the IRS to disallow the tax benefits taken by the taxpayer. In the second case, a United States District Court rendered an opinion concerning a SILO transaction in which it upheld the IRS’s disallowance of tax benefits taken by the taxpayer. Under FIN 48, “Accounting for Uncertainty in Income Taxes,” the financial statement recognition of an uncertain tax position is permitted only if it is more likely than not that the position will be sustained. Further, under FSP 13-2, “Accounting for a Change in the Timing of Cash Flows Relating to Income Taxes Generated by a Leveraged-lease Transaction,” a company is required to assess on a periodic basis the likely outcome of tax positions relating to its cross-border energy lease investments and, if there is a change or a projected change in the timing of the tax benefits generated by the transactions, the company is required to recalculate the value of its equity investment.

While PHI believes that its tax position with regard to its cross-border energy lease investments is appropriate based on applicable statutes, regulations and case law, after evaluating the court rulings described above, PHI at June 30, 2008 reassessed the sustainability of its tax position and revised its assumptions regarding the estimated timing of the tax benefits from its

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cross-border energy lease investments. Based on this reassessment, PHI for the quarter ended June 30, 2008, recorded an after-tax charge to net income of $93 million, consisting of the following components:

• A non-cash pre-tax charge of $124 million ($86 million after tax) under FSP 13-2 to reduce the equity value of these cross-border energy lease investments. This pre-tax charge has been recorded in the Consolidated Statement of Earnings as a reduction in other operating revenue.

• A non-cash charge of $7 million after-tax to reflect the anticipated additional interest expense under FIN 48 on the estimated federal and state income tax that would be payable for the period January 1, 2001 through June 30, 2008, based on the revised assumptions regarding the estimated timing of the tax benefits. This after-tax charge has been recorded in the Consolidated Statement of Earnings as an increase in income tax expense.

The charge pursuant to FSP 13-2 reflects changes to the book equity value of the cross-border energy lease investments and the pattern of recognizing the related cross-border energy lease income. This amount will be recognized as income over the remaining term of the affected leases, which expire between 2017 and 2047. The tax benefits associated with the lease transactions represent timing differences that do not change the aggregate amount of the lease net income over the life of the transactions. Beginning with the 2007 tax return, PHI has filed its federal and state tax returns consistent with the revised assumptions regarding the estimated timing of the tax benefits. Excluding the adjustment of tax payments made on the 2007 and subsequent tax returns, PHI has made no additional cash payments of federal or state income taxes or interest thereon as a result of the reassessment discussed above. Whether PHI makes an additional payment, and the amount and the timing thereof, will depend on a number of factors, including PHI’s litigation strategy, whether a settlement with the IRS can be reached or whether the company decides to deposit funds with the IRS to avoid higher interest costs, until the issue is resolved. PHI is continuing to defend vigorously its tax position with the IRS.

In connection with the recording of the above adjustment, PHI calculated as of June 30, 2008, the additional non-cash charge to earnings that would have been recorded and the cash outflow that would have been required resulting from the disallowance of the entire amount of the tax benefits from the depreciation and interest deductions in excess of rental income and the recharacterization of the transactions as loans over the period from January 1, 2001 through the end of the lease term.

• PHI would have incurred an additional non-cash charge to earnings at June 30, 2008 of approximately $346 million consisting of a non-cash charge of $324 million ($293 million after tax) under FSP 13-2 to further reduce the equity value of these cross-border energy lease investments and a non-cash charge of $53 million after-tax to reflect the anticipated additional interest expense under FIN 48 on the estimated federal and state income tax for the period from January 1, 2001 through June 30, 2008.

• PHI would have been obligated to pay, as of June 30, 2008, approximately $510 million in additional federal and state taxes (including the $458 million of tax

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benefits received from 2001 to date) and $63 million of interest (which amounts include $107 million of federal and state income taxes and $10 million of interest referred to earlier in relation to the charge recorded).

As of March 31, 2009, no changes in the assumptions have occurred that would materially impact the June 30, 2008 estimates.

In the event of the total disallowance of the tax benefits and the imputing of original issue discount income due to the recharacterization of the leases as loans, as of March 31, 2009, PHI would have been obligated to pay approximately $520 million in additional federal and state taxes and $88 million of interest. In addition, the IRS could require PHI to pay a penalty of up to 20% on the amount of additional taxes due. PHI anticipates that any additional taxes that it would be required to pay as a result of the disallowance of prior deductions or a recharacterization of the leases as loans would be recoverable in the form of lower taxes over the remaining term of the investments.

On August 7, 2008, PHI received a global settlement offer from the IRS with respect to its SILO transactions. PHI is continuing its discussion with the Appeals Office and has not responded to the global settlement offer.

IRS Mixed Service Cost Issue

During 2001, Pepco, DPL, and ACE changed their methods of accounting with respect to capitalizable construction costs for income tax purposes. The change allowed the companies to accelerate the deduction of certain expenses that were previously capitalized and depreciated. As a result of this method change, PHI generated incremental tax cash flow benefits of approximately $205 million (consisting of $94 million for Pepco, $62 million for DPL, and $49 million for ACE).

In 2005, the IRS issued Revenue Ruling 2005-53, which limited the ability of Pepco, DPL and ACE to utilize its tax accounting method on their 2001 through 2004 tax returns. Based on the Revenue Ruling and other Treasury Department guidance, PHI in its 2005 federal tax return adopted an alternative method of accounting for capitalizable construction costs that management believed would be acceptable to the IRS.

In line with this Revenue Ruling, the RAR for the 2001 and 2002 tax returns disallowed substantially all of the incremental tax benefits that Pepco, DPL and ACE had claimed on those returns by requiring the companies to capitalize and depreciate certain expenses rather than treat such expenses as current deductions.

In March 2009, PHI reached a settlement with the IRS for all years (2001 through 2004) that is consistent with the approach adopted on the 2005 federal tax return. The terms of the settlement reduced the tax benefits related to the mixed service costs deductions by $35 million ($17 million for Pepco, $12 million for DPL and $6 million for ACE) from $205 million claimed on originally filed returns to $170 million.

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

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

As of March 31, 2009, 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		Other		Total
Energy marketing obligations of Conectiv Energy (a)	$	192	$	—	$	—	$	—	$	192
Energy procurement obligations of Pepco Energy Services (a)		610		—		—		—		610
Guaranteed lease residual values (b)		—		3		2		1		6
Other (c)		2		—		—		1		3
Total	$	804	$	3	$	2	$	2	$	811

(a) Pepco Holdings has contractual commitments for performance and related payments of Conectiv Energy and Pepco Energy Services to counterparties under routine energy sales and procurement obligations, including retail customer load obligations of Pepco Energy Services and requirements under BGS contracts entered into by Conectiv Energy with ACE.

(b) 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, 2009, obligations under the guarantees were approximately $6 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 minimal. As such, Pepco Holdings believes the likelihood of payment being required under the guarantee is remote.

(c) Other guarantees consist of:

• Pepco Holdings has guaranteed a subsidiary building lease of $2 million. Pepco Holdings does not expect to fund the full amount of the exposure under the guarantee.

• PCI has guaranteed facility rental obligations related to contracts entered into by Starpower Communications, LLC, a joint venture in which PCI prior to December 2004 had a 50% interest. As of March 31, 2009, the guarantees cover the remaining $1 million in rental obligations.

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.

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Dividends

On April 23, 2009, Pepco Holdings’ Board of Directors declared a dividend on common stock of 27 cents per share payable June 30, 2009, to shareholders of record on June 10, 2009.

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POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF EARNINGS

(Unaudited)

	Three Months Ended March 31,
	2009			2008
	(millions of dollars)
Operating Revenue	$	577		$	525
Operating Expenses
Purchased energy		349			308
Other operation and maintenance		79			70
Depreciation and amortization		35			34
Other taxes		73			70
Effect of settlement of Mirant bankruptcy claims		(14	)		—
Total Operating Expenses		522			482
Operating Income		55			43
Other Income (Expenses)
Interest and dividend income		1			4
Interest expense		(25	)		(24	)
Other income		2			3
Other expenses		—			(1	)
Total Other Expenses		(22	)		(18	)
Income Before Income Tax Expense		33			25
Income Tax Expense		14			10
Net Income		19			15
Retained Earnings at Beginning of Period		624			597
Dividends Paid to Parent		—			(20	)
Retained Earnings at End of Period	$	643		$	592

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

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POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

(Unaudited)

	March 31, 2009			December 31, 2008
	(millions of dollars)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	356		$	146
Accounts receivable, less allowance for uncollectible accounts of $14 million and $15 million, respectively		363			377
Inventories		49			45
Prepayments of income taxes		72			151
Prepaid expenses and other		36			37
Total Current Assets		876			756
INVESTMENTS AND OTHER ASSETS
Regulatory assets		154			169
Prepaid pension expense		137			142
Investment in trust		24			24
Restricted cash equivalents		64			102
Income taxes receivable		194			166
Assets and accrued interest related to uncertain tax positions		4			35
Other		65			70
Total Investments and Other Assets		642			708
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		5,666			5,607
Accumulated depreciation		(2,399	)		(2,371	)
Net Property, Plant and Equipment		3,267			3,236
TOTAL ASSETS	$	4,785		$	4,700

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

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POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

(Unaudited)

	March 31, 2009		December 31, 2008
	(millions of dollars, except shares)
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Short-term debt	$	125	$	125
Current maturities of long-term debt		16		50
Accounts payable and accrued liabilities		158		187
Accounts payable due to associated companies		70		70
Capital lease obligations due within one year		6		6
Taxes accrued		47		44
Interest accrued		39		19
Liabilities and accrued interest related to uncertain tax positions		—		38
Other		136		94
Total Current Liabilities		597		633
DEFERRED CREDITS
Regulatory liabilities		242		239
Deferred income taxes, net		786		788
Investment tax credits		10		10
Other postretirement benefit obligation		48		49
Income taxes payable		132		137
Other		78		65
Total Deferred Credits		1,296		1,288
LONG-TERM LIABILITIES
Long-term debt		1,539		1,445
Capital lease obligations		99		99
Total Long-Term Liabilities		1,638		1,544
COMMITMENTS AND CONTINGENCIES (NOTE 10)
EQUITY
Common stock, $.01 par value, authorized 200,000,000 shares, issued 100 shares		—		—
Premium on stock and other capital contributions		611		611
Retained earnings		643		624
Total Equity		1,254		1,235
TOTAL LIABILITIES AND EQUITY	$	4,785	$	4,700

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

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POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
	2009			2008
	(millions of dollars)
OPERATING ACTIVITIES
Net income	$	19		$	15
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		35			34
Effect of settlement of Mirant bankruptcy claims		(14	)		—
Changes in restricted cash related to Mirant		38			—
Deferred income taxes		8			23
Changes in:
Accounts receivable		14			21
Regulatory assets and liabilities, net		28			(5	)
Accounts payable and accrued liabilities		(16	)		(6	)
Interest accrued		20			16
Taxes accrued		91			(22	)
Other changes in working capital		(10	)		(5	)
Net other operating		11			7
Net Cash From Operating Activities		224			78
INVESTING ACTIVITIES
Investment in property, plant and equipment		(67	)		(59	)
Net other investing activities		2			(7	)
Net Cash Used By Investing Activities		(65	)		(66	)
FINANCING ACTIVITIES
Dividends paid to Parent		—			(20	)
Capital contribution from Parent		—			78
Issuances of long-term debt		110			250
Reacquisition of long-term debt		(50	)		(78	)
Repayments of short-term debt, net		—			(180	)
Net other financing activities		(9	)		(20	)
Net Cash From Financing Activities		51			30
Net Increase in Cash and Cash Equivalents		210			42
Cash and Cash Equivalents at Beginning of Period		146			19
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	356		$	61
NONCASH ACTIVITIES
Asset retirement obligations associated with removal costs transferred to regulatory liabilities	$	2		$	3
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash (received) paid for income taxes (includes payments to PHI for Federal income taxes)	$	(81	)	$	2

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

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NOTES TO FINANCIAL STATEMENTS

POTOMAC ELECTRIC POWER COMPANY

(1) ORGANIZATION

Potomac Electric Power Company (Pepco) is engaged in the transmission and distribution of electricity in Washington, D.C. and major portions of Prince George’s County and Montgomery County in suburban Maryland. Pepco provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its territories who do not elect to purchase electricity from a competitive supplier, in both the District of Columbia and Maryland. 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, 2008. 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, 2009, in accordance with GAAP. The year-end balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP. Interim results for the three months ended March 31, 2009 may not be indicative of results that will be realized for the full year ending December 31, 2009 since the sales of electric energy are seasonal.

Consolidation of Variable Interest Entities

Due to a variable element in the pricing structure of Pepco’s purchase power agreement with Panda-Brandywine, L.P. (Panda) entered into in 1991, pursuant to which Pepco was obligated to purchase from Panda 230 megawatts of capacity and energy annually through 2021 (Panda PPA), Pepco potentially assumes the variability in the operations of the plants related to the Panda PPA and therefore has a variable interest in the entity. During the third quarter of 2008, Pepco transferred the Panda PPA to Sempra Energy Trading LLP (Sempra). Net purchase activities with the counterparty to the Panda PPA for the three months ended March 31, 2008 were approximately $20 million.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in Pepco’s gross revenues were $61 million and $57 million for the three months ended March 31, 2009 and 2008, respectively.

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Reclassifications

Certain prior period amounts have been reclassified in order to conform period to current period presentation.

(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Statement of Financial Accounting Standards (SFAS) No. 141(R), “Business Combinations—a Replacement of FASB Statement No. 141” (SFAS No. 141 (R))

SFAS No. 141(R) replaces Financial Accounting Standards Board (FASB) Statement No. 141, “Business Combinations,” and retains the fundamental requirements that the acquisition method of accounting be used for all business combinations and for an acquirer to be identified for each business combination. However, SFAS No. 141(R) expands the definition of a business and amends FASB Statement No. 109, “Accounting for Income Taxes,” to require the acquirer to recognize changes in the amount of its deferred tax benefits that are realizable because of a business combination either in income from continuing operations or directly in contributed capital, depending on the circumstances.

On April 1, 2009, the FASB issued FASB Staff Position (FSP) Financial Accounting Standard (FAS) 141(R)-1 “Accounting for Assets and Liabilities Assumed in a Business Combination that Arise from Contingencies” (FSP FAS 141(R)-1), to clarify the accounting for the initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. FSP FAS 141(R)-1 requires that assets acquired and liabilities assumed in a business combination that arise from contingencies be measured at fair value if the acquisition date fair value of that asset and liability can be determined during the measurement period in accordance with SFAS No. 157. If the acquisition date fair value cannot be determined, then the asset or liability would be measured in accordance with SFAS No. 5, “Accounting for Contingencies,” and FASB Interpretation Number 14, “Reasonable Estimate of the Amount of Loss.”

SFAS No. 141(R) and the guidance provided in FSP FAS 141(R)-1 applies prospectively to business combinations for which the acquisition date is on or after January 1, 2009. Pepco adopted SFAS No. 141(R) on January 1, 2009, and it did not have a material impact on Pepco’s overall financial condition, results of operations, or cash flows.

FSP 157-2, “Effective Date of FASB Statement No. 157” (FSP 157-2)

FSP 157-2 deferred the effective date of SFAS No. 157, “Fair Value Measurements,” for all nonrecurring fair value measurements of non-financial assets and non-financial liabilities until January 1, 2009 for Pepco. The adoption of SFAS No. 157 did not have a material impact on the fair value measurements of Pepco’s non-financial assets and non-financial liabilities.

SFAS No. 160, “Non-controlling Interests in Consolidated Financial Statements—an Amendment of ARB No. 51” (SFAS No. 160)

SFAS No. 160 establishes new accounting and reporting standards for a non-controlling interest (previously called minority interest) in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a non-controlling interest in a subsidiary is an ownership interest in the consolidated entity that should be separately reported in the consolidated financial statements.

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SFAS No. 160 establishes accounting and reporting standards that require (i) the ownership interests and the related consolidated net income in subsidiaries held by parties other than the parent be clearly identified, labeled, and presented in the consolidated balance sheets within equity, but separate from the parent’s equity, and presented separately on the face of the consolidated statement of earnings, (ii) the changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for as equity transactions, and (iii) when a subsidiary is deconsolidated, any retained non-controlling equity investment in the former subsidiary must be initially measured at fair value.

SFAS No. 160 was effective prospectively for financial statement reporting periods beginning January 1, 2009 for Pepco, except for the financial statement presentation and disclosure requirements which also apply to prior reporting periods presented. As of January 1, 2009, Pepco has adopted the provisions of SFAS No. 160, and the provisions did not have a material impact on Pepco’s overall financial condition, results of operations, or cash flows.

(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

FSP FAS 107-1 and Accounting Principles Board (APB) 28-1, “Interim Disclosures about Fair Value of Financial Instruments” (FSP FAS 107-1 and APB 28-1)

On April 9, 2009, the FASB issued FSP FAS 107-1 and APB 28-1, which require quarterly disclosures of the fair value of financial instruments beginning with the second quarter of 2009. Prior to FSP FAS 107-1 and APB 28-1, these disclosures were only required on an annual basis. The disclosures for prior reporting periods are required after initial adoption.

FSP FAS 107-1 and APB 28-1 are effective for interim reporting periods ending after June 15, 2009 with the option to early adopt for interim periods ending after March 15, 2009. Pepco elected not to early adopt; therefore, the disclosure requirements will be reflected in Pepco’s second quarter 2009 Form 10-Q. The primary impact of the new standard will be the quarterly disclosure of the fair value of debt issued by Pepco.

FSP FAS 115-2 and FAS 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments” (FSP FAS 115-2 and FAS 124-2)

On April 9, 2009, the FASB issued FSP FAS 115-2 and FAS 124-2, which provided additional guidance on other-than-temporary impairment (OTTI) of debt and equity securities. It requires disclosure of information about the credit and noncredit component of an OTTI event and when an OTTI event has occurred. The FSP requires separate display on the statements of earnings, of losses related to credit deterioration and losses related to other market factors. Market-related losses will be recorded in accumulated other comprehensive (losses) earnings if it is not likely that the investor will have to sell the security prior to recovery.

FSP 115-2 and FAS 124-2 are effective for interim reporting periods ending after June 15, 2009, with the option to early adopt for interim periods ending after March 15, 2009. Pepco elected not to early adopt. Pepco does not anticipate the adoption of FSP 115-2 and FAS 124-2 to have a material impact on Pepco’s overall financial condition, results of operations, or cash flows.

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(5) SEGMENT INFORMATION

In accordance with SFAS No. 131 “Disclosures about Segments of an Enterprise and Related Information,” Pepco has one segment, its regulated utility business.

(6) PENSIONS 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, 2009 before intercompany allocations from the PHI Service Company, of $31 million includes $8 million for Pepco’s allocated share. PHI’s pension and other postretirement net periodic benefit cost for the three months ended March 31, 2008, of $16 million, before intercompany allocations, included $6 million for Pepco’s allocated share.

(7) DEBT

PHI, Pepco, Delmarva Power and Light Company (DPL) and Atlantic City Electric Company (ACE) maintain an unsecured credit facility to provide for their respective short-term liquidity needs. The aggregate borrowing limit under the facility is $1.5 billion, all or any portion of which may be used to obtain loans or to issue letters of credit. PHI’s credit limit under the facility is $875 million. The credit limit of each of Pepco, DPL and ACE is the lesser of $500 million and the maximum amount of debt the company is permitted to have outstanding by its regulatory authorities, except that the aggregate amount of credit used by Pepco, DPL and ACE at any given time collectively may not exceed $625 million.

Pepco historically has issued commercial paper to meet its short-term working capital requirements. As a result of the recent disruptions in the commercial paper markets, Pepco has borrowed under the credit facility to create a cash reserve for future short-term operating needs. At March 31, 2009, Pepco had an outstanding loan of $100 million. The loan was repaid at maturity in April 2009.

In January 2009, Pepco redeemed $50 million of 6.25% medium-term notes at maturity.

In March 2009, Pepco resold $110 million of Pollution Control Revenue Refunding Bonds which previously had been issued for the benefit of Pepco by the Maryland Economic Development Corporation. Pepco purchased the bonds in 2008 in response to disruptions in the municipal auction rate securities market that made it difficult for the remarketing agent to successfully remarket the bonds. As the owner of the bonds, Pepco received the proceeds of the sale, which it intends to use for general corporate purposes.

In April 2009, Pepco repaid, prior to maturity, a $25 million short-term loan.

The continued disruptions in the capital and credit markets, combined with the volatility of energy prices, have had an impact on the borrowing capacity and liquidity of Pepco. Since the third quarter of 2008, to address the challenges posed by the current capital and credit market environment and to ensure that Pepco will continue to have sufficient access to cash to meet its liquidity needs,

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Pepco has taken several measures to reduce expenditures, issued $250 million in long-term debt securities and resold $110 million of Pollution Control Revenue Refunding Bonds (as discussed above).

(8) INCOME TAXES

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

	For the Three Months Ended March 31,
	2009		2008
Federal statutory rate	35.0	%	35.0	%
Increases (decreases) resulting from:
Depreciation	3.6		5.1
Asset removal costs	(1.8	)	(6.3	)
State income taxes, net of federal effect	5.8		6.7
Software amortization	1.2		2.4
Tax credits	(1.2	)	(2.0	)
Change in estimates and interest related to uncertain and effectively settled tax positions	1.8		(2.7	)
Permanent differences related to deferred compensation funding	(.6	)	2.0
Other, net	(1.4	)	—
Effective Income Tax Rate	42.4	%	40.2	%

Pepco’s effective tax rates for the three months ended March 31, 2009 and 2008 were 42.4% and 40.2%, respectively. The increase in the rate resulted from decreases in asset removal costs, the amortization of Investment Tax Credits, an increase in the change in estimates and interest related to uncertain and effectively settled tax positions, offset by a decrease in the flow-through of certain book tax depreciation and software amortization differences. The increase in the change in estimates and interest related to uncertain and effectively settled tax positions is primarily due to the non-recurring impact of a tax claim filed with the Internal Revenue Service (IRS) in March 2008. The claim was for the treatment of casualty losses as current deductions (as opposed to being depreciated over their tax lives) on prior year returns currently under audit.

In March 2009, the IRS issued its Revenue Agent’s Report (RAR) for the audit of PHI’s consolidated federal income tax returns for the calendar years 2003 to 2005. The IRS has proposed adjustments to PHI’s tax returns, including adjustments to Pepco’s capitalization of overhead costs for tax purposes and the deductibility of certain Pepco casualty losses. In conjunction with PHI, Pepco is taking steps to appeal certain of the proposed adjustments and believes it has adequately reserved for the adjustments included in the RAR.

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During the first quarter of 2009, primarily as a result of the RAR, Pepco reduced uncertain tax benefits by $26 million ($21 million as a result of settlements with taxing authorities and $5 million as adjustments to prior year tax positions).

(9) FAIR VALUE DISCLOSURES

Effective January 1, 2008, Pepco adopted SFAS No. 157 which established a framework for measuring fair value and expands disclosures about fair value measurements.

As defined in SFAS No. 157, 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. Pepco is able to classify fair value balances based on the observability of those inputs. SFAS No. 157 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 measurement) and the lowest priority to unobservable inputs (level 3 measurement). The three levels of the fair value hierarchy defined by SFAS No. 157 are 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 pricing 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, 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 investments that are valued using models or other valuation methodologies. Level 3 instruments classified as executive deferred compensation plan assets are life insurance policies that are valued using the cash surrender value of the policies. Since these values do not represent a quoted price in an active market they are considered level 3.

The following tables sets 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, 2009 and December 31, 2008. As required by SFAS No. 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Pepco’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

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	Fair Value Measurements at March 31, 2009
	(millions of dollars)
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
ASSETS
Cash equivalents	$	411	$	411	$	—	$	—
Executive deferred compensation plan assets		57		6		34		17
	$	468	$	417	$	34	$	17
LIABILITIES
Executive deferred compensation plan liabilities	$	12	$	—	$	12	$	—
	$	12	$	—	$	12	$	—

	Fair Value Measurements at December 31, 2008
	(millions of dollars)
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Levels)
ASSETS
Cash equivalents	$	236	$	236	$	—	$	—
Executive deferred compensation plan assets		59		7		35		17
	$	295	$	243	$	35	$	17
LIABILITIES
Executive deferred compensation plan liabilities	$	13	$	—	$	13	$	—
	$	13	$	—	$	13	$	—

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, 2009 and March 31, 2008 are shown below:

	Three Months Ended March 31, 2009
	Deferred Compensation Plan Assets
	(millions of dollars)
Beginning balance as of January 1, 2009	$	17
Total gains or (losses) (realized and unrealized)
Included in earnings		1
Included in accumulated other comprehensive (losses) earnings		—
Purchases and issuances		(1	)
Settlements		—
Transfers in and/or out of Level 3		—
Ending balance as of March 31, 2009	$	17
	Other Operation and Maintenance Expense
	(millions of dollars)
Gains or (losses) (realized and unrealized) included in earnings for the period above are reported in Other Operation and Maintenance Expense as follows:
Total gains included in earnings for the period above	$	1
Change in unrealized gains relating to assets still held at reporting date	$	1

	Three Months Ended March 31, 2008
	Deferred Compensation Plan Assets
	(millions of dollars)
Beginning balance as of January 1, 2008	$	16
Total gains or (losses) (realized and unrealized)
Included in earnings		1
Included in accumulated other comprehensive (losses) earnings		—
Purchases and issuances		(1	)
Settlements		—
Transfers in and/or out of Level 3		—
Ending balance as of March 31, 2008	$	16
	Other Operation and Maintenance Expense
	(millions of dollars)
Gains or (losses) (realized and unrealized) included in earnings for the period above are reported in Other Operation and Maintenance Expense as follows:
Total gains (losses) included in earnings for the period above	$	1
Change in unrealized gains (losses) relating to assets still held at reporting date	$	1

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(10) COMMITMENTS AND CONTINGENCIES

Regulatory and Other Matters

Proceeds from Settlement of Mirant Bankruptcy Claims

In 2000, Pepco sold substantially all of its electricity generating assets to Mirant Corporation (Mirant). As part of the sale, Pepco and Mirant entered into a “back-to-back” arrangement, whereby Mirant agreed to purchase from Pepco the 230 megawatts of electricity and capacity that Pepco was obligated to purchase annually through 2021 from Panda under the Panda PPA at the purchase price Pepco was obligated to pay to Panda. In 2003, Mirant commenced a voluntary bankruptcy proceeding in which it sought to reject certain obligations that it had undertaken in connection with the asset sale. As part of the settlement of Pepco’s claims against Mirant arising from the bankruptcy, Pepco agreed not to contest the rejection by Mirant of its obligations under the “back-to-back” arrangement in exchange for the payment by Mirant of damages corresponding to the estimated amount by which the purchase price that Pepco was obligated to pay Panda for the energy and capacity exceeded the market price. In 2007, Pepco received as damages $414 million in net proceeds from the sale of shares of Mirant common stock issued to it by Mirant. In September 2008, Pepco transferred the Panda PPA to Sempra, along with a payment to Sempra, thereby terminating all further rights, obligations and liabilities of Pepco under the Panda PPA. In November 2008, Pepco filed with the District of Columbia Public Service Commission (DCPSC) and the Maryland Public Service Commission (MPSC) proposals to share with customers the remaining balance of proceeds from the Mirant settlement in accordance with divestiture sharing formulas previously approved by the respective commissions.

On March 5, 2009, the DCPSC issued an order approving Pepco’s sharing proposal. Under the order and Pepco’s compliance filing tariff, which was deemed effective on March 20, 2009, approximately $24 million has been reflected in customers’ April 2009 bills as a one-time credit. As a result of this decision, Pepco recorded a pre-tax gain of approximately $14 million for the quarter ended March 31, 2009.

On February 17, 2009, Pepco, the Maryland Office of People’s Counsel (the Maryland OPC) and the MPSC staff filed a settlement agreement with the MPSC, which, among other things, provides that Pepco would distribute $39 million of the remaining balance of the Mirant settlement to its Maryland customers through a one-time billing credit. If the settlement is approved by the MPSC, Pepco currently estimates that it would result in a pre-tax gain in the range of $15 million to $25 million, which would be recorded when the MPSC issues its final order approving the settlement. A hearing before the MPSC on the settlement is scheduled for May 14, 2009.

Pending the final disposition of these funds in Maryland, as of March 31, 2009, approximately $64 million in remaining proceeds from the Mirant settlement is being accounted for as restricted cash and approximately $88 million is being accounted for as a regulatory liability. The regulatory liability is comprised of approximately $64 million awaiting final regulatory resolution and approximately $24 million relating to the one-time customer credit approved by the DCPSC.

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Rate Proceedings

In the most recent electric service distribution base rate cases filed in the District of Columbia and Maryland, Pepco proposed the adoption of a bill stabilization adjustment mechanism (BSA) for retail customers. As more fully discussed below, the implementation of a BSA has been approved for electric service in Maryland and remains pending in the District of Columbia. Under the BSA, customer delivery rates are subject to adjustment (through a surcharge or credit mechanism), depending on whether actual distribution revenue per customer exceeds or falls short of the approved revenue-per-customer amount. The BSA increases rates if actual distribution revenues fall below the level approved by the applicable commission and decreases rates if actual distribution revenues are above the approved level. The result is that, over time, Pepco collects its authorized revenues for distribution deliveries. As a consequence, a BSA “decouples” revenue from unit sales consumption and ties the growth in 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 utility distribution revenues that are better aligned with costs, (ii) provides for more reliable fixed-cost recovery, (iii) tends to stabilize customers’ delivery bills, and (iv) removes any disincentives for Pepco to promote energy efficiency programs for their customers, because it breaks the link between overall sales volumes and delivery revenues.

District of Columbia

In December 2006, Pepco submitted an application to the DCPSC to increase electric distribution base rates, including a proposed BSA. In January 2008, the DCPSC approved, effective February 20, 2008, a revenue requirement increase of approximately $28 million, based on an authorized return on rate base of 7.96%, including a 10% return on equity (ROE). This increase did not include a BSA mechanism. While finding a BSA to be an appropriate ratemaking concept, the DCPSC cited potential statutory problems in its authority to implement the BSA. In February 2008, the DCPSC established a Phase II proceeding to consider these implementation issues. In August 2008, the DCPSC issued an order concluding that it has the necessary statutory authority to implement the BSA proposal and that further evidentiary proceedings are warranted to determine whether the BSA is just and reasonable. On January 2, 2009, the DCPSC issued an order designating the issues and establishing a procedural schedule for the BSA proceeding. Hearings are scheduled for May 12 and 13, 2009.

In June 2008, the District of Columbia Office of People’s Counsel (the DC OPC), citing alleged errors by the DCPSC, filed with the DCPSC a motion for reconsideration of the January 2008 order granting Pepco’s rate increase. The DC OPC’s motion was denied by the DCPSC and, in August 2008, the DC OPC filed with the District of Columbia Court of Appeals a petition for review of the DCPSC’s order of denial. The District of Columbia Court of Appeals granted the petition; briefs have been filed by the parties and oral argument was held on March 23, 2009. Pepco expects a decision by the end of the second quarter 2009.

Maryland

In July 2007, the MPSC issued an order in Pepco’s electric service distribution rate case, which included approval of a BSA. The order approved an annual increase in distribution rates of approximately $11 million (including a decrease in annual depreciation expense of approximately $31 million). The approved distribution rate reflects an ROE of 10%. The rate

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increase was effective as of June 16, 2007, and remained in effect for an initial period until July 19, 2008, pending a Phase II proceeding in which the MPSC considered the results of an audit of Pepco’s cost allocation manual, as filed with the MPSC, to determine whether a further adjustment to the rates was required. In July 2008, the MPSC issued an order covering the Phase II proceeding, denying any further adjustment to Pepco’s rates, thus making permanent the rate increase approved in the July 2007 order. The MPSC also issued an order in August 2008, further explaining its July 2008 order.

Pepco appealed the MPSC’s July 2007, July 2008 and August 2008 orders. The case currently is pending before the Circuit Court for Baltimore City. In a brief filed on March 9, 2009, Pepco contends that the MPSC erred in failing to implement permanent rates in accordance with Maryland law, and in its denial of Pepco’s rights to recover an increased share of the PHI Service Company costs and the costs of performing a MPSC-mandated management audit. The MPSC and OPC filed briefs on April 23, 2009 and a hearing is scheduled for May 12, 2009.

Divestiture Cases

District of Columbia

In June 2000, the DCPSC approved a divestiture settlement under which Pepco is required to share with its District of Columbia customers the net proceeds realized by Pepco from the sale of its generation-related assets. An unresolved issue relating to the application filed with the DCPSC by Pepco to implement the divestiture settlement is 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. As of March 31, 2009, the District of Columbia allocated portions of EDIT and ADITC associated with the divested generating assets were approximately $6 million each. Other issues in the divestiture proceeding deal with the treatment of internal costs and cost allocations as deductions from the gross proceeds of the divestiture.

Pepco believes that a sharing of EDIT and ADITC would violate the IRS normalization rules. Under these rules, Pepco could not transfer the EDIT and the ADITC benefit to customers more quickly than on a straight line basis over the book life of the related assets. Since the assets are no longer owned by Pepco, there is no book life over which the EDIT and ADITC can be returned. If Pepco were required to share EDIT and ADITC and, as a result, the normalization rules were violated, Pepco would be unable to use accelerated depreciation on District of Columbia allocated or assigned property. In addition to sharing with customers the generation-related EDIT and ADITC balances, Pepco would have to pay to the IRS an amount equal to Pepco’s District of Columbia jurisdictional generation-related ADITC balance ($6 million as of March 31, 2009), as well as its District of Columbia jurisdictional transmission and distribution-related ADITC balance ($3 million as of March 31, 2009) in each case as those balances exist as of the later of the date a DCPSC order is issued and all rights to appeal have been exhausted or lapsed, or the date the DCPSC order becomes operative.

In March 2008, the IRS approved final regulations, effective March 20, 2008, which allow utilities whose assets cease to be utility property (whether by disposition, deregulation or otherwise) to return to its utility customers the normalization reserve for EDIT and part or all of

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the normalization reserve for ADITC. This ruling applies to assets divested after December 21, 2005. For utility property divested on or before December 21, 2005, the IRS stated that it would continue to follow the holdings set forth in private letter rulings prohibiting the flow through of EDIT and ADITC associated with the divested assets. Pepco made a filing in April 2008, advising the DCPSC of the adoption of the final regulations and requesting that the DCPSC issue an order consistent with the IRS position. If the DCPSC issues the requested order, no accounting adjustments to the gain recorded in 2000 would be required.

As part of the proposal filed with the DCPSC in November 2008 concerning the sharing of the proceeds of the Mirant settlement, as discussed above under “Proceeds from Settlement of Mirant Bankruptcy Claims,” Pepco again requested that the DCPSC rule on all of the issues related to the divestiture of Pepco’s generating assets that remain outstanding. On March 5, 2009, the DCPSC issued an order approving Pepco’s proposal for sharing the remaining balance of the proceeds from the Mirant settlement; however, the DCPSC did not rule on the other outstanding issues concerning the divestiture of Pepco’s generating assets.

Pepco believes that its calculation of the District of Columbia customers’ share of divestiture proceeds is correct. However, depending on the ultimate outcome of this proceeding, Pepco could be required to make additional gain-sharing payments to District of Columbia customers, including the payments described above related to EDIT and ADITC. Such additional payments (which, other than the EDIT and ADITC related payments, cannot be estimated) would be charged to expense in the quarter and year in which a final decision is rendered and could have a material adverse effect on Pepco’s and PHI’s results of operations for those periods. However, neither PHI nor Pepco believes that additional gain-sharing payments, if any, or the ADITC-related payments to the IRS, if required, would have a material adverse impact on its financial position or cash flows.

Maryland

Pepco filed its divestiture proceeds plan application with the MPSC in April 2001. The principal issue in the Maryland case is the same EDIT and ADITC sharing issue that has been raised in the District of Columbia case. See the discussion above under “Divestiture Cases — District of Columbia.” As of March 31, 2009, the Maryland allocated portions of EDIT and ADITC associated with the divested generating assets were approximately $9 million and $10 million, respectively. Other issues deal with the treatment of certain costs as deductions from the gross proceeds of the divestiture. In November 2003, the Hearing Examiner in the Maryland proceeding issued a proposed order with respect to the application that concluded that Pepco’s Maryland divestiture settlement agreement provided for a sharing between Pepco and customers of the EDIT and ADITC associated with the sold assets. Pepco believes that such a sharing would violate the normalization rules (as discussed above) and would result in Pepco’s inability to use accelerated depreciation on Maryland allocated or assigned property. If the proposed order is affirmed, Pepco would have to share with its Maryland customers, on an approximately 50/50 basis, the Maryland allocated portion of the generation-related EDIT ($9 million as of March 31, 2009), and the Maryland-allocated portion of generation-related ADITC. Furthermore, Pepco would have to pay to the IRS an amount equal to Pepco’s Maryland jurisdictional generation-related ADITC balance ($10 million as of March 31, 2009), as well as its Maryland retail jurisdictional ADITC transmission and distribution-related balance ($6 million as of March 31, 2009), in each case as those balances exist as of the later of the date a MPSC order is issued and all rights to appeal have been exhausted or lapsed, or the date the

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MPSC order becomes operative. The Hearing Examiner decided all other issues in favor of Pepco, except for the determination that only one-half of the severance payments that Pepco included in its calculation of corporate reorganization costs should be deducted from the sales proceeds before sharing of the net gain between Pepco and customers.

In December 2003, Pepco appealed the Hearing Examiner’s decision to the MPSC as it relates to the treatment of EDIT and ADITC and corporate reorganization costs. The MPSC has not issued any ruling on the appeal, pending completion of the IRS rulemaking regarding sharing of EDIT and ADITC related to divested assets. Pepco made a filing in April 2008, advising the MPSC of the adoption of the final IRS normalization regulations (described above under “Divestiture Cases — District of Columbia”) and requesting that the MPSC issue a ruling on the appeal consistent with the IRS position.

As part of the proposal filed with the MPSC in November 2008 concerning the sharing of the proceeds of the Mirant settlement, as discussed above under “Proceeds from Settlement of Mirant Bankruptcy Claims,” Pepco again requested that the MPSC rule on all of the issues related to the divestiture of Pepco’s generating assets that remain outstanding.

On February 17, 2009, Pepco, the Maryland OPC and the MPSC staff filed a settlement agreement with the MPSC with respect to all of the open divesture plan issues. The settlement agreement, among other things, provides that Pepco would be allowed to retain the EDIT and ADITC reserves associated with Pepco’s divested generating assets and that none of those amounts would be available for sharing with Pepco’s Maryland customers. A hearing before the MPSC on the settlement is scheduled for May 14, 2009. If the settlement is approved, no accounting adjustments to the gain recorded in 2000 would be required.

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, 2009, there are approximately 180 cases still pending against Pepco in the State Courts of Maryland, of which approximately 90 cases were filed after December 19, 2000, and were tendered to Mirant for defense and indemnification pursuant to the terms of the Asset Purchase and Sale Agreement between Pepco and Mirant under which Pepco sold 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, neither PHI nor Pepco believes these suits will have a material adverse effect on its financial position, 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 position, results of operations or cash flows.

IRS Mixed Service Cost Issue

During 2001, Pepco changed its method of accounting with respect to capitalizable construction costs for income tax purposes. The change allowed the company to accelerate the deduction of certain expenses that were previously capitalized and depreciated. As a result of this method change, Pepco generated incremental tax cash flow benefits of approximately $94 million.

In 2005, the IRS issued Revenue Ruling 2005-53, which limited the ability of Pepco to utilize its tax accounting method on its 2001 through 2004 tax returns. Based on the Revenue Ruling and other Treasury Department guidance, PHI in its 2005 federal tax return adopted an alternative method of accounting for capitalizable construction costs that management believed would be acceptable to the IRS.

In line with this Revenue Ruling, the RAR for the 2001 and 2002 tax returns disallowed substantially all of the incremental tax benefits that Pepco had claimed on those returns by requiring the company to capitalize and depreciate certain expenses rather than treat such expenses as current deductions.

In March 2009, PHI reached a settlement with the IRS for all years (2001 through 2004) that is consistent with the approach adopted on the 2005 federal tax return. The terms of the settlement reduced the tax benefits related to the mixed service costs deductions by $17 million for 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, 2009 and 2008 were approximately $42 million and $39 million, respectively.

Certain subsidiaries of Pepco Energy Services Inc. (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, 2009 and 2008 were approximately $2 million and $3 million, respectively.

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In addition to the transactions described above, Pepco’s financial statements include the following related party transactions in its Statements of Earnings:

	For the Three Months Ended March 31,
	2009		2008
Income (Expense)	(millions of dollars)
Intercompany power purchases – Conectiv Energy Supply (a)	$	—	$	(15	)

(a) Included in purchased energy expense.

As of March 31, 2009 and December 31, 2008, Pepco had the following balances on its Balance Sheets due (to) from related parties:

	March 31, 2009			December 31, 2008
Liability	(millions of dollars)
Payable to Related Party (current)
PHI Service Company	$	(17	)	$	(17	)
Pepco Energy Services (a)		(53	)		(53	)

The items listed above are included in the “Accounts payable due to associated companies” balances on the Balance Sheets of $70 million and $70 million at March 31, 2009 and December 31, 2008, respectively.

(a) Pepco bills customers on behalf of Pepco Energy Services where customers have selected Pepco Energy Services as their alternative supplier or where Pepco Energy Services has performed work for certain government agencies under a General Services Administration area-wide agreement.

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DELMARVA POWER & LIGHT COMPANY

STATEMENTS OF EARNINGS

(Unaudited)

	Three Months Ended March 31,
	2009			2008
	(millions of dollars)
Operating Revenue
Electric	$	321		$	295
Natural Gas		131			116
Total Operating Revenue		452			411
Operating Expenses
Purchased energy		219			195
Gas purchased		101			88
Other operation and maintenance		59			56
Depreciation and amortization		19			18
Other taxes		10			10
Gain on sale of assets		—			(3	)
Total Operating Expenses		408			364
Operating Income		44			47
Other Income (Expenses)
Interest and dividend income		—			1
Interest expense		(11	)		(10	)
Other income		—			1
Total Other Expenses		(11	)		(8	)
Income Before Income Tax Expense		33			39
Income Tax Expense		12			13
Net Income		21			26
Retained Earnings at Beginning of Period		448			432
Dividends Paid to Parent		28			27
Retained Earnings at End of Period	$	441		$	431

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

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DELMARVA POWER & LIGHT COMPANY

BALANCE SHEETS

(Unaudited)

	March 31, 2009			December 31, 2008
	(millions of dollars)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	137		$	138
Accounts receivable, less allowance for uncollectible accounts of $13 million and $10 million, respectively		215			202
Inventories		36			52
Prepayments of income taxes		34			34
Prepaid expenses and other		26			28
Total Current Assets		448			454
INVESTMENTS AND OTHER ASSETS
Goodwill		8			8
Regulatory assets		236			244
Prepaid pension expense		181			184
Other		45			33
Total Investments and Other Assets		470			469
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		2,688			2,656
Accumulated depreciation		(837	)		(827	)
Net Property, Plant and Equipment		1,851			1,829
TOTAL ASSETS	$	2,769		$	2,752

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

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DELMARVA POWER & LIGHT COMPANY

BALANCE SHEETS

(Unaudited)

	March 31, 2009		December 31, 2008
	(millions of dollars, except shares)
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Short-term debt	$	246	$	246
Accounts payable and accrued liabilities		87		108
Accounts payable due to associated companies		33		34
Taxes accrued		15		7
Interest accrued		13		6
Liabilities and accrued interest related to uncertain tax positions		—		23
Derivative liabilities		12		13
Other		74		56
Total Current Liabilities		480		493
DEFERRED CREDITS
Regulatory liabilities		294		277
Deferred income taxes, net		457		446
Investment tax credits		8		8
Above-market purchased energy contracts and other electric restructuring liabilities		19		19
Derivative liabilities		22		14
Other		58		57
Total Deferred Credits		858		821
LONG-TERM LIABILITIES
Long-term debt		686		686
COMMITMENTS AND CONTINGENCIES (NOTE 12)
EQUITY
Common stock, $2.25 par value, authorized 1,000,000 shares, issued 1,000 shares		—		—
Premium on stock and other capital contributions		304		304
Retained earnings		441		448
Total Equity		745		752
TOTAL LIABILITIES AND EQUITY	$	2,769	$	2,752

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

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DELMARVA POWER & LIGHT COMPANY

STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
	2009			2008
	(millions of dollars)
OPERATING ACTIVITIES
Net income	$	21		$	26
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		19			18
Gain on sale of assets		—			(3	)
Deferred income taxes		12			18
Changes in:
Accounts receivable		(12	)		(6	)
Regulatory assets and liabilities		35			12
Accounts payable and accrued liabilities		(35	)		(19	)
Taxes accrued		(2	)		11
Interest accrued		7			3
Inventories		16			15
Other changes in working capital		2			(2	)
Net other operating		3			(6	)
Net Cash From Operating Activities		66			67
INVESTING ACTIVITIES
Investment in property, plant and equipment		(37	)		(32	)
Proceeds from sale of assets		—			50
Changes in restricted cash equivalents		—			(6	)
Net Cash (Used By) From Investing Activities		(37	)		12
FINANCING ACTIVITIES
Dividends paid to Parent		(28	)		(27	)
Capital contribution from Parent		—			62
Issuance of long-term debt		—			150
Reacquisitions of long-term debt		—			(58	)
Repayments of short-term debt, net		—			(181	)
Net other financing activities		(2	)		(5	)
Net Cash Used By Financing Activities		(30	)		(59	)
Net (Decrease) Increase in Cash and Cash Equivalents		(1	)		20
Cash and Cash Equivalents at Beginning of Period		138			11
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	137		$	31
NONCASH ACTIVITIES
Asset retirement obligations associated with removal costs transferred to regulatory liabilities	$	2		$	(5	)
Cash paid (received) for income taxes (includes payments to PHI for Federal income taxes)	$	5		$	(16	)

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 supplies electricity at regulated rates to retail customers in its territories who do not elect to purchase electricity from a competitive supplier. The regulatory term for this service varies by jurisdiction as follows:

Delaware	Standard Offer Service (SOS)
Maryland	SOS

DPL is a wholly owned subsidiary of Conectiv, which is wholly owned by Pepco Holdings, Inc. (Pepco Holdings or PHI).

In January 2008, DPL completed the sale of its retail electric distribution assets and the sale of its wholesale electric transmission assets, both located on the Eastern Shore of Virginia.

(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, 2008. 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, 2009, in accordance with GAAP. The year-end balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP. Interim results for the three months ended March 31, 2009 may not be indicative of results that will be realized for the full year ending December 31, 2009 since the sales of electric energy are seasonal.

DPL Onshore Wind Transactions

In 2008, PHI, through its DPL subsidiary, entered into three onshore wind PPAs. Under the contracts, DPL receives renewable energy credits (RECs) to help serve a portion of its requirements under the State of Delaware’s Renewable Energy Portfolio Standards Act, which requires that 20 percent of total load needed in Delaware be produced from renewable sources by 2019. The Delaware Public Service Commission (DPSC) has approved all three agreements, and payments under the agreements currently are expected to start in late 2009 for one contract and 2010 for the remaining two contracts.

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DPL has exclusive rights to the energy and RECs in amounts up to a total between 120 and 150 megawatts. The lengths of the contracts range between 15 and 20 years. DPL is only obligated to purchase energy and RECs in amounts generated and delivered by the sellers at rates that are primarily fixed. Recent disruptions in the capital and credit markets could result in delays in the start dates for these PPAs. If the PPAs are not initiated by the specified dates, DPL has the right to terminate the PPAs. DPL’s exposure to loss under the PPAs is the extent to which the market prices for energy and RECs fall below the contractual purchase price.

DPL has concluded that two of the PPAs are leases in accordance with the guidance in Emerging Issues Task Force (EITF) Issue No. 01-8, “Determining Whether an Arrangement Contains a Lease” (EITF 01-8), but that DPL did not own the assets under the lease during construction in accordance with EITF Issue No. 97-10, “The Effect of Lessee Involvement in Asset Construction.” DPL concluded that consolidation is not required for any of these PPAs under Financial Accounting Standards Board (FASB) Interpretation Number (FIN) 46(R).

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 as of July 1, 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. Factors that may result in an interim impairment test include, but are not limited to: a change in identified reporting units; an adverse change in business conditions; an adverse regulatory action; or an impairment of long-lived assets. DPL performed its annual impairment test as of July 1, 2008 and an interim impairment test as of December 31, 2008 and analyzed impairment factors as of March 31, 2009. As described in Note (6), “Goodwill,” no impairment charge has been required to be recorded.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in DPL’s gross revenues were $4 million and $4 million for the three months ended March 31, 2009 and 2008, respectively.

Reclassifications and Adjustments

Certain prior period amounts have been reclassified in order to conform to current period presentation.

During the first quarter of 2009, DPL recorded additional revenue of $8 million related to the unbilled portion of the Gas Cost Rate (GCR) revenue, which was not previously recognized. Because the GCR revenue is deferred, an additional expense of $8 million has also been recorded in the first quarter of 2009. Consequently there is no impact on net earnings as a result of this adjustment.

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(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Statement of Financial Accounting Standards (SFAS) No. 141(R), “Business Combinations—a Replacement of FASB Statement No. 141” (SFAS No. 141 (R))

SFAS No. 141(R) replaces FASB Statement No. 141, “Business Combinations,” and retains the fundamental requirements that the acquisition method of accounting be used for all business combinations and for an acquirer to be identified for each business combination. However, SFAS No. 141(R) expands the definition of a business and amends FASB Statement No. 109, “Accounting for Income Taxes,” to require the acquirer to recognize changes in the amount of its deferred tax benefits that are realizable because of a business combination either in income from continuing operations or directly in contributed capital, depending on the circumstances.

On April 1, 2009, the FASB issued FASB Staff Position (FSP) Financial Accounting Standard (FAS) 141(R)-1 “Accounting for Assets and Liabilities Assumed in a Business Combination that Arise from Contingencies” (FSP FAS 141(R)-1), to clarify the accounting for the initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. FSP FAS 141(R)-1 requires that assets acquired and liabilities assumed in a business combination that arise from contingencies be measured at fair value if the acquisition date fair value of that asset and liability can be determined during the measurement period in accordance with SFAS No. 157. If the acquisition date fair value cannot be determined, then the asset or liability would be measured in accordance with SFAS No. 5, “Accounting for Contingencies,” and FIN 14, “Reasonable Estimate of the Amount of Loss.”

SFAS No. 141(R) and the guidance provided in FSP FAS 141(R)-1 applies prospectively to business combinations for which the acquisition date is on or after January 1, 2009. DPL adopted SFAS No. 141(R) on January 1, 2009, and it did not have a material impact on DPL’s overall financial condition, results of operations, or cash flows.

FSP 157-2, “Effective Date of FASB Statement No. 157” (FSP 157-2)

FSP 157-2 deferred the effective date of SFAS No. 157, “Fair Value Measurements,” for all nonrecurring fair value measurements of non-financial assets and non-financial liabilities until January 1, 2009 for DPL. The adoption of SFAS No. 157 did not have a material impact on the fair value measurements of DPL’s non-financial assets and non-financial liabilities.

SFAS No. 160, “Non-controlling Interests in Consolidated Financial Statements—an Amendment of ARB No. 51” (SFAS No. 160)

SFAS No. 160 establishes new accounting and reporting standards for a non-controlling interest (previously called minority interest) in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a non-controlling interest in a subsidiary is an ownership interest in the consolidated entity that should be separately reported in the consolidated financial statements.

SFAS No. 160 establishes accounting and reporting standards that require (i) the ownership interests and the related consolidated net income in subsidiaries held by parties other than the parent be clearly identified, labeled, and presented in the consolidated balance sheets within equity, but separate from the parent’s equity, and presented separately on the face of the

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consolidated statement of earnings, (ii) the changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for as equity transactions, and (iii) when a subsidiary is deconsolidated, any retained non-controlling equity investment in the former subsidiary must be initially measured at fair value.

SFAS No. 160 was effective prospectively for financial statement reporting periods beginning January 1, 2009 for DPL, except for the financial statement presentation and disclosure requirements which also apply to prior reporting periods presented. As of January 1, 2009, DPL has adopted the provisions of SFAS No. 160, and the provisions did not have a material impact on DPL’s overall financial condition, results of operations, or cash flows.

SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities—an Amendment of FASB Statement No. 133” (SFAS No. 161)

SFAS No. 161 enhances the disclosure requirements for derivative instruments and hedging activities. Some of the new disclosures include derivative objectives and strategies, derivative volumes by product type, location and gross fair values of derivative assets and liabilities, location and amounts of gains and losses on derivatives and related hedged items, and credit-risk-related contingent features in derivatives.

SFAS No. 161 was effective for financial statement reporting periods beginning January 1, 2009 for DPL. SFAS No. 161 encourages but does not require disclosures for earlier periods presented for comparative purposes at initial adoption. DPL has adopted the provisions of SFAS No. 161 with comparative disclosures within Note (10), “Derivative Instruments and Hedging Activities.”

EITF Issue No. 08-5, “Issuer’s Accounting for Liabilities Measured at Fair Value with a Third Party Credit Enhancement” (EITF 08-5)

In September 2008, the FASB issued EITF 08-5 to provide guidelines for the determination of the unit of accounting for a liability issued with an inseparable third-party credit enhancement when it is measured or disclosed at fair value on a recurring basis. EITF 08-5 applies to entities that incur liabilities with inseparable third-party credit enhancements or guarantees that are recognized or disclosed at fair value. This would include guaranteed debt obligations, derivatives, and other instruments that are guaranteed by third parties.

The effect of the credit enhancement may not be included in the fair value measurement of the liability, even if the liability is an inseparable third-party credit enhancement. The issuer is required to disclose the existence of the inseparable third-party credit enhancement on the issued liability.

EITF 08-5 was effective on a prospective basis for reporting periods beginning on and after January 1, 2009 for DPL. As of January 1, 2009, DPL has adopted the provisions of EITF 08-5, and it did not have a material impact on DPL’s overall financial condition, results of operations, or cash flows.

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(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

FSP FAS 107-1 and Accounting Principles Board (APB) 28-1, “Interim Disclosures about Fair Value of Financial Instruments” (FSP FAS 107-1 and APB 28-1)

On April 9, 2009, the FASB issued FSP FAS 107-1 and APB 28-1, which require quarterly disclosures of the fair value of financial instruments beginning with the second quarter of 2009. Prior to FSP 107-1 and APB 28-1, these disclosures were only required on an annual basis. The disclosures for prior reporting periods are required after initial adoption.

FSP FAS 107-1 and APB 28-1 are effective for interim reporting periods ending after June 15, 2009 with the option to early adopt for interim periods ending after March 15, 2009. DPL elected not to early adopt; therefore, the disclosure requirements will be reflected in DPL’s second quarter 2009 Form 10-Q. The primary impact of the new standard will be the quarterly disclosure of the fair value of debt issued by DPL.

FSP FAS 157-4, “Determining Whether a Market is Not Active and a Transaction is Not Distressed” (FSP FAS 157-4)

On April 9, 2009, the FASB issued FSP FAS 157-4, which outlines a two-step test to identify inactive and distressed markets and provides a fair value application example for financial instruments when both conditions are met. The FSP is designed to improve application of fair value in illiquid or inactive markets.

FSP FAS 157-4 is effective for interim reporting periods ending after June 15, 2009 with the option to early adopt for interim periods ending after March 15, 2009. DPL did not elect to early adopt. The new requirement would affect DPL’s valuation of derivative instruments if they are valued using information from inactive and distressed markets. DPL is currently evaluating whether FSP 157-4 will have a material impact on DPL’s overall financial condition, results of operations, or cash flows.

FSP FAS 115-2 and FAS 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments” (FSP FAS 115-2 and FAS 124-2)

On April 9, 2009, the FASB issued FSP FAS 115-2 and FAS 124-2, which provided additional guidance on other-than-temporary impairment (OTTI) of debt and equity securities. It requires disclosure of information about the credit and noncredit component of an OTTI event and when an OTTI event has occurred. The FSP requires separate display on the statements of earnings, of losses related to credit deterioration and losses related to other market factors. Market-related losses will be recorded in accumulated other comprehensive (losses) earnings if it is not likely that the investor will have to sell the security prior to recovery.

FSP 115-2 and FAS 124-2 are effective for interim reporting periods ending after June 15, 2009, with the option to early adopt for interim periods ending after March 15, 2009. DPL elected not to early adopt. DPL does not anticipate the adoption of FSP 115-2 and FAS 124-2 to have a material impact on DPL’s overall financial condition, results of operations, or cash flows.

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(5) SEGMENT INFORMATION

In accordance with SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information,” DPL has one segment, its regulated utility business.

(6) GOODWILL

As of March 31, 2009 and December 31, 2008, DPL had goodwill of approximately $8 million all of which was generated by DPL’s acquisition of Conowingo Power Company in 1995.

DPL’s July 1, 2008 annual impairment test indicated that its goodwill was not impaired. DPL performed an interim impairment test as of December 31, 2008 which indicated the goodwill balance was not impaired. Because of the continued uncertainty in the financial markets and overall economic conditions, during the first quarter of 2009, DPL reviewed the significant assumptions included in its goodwill impairment analysis to determine if it was more likely than not that DPL’s fair value was less than its carrying value and determined that DPL did not have a triggering event requiring DPL to perform a comprehensive goodwill assessment during the first quarter of 2009.

With the current volatile general market conditions and the disruptions in the credit and capital markets, DPL will continue to closely monitor whether there is goodwill impairment.

(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, 2009 before intercompany allocations from the PHI Service Company, of $31 million includes $5 million for DPL’s allocated share. PHI’s pension and other postretirement net periodic benefit cost for the three months ended March 31, 2008 before intercompany allocations, of $16 million included $1 million for DPL’s allocated share.

(8) DEBT

PHI, Potomac Electric Power Company (Pepco), DPL and Atlantic City Electric Company (ACE) maintain an unsecured credit facility to provide for their respective short-term liquidity needs. The aggregate borrowing limit under the facility is $1.5 billion, all or any portion of which may be used to obtain loans or to issue letters of credit. PHI’s credit limit under the facility is $875 million. The credit limit of each of Pepco, DPL and ACE is the lesser of $500 million and the maximum amount of debt the company is permitted to have outstanding by its regulatory authorities, except that the aggregate amount of credit used by Pepco, DPL and ACE at any given time collectively may not exceed $625 million.

In April 2009, DPL resold $9 million of its Pollution Control Revenue Refunding bonds issued by the Delaware Economic Development Authority. These bonds were repurchased by DPL in November 2008 in response to disruption in the tax-exempt bond market that made it difficult for the remarketing agent to successfully remarket the bonds. As the owner of the bonds, DPL received the proceeds of the sale and intends to use the proceeds for general corporate purposes.

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In May 2009, DPL repaid, prior to maturity, $50 million of its $150 million short-term loan which matures in July 2009.

The continued disruptions in the capital and credit markets, combined with the volatility of energy prices, have had an impact on the borrowing capacity and liquidity of DPL. Since the third quarter of 2008, to address the challenges posed by the current capital and credit market environment and to ensure that DPL will continue to have sufficient access to cash to meet its liquidity needs, DPL has taken several measures to reduce expenditures, issued $250 million in long-term debt securities and resold $9 million of Pollution Control Revenue Refunding Bonds (as discussed above).

(9) INCOME TAXES

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

	For the Three Months Ended March 31,
	2009		2008
Federal statutory rate	35.0	%	35.0	%
Increases (decreases) resulting from:
Depreciation	1.2		1.5
State income taxes, net of federal effect	5.5		5.4
Tax credits	(.6	)	(.5	)
Change in estimates and interest related to uncertain and effectively settled tax positions	(3.6	)	(7.9	)
Other, net	(1.1	)	(.3	)
Effective Income Tax Rate	36.4	%	33.2	%

DPL’s effective tax rates for the three months ended March 31, 2009 and 2008 were 36.4% and 33.2%, respectively. The increase in the rate resulted from the change in estimates and interest related to uncertain and effectively settled tax positions. The increase in the change in estimates and interest related to uncertain and effectively settled tax positions is primarily due to the non-recurring impact of a tax claim filed with the Internal Revenue Service (IRS) in March 2008. The claim was for the treatment of casualty losses as current deductions (as opposed to being depreciated over their tax lives) on prior year returns currently under audit.

In March 2009, the IRS issued its Revenue Agent’s Report (RAR) for the audit of PHI’s consolidated federal income tax returns for the calendar years 2003 to 2005. The IRS has proposed adjustments to PHI’s tax returns, including adjustments to DPL’s capitalization of overhead costs for tax purposes and the deductibility of certain DPL casualty losses. In conjunction with PHI, DPL is taking steps to appeal certain of the proposed adjustments and believes it has adequately reserved for the adjustments included in the RAR.

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During the first quarter of 2009, primarily as a result of the RAR, DPL reduced uncertain tax benefits by $23 million ($17 million as a result of settlements with taxing authorities and $6 million as adjustments to prior year tax positions).

(10) DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

DPL accounts for its derivative activities in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133) as amended by subsequent pronouncements.

DPL uses derivative instruments in the form of forward contracts, futures, swaps, and exchange-traded and over-the-counter options primarily to reduce gas commodity price volatility and limit its customers’ exposure to increases in the market price of gas. DPL also manages commodity risk with physical natural gas and capacity contracts that are not classified as derivatives. All premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all gains and losses related to hedging activities, are deferred under Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation,” until recovered based on the Fuel Adjustment clause approved by the DPSC.

The table below identifies the balance sheet location and fair values of derivative instruments as of March 31, 2009 and December 31, 2008:

	As of March 31, 2009
	(in millions of dollars)
Balance Sheet Caption	Derivatives Designated as Hedging Instruments			Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting			Net Derivative Instruments
Derivative Assets (current assets)	$	—		$	8		$	8		$	(8	)	$	—
Derivative Assets (non-current assets)		—			—			—			—			—
Total Derivative Assets		—			8			8			(8	)		—
Derivative Liabilities (current liabilities)		(33	)		(23	)		(56	)		44			(12	)
Derivative Liabilities (non-current liabilities)		—			(22	)		(22	)		—			(22	)
Total Derivative Liabilities		(33	)		(45	)		(78	)		44			(34	)
Net Derivative (Liability) Asset	$	(33	)	$	(37	)	$	(70	)	$	36		$	(34	)

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	As of December 31, 2008
	(in millions of dollars)
Balance Sheet Caption	Derivatives Designated as Hedging Instruments			Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting			Net Derivative Instruments
Derivative Assets (current assets)	$	—		$	3		$	3		$	(3	)	$	—
Derivative Assets (non-current assets)		—			—			—			—			—
Total Derivative Assets		—			3			3			(3	)		—
Derivative Liabilities (current liabilities)		(31	)		(13	)		(44	)		31			(13	)
Derivative Liabilities (non-current liabilities)		—			(14	)		(14	)		—			(14	)
Total Derivative Liabilities		(31	)		(27	)		(58	)		31			(27	)
Net Derivative (Liability) Asset	$	(31	)	$	(24	)	$	(55	)	$	28		$	(27	)

Under FSP FIN 39-1, 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 arrangement. The amount of cash collateral that was offset against these derivative positions is as follows:

	March 31, 2009		December 31, 2008
	(millions of dollars)
Cash collateral pledged to counterparties with the right to reclaim	$	36	$	28

As of March 31, 2009 and December 31, 2008, PHI had no cash collateral pledged or received related to derivatives accounted for at fair value that was not entitled to offset under master netting arrangements.

Derivatives Designated as Hedging Instruments

Cash Flow Hedges

As described above, all premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all gains and losses related to hedging activities, are deferred under SFAS No. 71 until recovered based on the Fuel Adjustment clause approved by the DPSC. The following table indicates the amounts deferred as regulatory assets or liabilities and the location in the statements of earnings of amounts reclassified to earnings through the fuel adjustment clause for the three months ended March 31, 2009 and March 31, 2008:

Type of Derivative	Gain (Loss) Deferred as a Regulatory Asset/Liability				Gain (Loss) Reclassified from Regulatory Asset/Liability to Earnings						Location of Gain (Loss) in Statements of  Earnings Reclassified from Regulatory Asset/Liability
	2009		2008		2009			2008
	(millions of dollars)
Energy Commodity Contracts	$	—	$	6	$	(16	)	$	(1	)	Fuel and Purchased Energy

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As of March 31, 2009 and December 31, 2008 Power Delivery had the following outstanding commodity forward contracts that were entered into to hedge forecasted transactions:

	Quantities
Commodity	March 31, 2009	December 31, 2008
Forecasted Purchases Hedges:
Natural Gas (MMBtu)	8,850,000	10,805,000

Other Derivative Activity

DPL holds certain derivatives that do not qualify as hedges. Under SFAS No. 133, these derivatives are recorded at fair value on the balance sheet with the gain or loss recorded in earnings. In accordance with SFAS No. 71, offsetting regulatory assets or regulatory liabilities are recorded on the balance sheet and the recognition of the gain or recovery of the loss is deferred. For the three months ended March 31, 2009 and March 31, 2008, the amount of the derivative gain/(loss) recognized by line item in the statements of earnings is provided in the table below:

Type of Derivative	Gain (Loss) Deferred as a Regulatory Asset/Liability						Gain (Loss) Reclassified from Regulatory Asset/Liability					Location of Gain (Loss) in Statements of Earnings Reclassified from Regulatory Asset/Liability
	2009			2008			2009			2008
	(millions of dollars)
Energy Commodity Contracts	$	(14	)	$	(4	)	$	(3	)	$	—	Fuel and Purchased Energy

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As of March 31, 2009 and December 31, 2008, DPL had the following net outstanding natural gas commodity forward contracts that did not qualify for hedge accounting:

	March 31, 2009		December 31, 2008
Commodity	Quantity	Net Position	Quantity	Net Position
Natural Gas (MMBtu)	11,159,796	Long	8,928,750	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 (“the exposed party”) may declare an early termination and liquidation of all transactions entered into under the ISDA, including foreclosure against any collateral security. In addition, some of the ISDAs have cross default provisions under which a default by a party under another commodity or derivative contract, or the breach by a party of another borrowing obligation in excess of a specified threshold, is a breach under the ISDA.

The collateral requirements under the ISDA or similar agreements generally work as follows. The parties establish a dollar amount 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 unsecured credit varies according to the senior, unsecured debt rating of either the party directly or a guarantor of the party’s obligations. The fair values of all transactions are netted under the master netting provisions. Transactions include derivatives accounted for on-balance sheet as well as normal purchases and sales that are accounted for off-balance sheet under SFAS No. 133. If the aggregate fair value of the transactions in a net loss position exceeds the unsecured credit amount, then collateral is required equal to the amount by which the unsecured credit amount 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 amount would be typically zero and collateral would be required for the entire net loss position. Exchange traded contracts do not contain this contingent credit risk feature related to credit rating as they are fully collateralized.

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, 2009, was $78 million. As of that date, DPL had posted cash collateral of $36 million in the normal course of business against the gross derivative liability resulting in a net liability of $42 million before giving effect to offsetting transactions that are encompassed within master netting agreements that would reduce

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this amount. PHI’s net settlement amount in the event of a downgrade of DPL below “investment grade” as of March 31, 2009, would have been approximately $33 million after taking into account the master netting agreements.

(11) FAIR VALUE DISCLOSURES

Effective January 1, 2008, DPL adopted SFAS No. 157 which established a framework for measuring fair value and expands disclosures about fair value measurements.

As defined in SFAS No. 157, 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. DPL is able to classify fair value balances based on the observability of those inputs. SFAS No. 157 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 measurement) and the lowest priority to unobservable inputs (level 3 measurement). The three levels of the fair value hierarchy defined by SFAS No. 157 are 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 pricing 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, 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 investments that are valued using models or other valuation methodologies. DPL’s Level 3 instruments are natural gas options. 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. Some of the options do not expire until December 2011. All of the options are part of the natural gas hedging program approved by the Delaware Public Service Commission.

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Level 3 instruments classified as executive deferred compensation plan assets are life insurance policies that are valued using the cash surrender value of the policies. Since these values do not represent a quoted price in an active market they are considered Level 3.

The following tables set forth by level within the fair value hierarchy DPL’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2009 and December 31, 2008. As required by SFAS No. 157, 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, 2009
	(millions of dollars)
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
ASSETS
Cash equivalents	$	128	$	128	$	—	$	—
Executive deferred compensation plan assets		4		3		—		1
	$	132	$	131	$	—	$	1
LIABILITIES
Derivative instruments	$	70	$	32	$	—	$	38
Executive deferred compensation plan liabilities		—		—		—		—
	$	70	$	32	$	—	$	38
	Fair Value Measurements at December 31, 2008
	(millions of dollars)
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
ASSETS
Cash equivalents	$	129	$	129	$	—	$	—
Executive deferred compensation plan assets		4		3		—		1
	$	133	$	132	$	—	$	1
LIABILITIES
Derivative instruments	$	56	$	29	$	3	$	24
Executive deferred compensation plan liabilities		1		—		1		—
	$	57	$	29	$	4	$	24

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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, 2009 and March 31, 2008 are shown below:

	Three Months Ended March 31, 2009
	Net Derivative Instruments Assets (Liability)			Deferred Compensation Plan Assets
	(millions of dollars)
Beginning balance as of January 1, 2009	$	(24	)	$	1
Total gains or (losses) (realized and unrealized)
Included in earnings		—			—
Included in accumulated other comprehensive (losses) earnings		—			—
Included in regulatory liabilities		(17	)		—
Purchases and issuances		—			—
Settlements		3			—
Transfers in and/or out of Level 3		—			—
Ending balance as of March 31, 2009	$	(38	)	$	1
				Other Operation and Maintenance Expense
					(millions of dollars)
Gains or (losses) (realized and unrealized) included in earnings for the period above are reported in Deferred Regulatory Asset and Other Operation and Maintenance Expense as follows:				$	—
Total losses included in earnings for the period above				$	—
Change in unrealized gains relating to assets still held at reporting date				$	—

	Three Months Ended March 31, 2008
	Net Derivative Instruments			Deferred Compensation Plan Assets
	(millions of dollars)
Beginning balance as of January 1, 2008	$	(10	)	$	1
Total gains or (losses) (realized and unrealized)
Included in earnings		—			—
Included in accumulated other comprehensive (losses) earnings		—			—
Included in regulatory liabilities		4			—
Purchases and issuances		—			—
Settlements		—			—
Transfers in and/or out of Level 3		—			—
Ending balance as of March 31, 2008	$	(6	)	$	1
				Other Operation and Maintenance Expense
				(millions of dollars)
Gains or (losses) (realized and unrealized) included in earnings for the period above are reported in Other Operation and Maintenance Expense as follows:
Total gains (losses) included in earnings for the period above				$	—
Change in unrealized gains (losses) relating to assets still held at reporting date				$	—

(12) COMMITMENTS AND CONTINGENCIES

Regulatory and Other Matters

Rate Proceedings

In the most recent electric service distribution base rate cases filed in Maryland, and in a natural gas distribution case filed in Delaware, DPL proposed the adoption of a bill stabilization adjustment mechanism (BSA) for retail customers. As more fully discussed below, the implementation of a BSA has been approved for electric service in Maryland. A method of revenue decoupling similar to a BSA, referred to as a modified fixed variable rate design (MFVRD), has been adopted for electric and natural gas service in Delaware, which will be implemented in the context of DPL’s next Delaware base rate case. Under the BSA, customer delivery rates are subject to adjustment (through a surcharge or credit mechanism), depending on whether actual distribution revenue per customer exceeds or falls short of the approved revenue-per-customer amount. The BSA increases rates if actual distribution revenues fall below the level approved by the applicable commission and decreases rates if actual distribution revenues are above the approved level. The result is that, over time, DPL collects its authorized revenues for distribution deliveries. As a consequence, a BSA “decouples” revenue from unit sales consumption and ties the growth in 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 utility 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

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promote energy efficiency programs for their customers, because it breaks the link between overall sales volumes and delivery revenues. The MFVRD adopted in Delaware relies primarily upon 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 believes that the MFVRD can serve as an appropriate revenue decoupling mechanism.

Delaware

On August 29, 2008, DPL submitted its 2008 GCR filing to the DPSC, requesting a 14.8% increase in the level of GCR. On September 16, 2008, the DPSC issued an initial order approving the requested increase, which became effective on November 1, 2008, subject to refund pending final DPSC approval after evidentiary hearings.

Due to a significant decrease in wholesale gas prices, on January 26, 2009, DPL submitted to the DPSC an interim GCR filing, requesting a 6.6% decrease in the level of GCR. On February 5, 2009, the DPSC issued an initial order approving the requested decrease, which became effective on March 1, 2009, subject to refund pending final DPSC approval after evidentiary hearings. A hearing is scheduled for May 27, 2009.

Maryland

In July 2007, the Maryland Public Service Commission (MPSC) issued an order in DPL’s electric service distribution rate case, which included approval of a BSA. The order approved an annual increase in distribution rates of approximately $15 million (including a decrease in annual depreciation expense of approximately $1 million). The approved distribution rate reflects a return on equity (ROE) of 10%. The rate increase was effective as of June 16, 2007, and remained in effect for an initial period until July 19, 2008, pending a Phase II proceeding in which the MPSC considered the results of an audit of DPL’s cost allocation manual, as filed with the MPSC, to determine whether a further adjustment to the rates was required. In July 2008, the MPSC issued an order covering the Phase II proceeding, denying any further adjustment to DPL’s rates, thus making permanent the rate increase approved in the July 2007 order. The MPSC also issued an order in August 2008, further explaining its July 2008 order.

DPL appealed the MPSC’s July 2007, July 2008 and August 2008 orders. The case currently is pending before the Circuit Court for Baltimore City. In a brief filed on March 9, 2009, DPL contends that the MPSC erred in failing to implement permanent rates in accordance with Maryland law, and in its denial of DPL’s rights to recover an increased share of the PHI Service Company costs and the costs of performing a MPSC-mandated management audit. The MPSC and OPC filed briefs on April 23, 2009 and a hearing is scheduled for May 12, 2009.

IRS Mixed Service Cost Issue

During 2001, DPL changed its method of accounting with respect to capitalizable construction costs for income tax purposes. The change allowed the company to accelerate the deduction of certain expenses that were previously capitalized and depreciated. As a result of this method change, DPL generated incremental tax cash flow benefits of approximately $62 million.

In 2005, the IRS issued Revenue Ruling 2005-53, which limited the ability of DPL to utilize its tax accounting method on its 2001 through 2004 tax returns. Based on the Revenue

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Ruling and other Treasury Department guidance, PHI in its 2005 federal tax return adopted an alternative method of accounting for capitalizable construction costs that management believed would be acceptable to the IRS.

In line with this Revenue Ruling, the RAR for the 2001 and 2002 tax returns disallowed substantially all of the incremental tax benefits that DPL had claimed on those returns by requiring the company to capitalize and depreciate certain expenses rather than treat such expenses as current deductions.

In March 2009, PHI reached a settlement with the IRS for all years (2001 through 2004) that is consistent with the approach adopted on the 2005 federal tax return. The terms of the settlement reduced the tax benefits related to the mixed service costs deductions by $12 million for DPL.

(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, 2009 and 2008 were $32 million and $30 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 Earnings:

	For the Three Months Ended March 31,
	2009			2008
Income (Expense)	(millions of dollars)
SOS with Conectiv Energy Supply (a)	$	(37	)	$	(61	)
Intercompany lease transactions (b)		2			2

(a) Included in purchased energy expense.

(b) Included in electric revenue.

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As of March 31, 2009 and December 31, 2008, DPL had the following balances on its balance sheets due (to) from related parties:

	March 31, 2009			December 31, 2008
Liability	(millions of dollars)
Payable to Related Party (current)
PHI Service Company	$	(17	)	$	(15	)
Conectiv Energy Supply		(11	)		(14	)
Pepco Energy Services (a)		(5	)		(6	)

The items listed above are included in the “Accounts payable due to associated companies” balances on the Balance Sheets of $33 million and $34 million at March 31, 2009 and December 31, 2008, respectively.

(a) DPL bills customers on behalf of Pepco Energy Services where customers have selected Pepco Energy Services as their alternative supplier.

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ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF EARNINGS

(Unaudited)

	Three Months Ended March 31,
	2009			2008
	(millions of dollars)
Operating Revenue	$	344		$	361
Operating Expenses
Purchased energy		277			245
Other operation and maintenance		48			46
Depreciation and amortization		25			24
Other taxes		5			6
Deferred electric service costs		(27	)		25
Total Operating Expenses		328			346
Operating Income		16			15
Other Income (Expenses)
Interest and dividend income		—			1
Interest expense		(17	)		(15	)
Other income		1			1
Total Other Expenses		(16	)		(13	)
Income Before Income Tax Benefit		—			2
Income Tax Benefit		(2	)		(3	)
Net Income		2			5
Retained Earnings at Beginning of Period		166			142
Dividends Paid to Parent		(24	)		—
Retained Earnings at End of Period	$	144		$	147

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, 2009			December 31, 2008
	(millions of dollars)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	21		$	65
Restricted cash equivalents		10			10
Accounts receivable, less allowance for uncollectible accounts of $7 million and $6 million, respectively		175			195
Inventories		15			15
Prepayments of income taxes		39			47
Prepaid expenses and other		17			16
Total Current Assets		277			348
INVESTMENTS AND OTHER ASSETS
Regulatory assets		753			768
Restricted funds held by trustee		5			5
Receivables and accrued interest related to uncertain tax positions		107			113
Income taxes receivable		37			12
Prepaid pension expense		4			6
Other		11			12
Total Investments and Other Assets		917			916
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		2,238			2,216
Accumulated depreciation		(673	)		(666	)
Net Property, Plant and Equipment		1,565			1,550
TOTAL ASSETS	$	2,759		$	2,814

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, 2009		December 31, 2008
	(millions of dollars, except shares)
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Short-term debt	$	23	$	23
Current maturities of long-term debt		32		32
Accounts payable and accrued liabilities		113		122
Accounts payable due to associated companies		25		28
Taxes accrued		15		7
Interest accrued		17		14
Liabilities and accrued interest related to uncertain tax positions		—		6
Other		40		35
Total Current Liabilities		265		267
DEFERRED CREDITS
Regulatory liabilities		330		377
Deferred income taxes, net		569		549
Investment tax credits		10		10
Other postretirement benefit obligation		42		41
Liabilities and accrued interest related to uncertain tax positions		3		3
Other		16		14
Total Deferred Credits		970		994
LONG-TERM LIABILITIES
Long-term debt		610		610
Transition Bonds issued by ACE Funding		393		401
Total Long-Term Liabilities		1,003		1,011
COMMITMENTS AND CONTINGENCIES (NOTE 10)
REDEEMABLE SERIAL PREFERRED STOCK		6		6
EQUITY
Common stock, $3.00 par value, authorized 25,000,000 shares, and 8,546,017 shares outstanding		26		26
Premium on stock and other capital contributions		345		344
Retained earnings		144		166
Total Equity		515		536
TOTAL LIABILITIES AND EQUITY	$	2,759	$	2,814

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

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ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
	2009			2008
	(millions of dollars)
OPERATING ACTIVITIES
Net income	$	2		$	5
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		25			24
Deferred income taxes		21			28
Changes in:
Accounts receivable		20			20
Regulatory assets and liabilities		(41	)		26
Accounts payable and accrued liabilities		(13	)		(3	)
Taxes accrued		(2	)		(33	)
Interest accrued		3			(2	)
Other changes in working capital		(1	)		—
Net other operating		5			7
Net Cash From Operating Activities		19			72
INVESTING ACTIVITIES
Investment in property, plant and equipment		(28	)		(57	)
Proceeds from sale of assets		—			1
Net other investing activities		—			1
Net Cash Used By Investing Activities		(28	)		(55	)
FINANCING ACTIVITIES
Dividends paid to Parent		(24	)		—
Capital contribution from Parent		—			35
Reacquisition of long-term debt		(8	)		(47	)
Issuances of short-term debt, net		—			6
Net other financing activities		(3	)		(7	)
Net Cash Used By Financing Activities		(35	)		(13	)
Net (Decrease) Increase in Cash and Cash Equivalents		(44	)		4
Cash and Cash Equivalents at Beginning of Period		65			7
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	21		$	11
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash (received) paid for income taxes (includes payments to PHI for Federal income taxes)	$	(13	)	$	8

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 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 supplier. Default Electricity Supply is also known as Basic Generation Service (BGS). 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, 2008. 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, 2009, in accordance with GAAP. The year-end balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP. Interim results for the three months ended March 31, 2009 may not be indicative of results that will be realized for the full year ending December 31, 2009 since the sales of electric energy are seasonal.

Consolidation of Variable Interest Entities

ACE has power purchase agreements (PPAs) with a number of entities, including three contracts between unaffiliated non-utility generators (NUGs) and ACE. Due to a variable element in the pricing structure of the NUGs, ACE potentially assumes the variability in the operations of the plants related to these PPAs and, therefore, has a variable interest in the entities. In accordance with the provisions of Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46(R) (revised December 2003), “Consolidation of Variable Interest Entities” (FIN 46(R)) and FASB Staff Position (FSP) FIN 46(R)-6, “Determining the Variability to Be Considered in Applying FASB Interpretation No. 46(R)” (FSP FIN 46(R)-6), ACE continued, during the first quarter of 2009, to conduct its efforts to obtain information from these entities, but was unable to obtain sufficient information to conduct the analysis required under FIN 46(R) 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 application of FIN 46(R) 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, 2009 and 2008 were approximately $83 million and $88 million, respectively, of which approximately $72 million and $76 million, respectively, related to power purchases under the NUGs. ACE does not have exposure to loss under the NUGs because cost recovery will be achieved from its customers through regulated rates.

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Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in ACE’s gross revenues were $6 million and $5 million for the three months ended March 31, 2009 and 2008, respectively.

Reclassifications and Adjustments

Certain prior period amounts have been reclassified in order to conform to current period presentation.

Income Tax Adjustments

During the first quarter of 2009, ACE recorded adjustments to correct certain income tax errors related to prior periods. The adjustments, which are not considered material, resulted in a decrease in income tax expense of $1 million for the quarter ended March 31, 2009.

(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Statement of Financial Accounting Standards (SFAS) No. 141(R), “Business Combinations—a Replacement of FASB Statement No. 141” (SFAS No. 141 (R))

SFAS No. 141(R) replaces FASB Statement No. 141, “Business Combinations,” and retains the fundamental requirements that the acquisition method of accounting be used for all business combinations and for an acquirer to be identified for each business combination. However, SFAS No. 141(R) expands the definition of a business and amends FASB Statement No. 109, “Accounting for Income Taxes,” to require the acquirer to recognize changes in the amount of its deferred tax benefits that are realizable because of a business combination either in income from continuing operations or directly in contributed capital, depending on the circumstances.

On April 1, 2009, the FASB issued FSP Financial Accounting Standard (FAS) 141(R)-1 “Accounting for Assets and Liabilities Assumed in a Business Combination that Arise from Contingencies” (FSP FAS 141(R)-1), to clarify the accounting for the initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. FSP FAS 141(R)-1 requires that assets acquired and liabilities assumed in a business combination that arise from contingencies be measured at fair value if the acquisition date fair value of that asset and liability can be determined during the measurement period in accordance with SFAS No. 157. If the acquisition date fair value cannot be determined, then the asset or liability would be measured in accordance with SFAS No. 5, “Accounting for Contingencies,” and FIN 14, “Reasonable Estimate of the Amount of Loss.”

SFAS No. 141(R) and the guidance provided in FSP FAS 141(R)-1 applies prospectively to business combinations for which the acquisition date is on or after January 1, 2009. ACE adopted SFAS No. 141(R) on January 1, 2009, and it did not have a material impact on ACE’s overall financial condition, results of operations, or cash flows.

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FSP 157-2, “Effective Date of FASB Statement No. 157” (FSP 157-2)

FSP 157-2 deferred the effective date of SFAS No. 157, “Fair Value Measurements,” for all nonrecurring fair value measurements of non-financial assets and non-financial liabilities until January 1, 2009 for ACE. The adoption of SFAS No. 157 did not have a material impact on the fair value measurements of ACE’s non-financial assets and non-financial liabilities.

SFAS No. 160, “Non-controlling Interests in Consolidated Financial Statements—an Amendment of ARB No. 51” (SFAS No. 160)

SFAS No. 160 establishes new accounting and reporting standards for a non-controlling interest (previously called minority interest) in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a non-controlling interest in a subsidiary is an ownership interest in the consolidated entity that should be separately reported in the consolidated financial statements.

SFAS No. 160 establishes accounting and reporting standards that require (i) the ownership interests and the related consolidated net income in subsidiaries held by parties other than the parent be clearly identified, labeled, and presented in the consolidated balance sheets within equity, but separate from the parent’s equity, and presented separately on the face of the consolidated statement of earnings, (ii) the changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for as equity transactions, and (iii) when a subsidiary is deconsolidated, any retained non-controlling equity investment in the former subsidiary must be initially measured at fair value.

SFAS No. 160 was effective prospectively for financial statement reporting periods beginning January 1, 2009 for ACE, except for the financial statement presentation and disclosure requirements which also apply to prior reporting periods presented. As of January 1, 2009, ACE has adopted the provisions of SFAS No. 160, and the provisions did not have a material impact on ACE’s overall financial condition, results of operations, or cash flows.

(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

FSP FAS 107-1 and Accounting Principles Board (APB) 28-1, “Interim Disclosures about Fair Value of Financial Instruments” (FSP FAS 107-1 and APB 28-1)

On April 9, 2009, the FASB issued FSP FAS 107-1 and APB 28-1, which require quarterly disclosures of the fair value of financial instruments beginning with the second quarter of 2009. Prior to FSP FAS 107-1 and APB 28-1, these disclosures were only required on an annual basis. The disclosures for prior reporting periods are required after initial adoption.

FSP FAS 107-1 and APB 28-1 are effective for interim reporting periods ending after June 15, 2009 with the option to early adopt for interim periods ending after March 15, 2009. ACE elected not to early adopt; therefore, the disclosure requirements will be reflected in ACE’s second quarter 2009 Form 10-Q. The primary impact of the new standard will be the quarterly disclosure of the fair value of debt issued by ACE.

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FSP FAS 115-2 and FAS 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments” (FSP FAS 115-2 and FAS 124-2)

On April 9, 2009, the FASB issued FSP FAS 115-2 and FAS 124-2, which provided additional guidance on other-than-temporary impairment (OTTI) of debt and equity securities. It requires disclosure of information about the credit and noncredit component of an OTTI event and when an OTTI event has occurred. The FSP requires separate display on the statements of earnings, of losses related to credit deterioration and losses related to other market factors. Market-related losses will be recorded in accumulated other comprehensive (losses) earnings if it is not likely that the investor will have to sell the security prior to recovery.

FSP 115-2 and FAS 124-2 are effective for interim reporting periods ending after June 15, 2009, with the option to early adopt for interim periods ending after March 15, 2009. ACE elected not to early adopt. ACE does not anticipate the adoption of FSP 115-2 and FAS 124-2 to have a material impact on ACE’s overall financial condition, results of operations, or cash flows.

(5) SEGMENT INFORMATION

In accordance with SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information,” ACE has one segment, its regulated utility business.

(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, 2009 before intercompany allocations from the PHI Service Company, of $31 million includes $4 million for ACE’s allocated share. PHI’s pension and other postretirement net periodic benefit cost for the three months ended March 31, 2008 before intercompany allocations, of $16 million included $3 million for ACE’s allocated share.

(7) DEBT

PHI, Potomac Electric Power Company (Pepco), Delmarva Power & Light Company (DPL) and ACE maintain an unsecured credit facility to provide for their respective short-term liquidity needs. The aggregate borrowing limit under the facility is $1.5 billion, all or any portion of which may be used to obtain loans or to issue letters of credit. PHI’s credit limit under the facility is $875 million. The credit limit of each of Pepco, DPL and ACE is the lesser of $500 million and the maximum amount of debt the company is permitted to have outstanding by its regulatory authorities, except that the aggregate amount of credit used by Pepco, DPL and ACE at any given time collectively may not exceed $625 million.

In January 2009, ACE Funding made principal payments of $5.7 million on Series 2002-1 Bonds, Class A-2, and $2.1 million on Series 2003-1 Bonds, Class A-1.

In April 2009, ACE Funding made principal payments of $5.3 million on Series 2002-1 Bonds, Class A-2, and $2.1 million on Series 2003-1 Bonds, Class A-1.

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The continued disruptions in the capital and credit markets, combined with the volatility of energy prices, have had an impact on the borrowing capacity and liquidity of ACE. Since the third quarter of 2008, to address the challenges posed by the current capital and credit market environment and to ensure that ACE will continue to have sufficient access to cash to meet its liquidity needs, ACE has taken several measures to reduce expenditures and issued $250 million in long-term debt securities.

(8) INCOME TAXES

ACE’s income before income tax for the three months ended March 31, 2009 was less than $1 million; therefore, the consolidated effective income tax rate for the period is not meaningful. The income tax benefit in 2009 was primarily the result of the change in estimates and interest related to uncertain and effectively settled tax positions and the non-recurring adjustment to prior years’ taxes. The income tax benefit in the 2008 period was primarily the result of the change in estimates and interest related to uncertain and effectively settled tax positions due to the non-recurring impact of a tax claim filed with the Internal Revenue Service (IRS) in March 2008 for the current deduction of casualty losses on prior year returns currently under audit.

In March 2009, the IRS issued its Revenue Agent’s Report (RAR) for the audit of PHI’s consolidated federal income tax returns for the calendar years 2003 to 2005. The IRS has proposed adjustments to PHI’s tax returns, including adjustments to ACE’s capitalization of overhead costs for tax purposes and the deductibility of certain ACE casualty losses. In conjunction with PHI, ACE is taking steps to appeal certain of the proposed adjustments and believes it has adequately reserved for the adjustments included in the RAR.

During the first quarter of 2009, primarily as a result of the RAR, ACE reduced uncertain tax benefits by $15 million ($7 million as a result of settlements with taxing authorities and $8 million as adjustments to prior year tax positions).

(9) FAIR VALUE DISCLOSURES

Effective January 1, 2008, ACE adopted SFAS No. 157 which established a framework for measuring fair value and expands disclosures about fair value measurements.

As defined in SFAS No. 157, 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. ACE is able to classify fair value balances based on the observability of those inputs. SFAS No. 157 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

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assets or liabilities (level 1 measurement) and the lowest priority to unobservable inputs (level 3 measurement). The three levels of the fair value hierarchy defined by SFAS No. 157 are 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 pricing 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, 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 investments that are valued using models or other valuation methodologies.

The following tables set forth by level within the fair value hierarchy ACE’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2009 and December 31, 2008. As required by SFAS No. 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. ACE’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Fair Value Measurements at March 31, 2009
	(millions of dollars)
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
ASSETS
Cash equivalents	$	31	$	31	$	—	$	—
Executive deferred compensation plan assets		1		1		—		—
	$	32	$	32	$	—	$	—
LIABILITIES
Executive deferred compensation plan liabilities	$	1	$	—	$	1	$	—
	$	1	$	—	$	1	$	—

	Fair Value Measurements at December 31, 2008
	(millions of dollars)
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
ASSETS
Cash equivalents	$	76	$	76	$	—	$	—
Executive deferred compensation plan assets		1		1		—		—
	$	77	$	77	$	—	$	—
LIABILITIES
Executive deferred compensation plan liabilities	$	1	$	—	$	1	$	—
	$	1	$	—	$	1	$	—

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(10) COMMITMENTS AND CONTINGENCIES

Regulatory and Other Matters

Rate Proceedings

On February 20, 2009, ACE filed an application with the New Jersey Board of Public Utilities (NJBPU) (supplemented on February 23, 2009), which included a proposal for the implementation of a bill stabilization adjustment mechanism (BSA). Applicable New Jersey law requires that the NJBPU approve, modify or deny the application within 180 days. The NJBPU has advised ACE that the 180-day period commenced on February 23, 2009 and, therefore, ACE anticipates that NJBPU will act on ACE’s application, including the BSA request, by late August 2009.

Under the BSA, customer delivery rates are subject to adjustment (through a surcharge or credit mechanism), depending on whether actual distribution revenue per customer exceeds or falls short of the approved revenue-per-customer amount. The BSA increases rates if actual distribution revenues fall below the level approved by the applicable commission and decreases rates if actual distribution revenues are above the approved level. The result is that, over time, ACE collects its authorized revenues for distribution deliveries. As a consequence, a BSA “decouples” revenue from unit sales consumption and ties the growth in 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 utility distribution revenues that are better aligned with costs, (ii) provides for more reliable fixed-cost recovery, (iii) tends to stabilize customers’ delivery bills, and (iv) removes any disincentives for ACE to promote energy efficiency programs for their customers, because it breaks the link between overall sales volumes and delivery revenues.

ACE Sale of B.L. England Generating Facility

In February 2007, ACE completed the sale of the B.L. England generating facility to RC Cape May Holdings, LLC (RC Cape May), an affiliate of Rockland Capital Energy Investments, LLC. In July 2007, ACE received a claim for indemnification from RC Cape May under the purchase agreement in the amount of $25 million. RC Cape May contends that one of the assets it purchased, a contract for terminal services (TSA) between ACE and Citgo Asphalt Refining Co. (Citgo), has been declared by Citgo to have been terminated due to a failure by ACE to renew the contract in a timely manner. RC Cape May has commenced an arbitration proceeding against Citgo seeking a determination that the TSA remains in effect and has notified ACE of the proceeding. The claim for indemnification seeks payment from ACE in the event the TSA is held not to be enforceable against Citgo. While ACE believes that it has defenses to the indemnification claim, should the arbitrator rule that the TSA has terminated, the outcome of this matter is uncertain. The arbitration hearings were conducted in November 2008 and the parties filed post-hearing memoranda in the first quarter of 2009. A decision is expected late in the second quarter of 2009.

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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.

Delilah Road Landfill Site. In 1991, the New Jersey Department of Environmental Protection (NJDEP) identified ACE as a potentially responsible party (PRP) at the Delilah Road Landfill site in Egg Harbor Township, New Jersey. In 1993, ACE, along with two other PRPs, signed an administrative consent order with NJDEP to remediate the site. The soil cap remedy for the site has been implemented and in August 2006, NJDEP issued a No Further Action Letter (NFA) and Covenant Not to Sue for the site. Among other things, the NFA requires the PRPs to monitor the effectiveness of institutional (deed restriction) and engineering (cap) controls at the site every two years. In September 2007, NJDEP approved the PRP group’s petition to conduct semi-annual, rather than quarterly, ground water monitoring for two years and deferred until the end of the two-year period a decision on the PRP group’s request for annual groundwater monitoring thereafter. In August 2007, the PRP group agreed to reimburse the costs of the U.S. Environmental Protection Agency (EPA) in the amount of $81,400 in full satisfaction of EPA’s claims for all past and future response costs relating to the site (of which ACE’s share is one-third). Effective April 2008, EPA and the PRP group entered into a settlement agreement which will allow EPA to reopen the settlement in the event of new information or unknown conditions at the site. Based on information currently available, ACE anticipates that its share of additional cost associated with this site for post-remedy operation and maintenance will be approximately $555,000 to $600,000. On November 23, 2008, Lenox, Inc., a member of the PRP group, filed a bankruptcy petition under Chapter 11 of the U.S. Bankruptcy Code. ACE filed a proof of claim in the Lenox bankruptcy case in February 2009. ACE believes that its liability for post-remedy operation and maintenance costs will not have a material adverse effect on its financial position, results of operations or cash flows regardless of the impact of the Lenox bankruptcy.

Frontier Chemical Site. In June 2007, ACE received a letter from the New York Department of Environmental Conservation (NYDEC) identifying ACE as a PRP at the Frontier Chemical Waste Processing Company site in Niagara Falls, N.Y. based on hazardous waste manifests indicating that ACE sent in excess of 7,500 gallons of manifested hazardous waste to the site. ACE has entered into an agreement with the other parties identified as PRPs to form a PRP group and has informed NYDEC that it has entered into good faith negotiations with the PRP group to address ACE’s responsibility at the site. ACE believes that its responsibility at the site will not have a material adverse effect on its financial position, results of operations or cash flows.

Franklin Slag Pile Superfund Site. On November 26, 2008, ACE received a general notice letter from EPA concerning the Franklin Slag Pile Superfund Site in Philadelphia, Pennsylvania, asserting that ACE is a 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

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and for the costs of implementing an EPA-mandated remedy. The EPA’s claims are based on ACE’s sale of boiler slag from the B.L. England generating facility to MDC Industries, Inc. (MDC) during the period June 1978 to May 1983 (ACE owned B.L. England at that time and MDC formerly operated the Franklin Slag Pile Site). EPA further 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’s letter also states that to date its expenditures for response measures at the site exceed $6 million. EPA estimates approximately $6 million as the cost for future response measures it recommends. ACE understands that the 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, such 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 such claims made by the EPA. At this time ACE cannot predict how EPA will proceed or what portion, if any, of the Franklin Slag Pile Site response costs EPA would seek to recover from ACE.

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, which took effect November 5, 2007, 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 that was previously unregulated under the FHACA and that is otherwise regulated under a number of other state and federal programs. ACE filed an appeal of these regulations with the Appellate Division of the Superior Court of New Jersey on November 3, 2008.

IRS Mixed Service Cost Issue

During 2001, ACE changed its method of accounting with respect to capitalizable construction costs for income tax purposes. The change allowed the company to accelerate the deduction of certain expenses that were previously capitalized and depreciated. As a result of this method change, ACE generated incremental tax cash flow benefits of approximately $49 million.

In 2005, the IRS issued Revenue Ruling 2005-53, which limited the ability of ACE to utilize its tax accounting method on its 2001 through 2004 tax returns. Based on the Revenue Ruling and other Treasury Department guidance, PHI in its 2005 federal tax return adopted an alternative method of accounting for capitalizable construction costs that management believed would be acceptable to the IRS.

In line with this Revenue Ruling, the RAR for the 2001 and 2002 tax returns disallowed substantially all of the incremental tax benefits that ACE had claimed on those returns by requiring the company to capitalize and depreciate certain expenses rather than treat such expenses as current deductions.

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In March 2009, PHI reached a settlement with the IRS for all years (2001 through 2004) that is consistent with the approach adopted on the 2005 federal tax return. The terms of the settlement reduced the tax benefits related to the mixed service costs deductions by $6 million for ACE.

(11) 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, 2009 and 2008 were $25 million and $23 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 Earnings:

	For the Three Months Ended March 31,
	2009			2008
Income (Expense)	(millions of dollars)
Purchased power from Conectiv Energy Supply (a)	$	(46	)	$	(22	)
Meter reading services provided by Millennium Account Services LLC (b)		(1	)		(1	)
Intercompany use revenue (c)		(2	)		1
Intercompany use expense (c)		—			(1	)

(a) Included in purchased energy expense.

(b) Included in other operation and maintenance expense.

(c) Included in operating revenue.

As of March 31, 2009 and December 31, 2008, ACE had the following balances due (to) from related parties:

	March 31, 2009			December 31, 2008
Liability	(millions of dollars)
Payable to Related Party (current)
PHI Service Company	$	(11	)	$	(11	)
Conectiv Energy Supply		(14	)		(16	)

The items listed above are included in the “Accounts payable due to associated companies” balances on the Consolidated Balance Sheets of $25 million and $28 million at March 31, 2009 and December 31, 2008, respectively.

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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	105
Pepco	136
DPL	144
ACE	153

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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 diversified energy company that, through its operating subsidiaries, is engaged primarily in two businesses:

• the distribution, transmission and default supply of electricity and the delivery and supply of natural gas (Power Delivery)

• competitive energy generation, marketing and supply (Competitive Energy).

For the three months ended March 31, 2009 and 2008, PHI’s Power Delivery operations produced 54% and 49%, respectively, of PHI’s consolidated operating revenues (including revenues from intercompany transactions) and 74% and 47%, respectively, of PHI’s consolidated operating income (including income from intercompany transactions). The increase in Power Delivery’s consolidated operating income percentage in 2009 is due to the lower operating income of the Competitive Energy businesses.

The Power Delivery business consists primarily of the transmission, distribution and default supply of electricity which for the three months ended March 31, 2009 and 2008, was responsible for 90% and 91%, respectively, of Power Delivery’s operating revenues. The distribution of natural gas contributed 10% and 9%, respectively, of Power Delivery’s operating revenues for the three months ended March 31, 2009 and 2008. Power Delivery represents one operating segment for financial reporting purposes.

The Power Delivery business is conducted by PHI’s three utility subsidiaries: Potomac Electric Power Company (Pepco), Delmarva Power and 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 delivery 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 varies by jurisdiction as follows:

Delaware	Standard Offer Service (SOS)
District of Columbia	SOS
Maryland	SOS
New Jersey	Basic Generation Service

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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.

Effective January 2, 2008, DPL sold its retail electric distribution assets and its wholesale electric transmission assets in Virginia.

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.

In connection with its approval of new electric service distribution base rates for Pepco and DPL in Maryland, effective in June 2007, the Maryland Public Service Commission (MPSC) approved a bill stabilization adjustment mechanism (BSA) for retail customers. For customers to which the BSA applies, Pepco and DPL recognize 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 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 which 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 has no impact on reported revenue.

The Competitive Energy businesses provide competitive generation, marketing and supply of electricity and gas, and related energy management services primarily in the mid-Atlantic region. These operations are conducted through:

• Subsidiaries of Conectiv Energy Holding Company (collectively, Conectiv Energy), which engage primarily in the generation and wholesale supply and marketing of electricity and gas within the PJM Interconnection, LLC (PJM) and Independent System Operator – New England (ISONE) wholesale markets.

• Pepco Energy Services, Inc. and its subsidiaries (collectively, Pepco Energy Services), which provides retail energy supply and energy services primarily to commercial, industrial, and governmental customers.

Each of Conectiv Energy and Pepco Energy Services is a separate operating segment for financial reporting purposes. For the three months ended March 31, 2009 and 2008, the operating revenues of the Competitive Energy businesses (including revenue from intercompany transactions) were equal to 49% and 55%, respectively, of PHI’s consolidated operating revenues, and the operating income of the Competitive Energy businesses (including operating

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income from intercompany transactions) was 19% and 45% of PHI’s consolidated operating income for the three months ended March 31, 2009 and 2008, respectively. The decrease in the Competitive Energy businesses percentage of consolidated operating income is driven by the decrease in the Conectiv Energy’s operating income which was primarily due to substantially lower short-term sales of natural gas and natural gas transportation and storage rights in 2009. For the three months ended March 31, 2009 and 2008, 7% of the operating revenues of the Competitive Energy businesses was attributable to electric energy and capacity, and natural gas sold to the Power Delivery segment.

Conectiv Energy’s primary objective is to maximize the value of its generation fleet by leveraging its operational and fuel flexibilities. Pepco Energy Services’ primary objective is to capture retail energy supply and service opportunities predominately in the mid-Atlantic region. The financial results of the Competitive Energy business can be significantly affected by wholesale and retail energy prices, the cost of fuel and gas to operate the Conectiv Energy plants, and the cost of purchased energy necessary to meet its power and gas supply obligations.

The Competitive Energy businesses, like the Power Delivery business, are seasonal, and therefore weather patterns can have a material impact on operating results.

Through its subsidiary Potomac Capital Investment Corporation (PCI), PHI maintains a portfolio of cross-border energy sale-leaseback transactions with a book value at March 31, 2009 of approximately $1.3 billion. This activity constitutes a fourth operating segment, which is designated as “Other Non-Regulated,” for financial reporting purposes. For a discussion of PHI’s cross-border leasing transactions, 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 Item 1 of this Form 10-Q.

Earnings Overview

Three Months Ended March 31, 2009 Compared to Three Months Ended March 31, 2008

PHI’s net income for the three months ended March 31, 2009 was $45 million, or $0.21 per share, compared to $99 million, or $0.49 per share, for the three months ended March 31, 2008.

Net income for the three months ended March 31, 2009, included the credit set forth below in the Power Delivery operating segment, which is presented net of federal and state income taxes and is in millions of dollars:

Mirant Bankruptcy Settlement, Transfer of Panda PPA $  8

Excluding the item listed above, net income would have been $37 million, or $0.17 per share, for the three months ended March 31, 2009.

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PHI’s net income for the three months ended March 31, 2009 and 2008, by operating segment, is set forth in the table below (in millions of dollars):

	2009			2008			Change
Power Delivery	$	42		$	47		$	(5	)
Conectiv Energy		4			48			(44	)
Pepco Energy Services		8			9			(1	)
Other Non-Regulated		6			10			(4	)
Corp. & Other		(15	)		(15	)		—
Total PHI Net Income	$	45		$	99		$	(54	)

Discussion of Operating Segment Net Income Variances:

Power Delivery’s $5 million decrease in earnings is primarily due to the following:

• $5 million decrease due to higher operating and maintenance costs (primarily higher pension costs and bad-debt expense).

• $6 million decrease due to higher interest expense.

• $5 million decrease due to less favorable income tax adjustments than experienced in 2008 primarily related to Financial Accounting Standards Board Interpretation Number (FIN) 48 interest.

• $8 million increase due to the District of Columbia Public Service Commission’s approval of Pepco’s share of the remaining proceeds of the Mirant Corporation (Mirant) bankruptcy settlement, following the transfer of the Panda PPA.

• $3 million increase due to higher sales (primarily favorable impact of weather compared to 2008; partially offset by lower customer usage).

Conectiv Energy’s $44 million decrease in earnings is primarily due to the following:

• $26 million decrease due to significantly fewer opportunities to benefit from generating unit operating flexibility and fuel switching capability, and from remarketing activities around firm natural gas transportation and storage positions, due to less favorable energy prices and less price volatility than were experienced during the first quarter of 2008.

• $11 million decrease in generation margin due to significantly lower run-time and reduced spark-spreads.

• $5 million decrease due to lower margins from default electricity supply contracts and associated hedges.

Other Non-Regulated’s $4 million decrease in earnings is primarily due to the impact of the revised assumptions on the cross-border energy lease investments implemented in June 2008.

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Consolidated Results Of Operations

The following results of operations discussion is for the three months ended March 31, 2009, compared to the three months ended March 31, 2008. All amounts in the tables (except sales and customers) are in millions of dollars.

Operating Revenue

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

	2009			2008			Change
Power Delivery	$	1,372		$	1,295		$	77
Conectiv Energy		575			823			(248	)
Pepco Energy Services		657			621			36
Other Non-Regulated		13			18			(5	)
Corp. & Other		(97	)		(116	)		19
Total Operating Revenue	$	2,520		$	2,641		$	(121	)

Power Delivery Business

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

	2009		2008		Change
Regulated T&D Electric Revenue	$	387	$	379	$	8
Default Supply Revenue		836		785		51
Other Electric Revenue		18		15		3
Total Electric Operating Revenue		1,241		1,179		62
Regulated Gas Revenue		119		92		27
Other Gas Revenue		12		24		(12	)
Total Gas Operating Revenue		131		116		15
Total Power Delivery Operating Revenue	$	1,372	$	1,295	$	77

Regulated Transmission and Distribution (T&D) Electric Revenue includes revenue from the delivery of electricity, including the delivery of Default Electricity Supply, by PHI’s utility subsidiaries to customers within their service territories at regulated rates. Regulated T&D Electric Revenue also includes transmission service revenue that PHI’s utility subsidiaries receive as transmission owners from PJM.

Default Supply Revenue is the revenue received for Default Electricity Supply. The costs related to Default Electricity Supply are included in Fuel and Purchased Energy and Other Services Cost of Sales. Default Supply Revenue also includes revenue from transition bond charges and other restructuring related revenues.

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

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Regulated Gas Revenue consists of revenues for on-system natural gas sales and the transportation of natural gas for customers by DPL within its service territories 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.

Electric Operating Revenue

Regulated T&D Electric Revenue
	2009		2008		Change
Residential	$	144	$	133	$	11
Commercial and industrial		180		169		11
Other		63		77		(14	)
Total Regulated T&D Electric Revenue	$	387	$	379	$	8

Other Regulated T&D Electric Revenue consists primarily of (i) transmission service revenue and (ii) revenue from the resale of energy and capacity under power purchase agreements between Pepco and unaffiliated third parties in the PJM Regional Transmission Organization (PJM RTO) market.

Regulated T&D Electric Sales (Gigawatt hours (GWh))
	2009	2008	Change
Residential	4,774	4,485	289
Commercial and industrial	7,493	7,565	(72	)
Other	70	70	—
Total Regulated T&D Electric Sales	12,337	12,120	217

Regulated T&D Electric Customers (in thousands)
	2009	2008	Change
Residential	1,615	1,604	11
Commercial and industrial	197	196	1
Other	2	2	—
Total Regulated T&D Electric Customers	1,814	1,802	12

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

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• 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 automotive, chemical, glass, pharmaceutical, steel manufacturing, food processing, and oil refining.

Regulated T&D Electric Revenue increased by $8 million primarily due to:

• An increase of $9 million due to a distribution rate change as part of a higher New Jersey Societal Benefit Charge that became effective in June 2008 (substantially offset in Deferred Electric Service Costs).

• An increase of $4 million due to a distribution rate change in the District of Columbia that became effective in February 2008.

• An increase of $4 million due to higher sales in the service territories other than Maryland as the result of colder weather. Due to the adoption of a BSA, weather in the Maryland service territory no longer affects distribution revenue.

• An increase of $4 million due to higher pass-through revenue primarily resulting from a tax rate increase in Montgomery County, Maryland (primarily offset in Other Taxes).

The aggregate amount of these increases was partially offset by:

• A decrease of $15 million in Other Regulated T&D Electric Revenue (offset in Fuel and Purchased Energy and Other Services Cost of Sales) due to the absence of revenues from the resale of energy and capacity purchased under the power purchase agreement between Panda-Brandywine, L.P. and Pepco (the Panda PPA) as the result of the transfer of the Panda PPA to an unaffiliated third party in September 2008.

Default Electricity Supply

Default Supply Revenue
	2009		2008		Change
Residential	$	517	$	451	$	66
Commercial and industrial		260		248		12
Other		59		86		(27	)
Total Default Supply Revenue	$	836	$	785	$	51

Other Default Supply Revenue consists primarily of revenue from the resale of energy and capacity under non-utility generating contracts (NUGs) between ACE and unaffiliated third parties in the PJM RTO market.

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Default Electricity Supply Sales (GWh)
	2009	2008	Change
Residential	4,638	4,345	293
Commercial and industrial	2,472	2,340	132
Other	27	26	1
Total Default Electricity Supply Sales	7,137	6,711	426
Default Electricity Supply Customers (in thousands)
	2009	2008	Change
Residential	1,574	1,566	8
Commercial and industrial	166	164	2
Other	2	2	—
Total Default Electricity Supply Customers	1,742	1,732	10

Default Supply Revenue, which is substantially offset in Fuel and Purchased Energy and Other Services Cost of Sales and Deferred Electric Service Costs, increased by $51 million primarily due to:

• An increase of $33 million as the result of higher Default Electricity Supply rates.

• An increase of $32 million due to higher sales as the result of colder weather.

• An increase of $18 million primarily due to commercial customers migration from competitive suppliers to Default Electricity Supply.

The aggregate amount of these increases was partially offset by:

• A decrease of $27 million in wholesale energy revenues due to the sale at lower market prices of electricity purchased from NUGs.

Gas Operating Revenue

Regulated Gas Revenue
	2009		2008		Change
Residential	$	75	$	57	$	18
Commercial and industrial		42		33		9
Transportation and Other		2		2		—
Total Regulated Gas Revenue	$	119	$	92	$	27

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Regulated Gas Sales (billion cubic feet)
	2009	2008	Change
Residential	4	4	—
Commercial and industrial	3	2	1
Transportation and Other	2	3	(1	)
Total Regulated Gas Sales	9	9	—
Regulated Gas Customers (in thousands)
	2009	2008	Change
Residential	114	113	1
Commercial and industrial	9	9	—
Transportation and Other	—	—	—
Total Regulated Gas Customers	123	122	1

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

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

• Industrial activity in the region includes automotive, chemical and pharmaceutical.

Regulated Gas Revenue increased by $27 million primarily due to:

• An increase of $14 million primarily due to a Gas Cost Rate change effective November 2008 (offset in Fuel and Purchased Energy and Other Services Cost of Sales).

• An increase of $9 million due to higher sales as the result of colder weather.

• An increase of $8 million due to the recording of the unbilled portion of Gas Cost Rate revenue as discussed below (offset in Fuel and Purchased Energy and Other Services Cost of Sales).

The aggregate amount of these increases was partially offset by:

• A decrease of $4 million due to a net decrease in customer usage.

During the first quarter of 2009, DPL recorded additional revenue of $8 million related to the unbilled portion of its Gas Cost Rate (GCR) revenue, which was not previously recognized. Because the GCR revenue is deferred, an additional deferred gas expense was also recorded in the first quarter of 2009 (see Fuel and Purchased Energy and Other Services Cost of Sales). Consequently, there is no impact on the consolidated net earnings as a result of this adjustment.

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Other Gas Revenue

Other Gas Revenue, which is substantially offset in Fuel and Purchased Energy and Other Services Cost of Sales, decreased by $12 million primarily due to lower revenue from off-system sales, the result of a decrease in market prices. Off-system sales are made possible when low demand for natural gas by regulated customers creates excess pipeline capacity.

Conectiv Energy

The impact of Operating Revenue changes and Fuel and Purchased Energy and Other Services Cost of Sales changes with respect to the Conectiv Energy component of the Competitive Energy businesses are encompassed within the discussion that follows.

Operating Revenues of the Conectiv Energy segment are derived primarily from the sale of electricity. The primary components of its costs of sales are fuel and purchased power. Because fuel and electricity prices tend to move in tandem, price changes in these commodities from period to period can have a significant impact on Operating Revenue and Costs of Sales without signifying any change in the performance of the Conectiv Energy segment. Conectiv Energy also uses a number of and various types of derivative contracts to lock in sales margins, and to economically hedge its power and fuel purchases and sales. Gains and losses on derivative contracts are netted in revenue and Cost of Sales as appropriate under the applicable accounting rules. For these reasons, PHI from a managerial standpoint focuses on gross margin as a measure of performance.

Conectiv Energy Gross Margin

Merchant Generation & Load Service consists primarily of electric power, capacity and ancillary services sales from Conectiv Energy’s generating plants; tolling arrangements entered into to sell energy and other products from Conectiv Energy’s generating plants and to purchase energy and other products from generating plants of other companies; hedges of power, capacity, fuel and load; the sale of excess fuel (primarily natural gas); natural gas transportation and storage; emission allowances; electric power, capacity, and ancillary services sales pursuant to competitively bid contracts entered into with affiliated and non-affiliated companies to fulfill their default electricity supply obligations; and fuel switching activities made possible by the multi-fuel capabilities of some of Conectiv Energy’s power plants.

Energy Marketing activities consist primarily of wholesale natural gas and fuel oil marketing, the activities of the short-term power desk, which generates margin by capturing price differences between power pools and locational and timing differences within a power pool, and power origination activities, which primarily represent the fixed margin component of structured power transactions such as default supply service.

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Conectiv Energy Gross Margin and Operating Statistics	March 31,					Change
	2009		2008
Operating Revenue ($ millions):
Merchant Generation & Load Service	$	369	$	506		$	(137	)
Energy Marketing		206		317			(111	)
Total Operating Revenue1	$	575	$	823		$	(248	)
Cost of Sales ($ millions):
Merchant Generation & Load Service	$	326	$	391		$	(65	)
Energy Marketing		192		302			(110	)
Total Cost of Sales2	$	518	$	693		$	(175	)
Gross Margin ($ millions):
Merchant Generation & Load Service	$	43	$	115		$	(72	)
Energy Marketing		14		15			(1	)
Total Gross Margin	$	57	$	130		$	(73	)
Generation Fuel and Purchased Power Expenses ($ millions) 3:
Generation Fuel Expenses 4,5
Natural Gas	$	18	$	33		$	(15	)
Coal		9		16			(7	)
Oil		18		12			6
Other6		1		1			—
Total Generation Fuel Expenses	$	46	$	62		$	(16	)
Purchased Power Expenses 5	$	242	$	268		$	(26	)
Statistics:
Generation Output (MWh):
Base-Load 7		308,675		566,063			(257,388	)
Mid-Merit (Combined Cycle) 8		308,975		375,355			(66,380	)
Mid-Merit (Oil Fired) 9		34,163		(3,322	)		37,485
Peaking		2,720		3,533			(813	)
Tolled Generation		180,014		6,798			173,216
Total		834,547		948,427			(113,880	)
Load Service Volume (MWh) 10		2,009,958		2,933,341			(923,383	)
Average Power Sales Price 11 ($/MWh):
Generation Sales 4	$	71.91	$	93.52		$	(21.61	)
Non-Generation Sales 12	$	88.60	$	88.20		$	.40
Total	$	84.36	$	89.27		$	(4.91	)
Average on-peak spot power price at PJM East Hub ($/MWh) 13	$	60.81	$	84.25		$	(23.44	)
Average around-the-clock spot power price at PJM East Hub ($/MWh) 13	$	54.89	$	74.76		$	(19.87	)
Average spot natural gas price at market area M3 ($/MMBtu)14	$	6.28	$	10.13		$	(3.85	)
Weather (degree days at Philadelphia Airport): 15
Heating degree days		2,534		2,322			212
Cooling degree days		—		—			—

¹ Includes $91 million and $107 million of affiliate transactions for 2009 and 2008, respectively.

² Includes less than $1 million and $4 million of affiliate transactions for 2009 and 2008, respectively. Also, excludes depreciation and amortization expense of $9 million and $9 million, respectively.

³ Consists solely of Merchant Generation & Load Service expenses; does not include the cost of fuel not consumed by the power plants and intercompany tolling expenses.

⁴ Includes tolled generation.

⁵ Includes associated hedging gains and losses.

⁶ Includes emissions expenses, fuel additives, and other fuel-related costs.

⁷ Edge Moor Units 3 and 4 and Deepwater Unit 6.

⁸ Hay Road and Bethlehem, all units.

⁹ Edge Moor Unit 5 and Deepwater Unit 1. Generation output for these units was negative for the first quarter of 2009 because of station service consumption.

¹⁰ Consists of all default electricity supply sales; does not include standard product hedge volumes.

¹¹ Calculated from data reported in Conectiv Energy’s Electric Quarterly Report (EQR) filed with the FERC; does not include capacity or ancillary services revenue.

¹² Consists of default electricity supply sales, standard product power sales, and spot power sales other than merchant generation as reported in Conectiv Energy’s EQR.

¹³ Source: PJM website (www.pjm.com).

¹⁴ Source: Average delivered natural gas price at Tetco Zone M3 as published in Gas Daily.

¹⁵ Source: National Oceanic and Atmospheric Administration National Weather Service data.

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Conectiv Energy’s revenue and cost of sales are lower in 2009 primarily due to decreased demand related to the current economy that adversely affected generation and default electricity supply volumes, and lower energy commodity prices. Conectiv Energy’s ability to take advantage of its fleet of mid-merit and peaking generation assets to generate high margins during peak usage periods was restricted by the depressed energy commodity prices during the first quarter of 2009. The spreads for Conectiv Energy’s coal power plants were also much smaller in first quarter of 2009 which contributed to reduced run-time. Conectiv Energy’s margins in the first quarter of 2008 were favorably affected by higher energy commodity prices and price volatility during that period.

Merchant Generation & Load Service gross margin decreased approximately $72 million primarily due to:

• A decrease of approximately $44 million due to significantly fewer opportunities to benefit from generating unit operating flexibility and fuel switching capability (as described below) and from remarketing activities around firm natural gas transportation and storage positions due to less favorable energy prices and less price volatility than were experienced during the first quarter of 2008. Fuel switching capability is the ability of the combined cycle mid-merit units to generate electricity utilizing either natural gas or oil, allowing the fuel not used to generate electricity to be sold, for purposes of maximizing the combined margin from the sale of electricity and excess fuel. In the first quarter of 2008, the magnitude of the gross margin increase related to these activities was greater than had been typically realized in the past due, in part, to significant fuel price increases in conjunction with less significant increases in power prices.

• A decrease of approximately $19 million of generation margin due to significantly lower run-time and reduced spark-spreads.

• A decrease of approximately $8 million due to lower margins from default electricity supply contracts and associated hedges. Reduced demand directly contributed to the lower margins and also caused early recognition of hedge losses of approximately $2 million.

Energy Marketing gross margin remained substantially the same between the first quarter of 2008 and 2009. Oil marketing was up about $4 million, and gas marketing was off about the same amount. Power origination and short-term power arbitrage performed consistently in both periods.

Pepco Energy Services

Pepco Energy Services’ operating revenue increased $36 million primarily due to:

• An increase of $46 million due to higher electricity sales prices in 2009.

• A decrease of $17 million due to less construction activity.

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Operating Expenses

Fuel and Purchased Energy and Other Services Cost of Sales

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

	2009			2008			Change
Power Delivery	$	946		$	836		$	110
Conectiv Energy		518			693			(175	)
Pepco Energy Services		614			584			30
Corp. & Other		(95	)		(115	)		20
Total	$	1,983		$	1,998		$	(15	)

Power Delivery Business

Power Delivery’s Fuel and Purchased Energy and Other Services Cost of Sales, which is primarily associated with Default Electricity Supply sales, increased by $110 million primarily due to:

• An increase of $40 million due to a higher rate of recovery on electric supply costs resulting in a change in the Default Electricity Supply deferral balance.

• An increase of $34 million due to higher sales as a result of colder weather.

• An increase of $26 million in average energy prices, the result of new Default Electricity Supply contracts.

• An increase of $18 million from the settlement of financial hedges (entered into as part of DPL’s regulated natural gas hedge program).

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

• An increase of $7 million primarily due to commercial customer migration from competitive suppliers to Default Electricity Supply.

The aggregate amount of these increases was partially offset by:

• A decrease of $15 million due to the termination of energy and capacity purchased under the Panda PPA.

• A decrease of $11 million in the cost of gas purchases for off-system sales, the result of lower average gas prices.

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Fuel and Purchased Energy expense is substantially offset in Regulated T&D Electric Revenue, Default Supply Revenue, Regulated Gas Revenue, Other Gas Revenue and Deferred Electric Service Costs.

Conectiv Energy

The impact of Fuel and Purchased Energy and Other Services Cost of Sales changes with respect to the Conectiv Energy component of the Competitive Energy businesses is encompassed within the prior discussion under the heading “Conectiv Energy Gross Margin.”

Pepco Energy Services

Pepco Energy Services’ Fuel and Purchased Energy and Other Services Cost of Sales increased $30 million primarily due to:

• An increase of $35 million due to higher cost of electricity to serve retail customers in 2009.

Other Operation and Maintenance

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

	2009			2008			Change
Power Delivery	$	186		$	171		$	15
Conectiv Energy		33			33			—
Pepco Energy Services		23			19			4
Other Non-Regulated		—			1			(1	)
Corp. & Other		(6	)		(5	)		(1	)
Total	$	236		$	219		$	17

Other Operation and Maintenance expense for Power Delivery increased by $15 million; however, excluding an increase of $6 million primarily related to bad debt expenses that are deferred and recoverable, Other Operation and Maintenance expense increased by $9 million. The $9 million increase was primarily due to:

• An increase of $9 million in employee-related costs primarily due to higher pension expenses.

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

Depreciation and Amortization

Depreciation and Amortization expenses increased by $5 million to $96 million in 2009, from $91 million in 2008 primarily due to utility plant additions.

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Deferred Electric Service Costs

Deferred Electric Service Costs, which relate only to ACE, decreased by $52 million to income of $27 million in 2009 from an expense of $25 million in 2008. The decrease was primarily due to:

• A decrease of $57 million due to a lower rate of recovery of costs associated with energy and capacity purchased under the NUGs.

• A decrease of $7 million due to a lower rate of recovery associated with deferred energy costs.

The aggregate amount of these decreases was partially offset by:

• An increase of $8 million due a higher rate of recovery associated with New Jersey Societal Benefit program costs.

• An increase of $3 million due to a higher rate of recovery associated with deferred transmission costs.

Deferred Electric Service Costs are substantially offset in Regulated T&D Electric Revenue, Default Supply Revenue and Fuel and Purchased Energy and Other Services Cost of Sales.

Effect of Settlement of Mirant Bankruptcy Claims

In September 2008, Pepco transferred the Panda PPA to an unaffiliated third party. In March 2009, the District of Columbia Public Service Commission approved an allocation between Pepco and its District of Columbia customers of the District of Columbia portion of the Mirant bankruptcy settlement proceeds remaining after the transfer of the Panda PPA. As a result, Pepco recorded a pre-tax gain of $14 million reflecting the District of Columbia proceeds retained by Pepco. A proposed settlement allocating the Maryland portion of the remaining Mirant bankruptcy settlement proceeds between Pepco and its Maryland customers is pending before the Maryland Public Service Commission.

Gain on Sale of Assets

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

Other Income (Expenses)

Other Expenses (which are net of Other Income) increased by $15 million to a net expense of $86 million in 2009 from a net expense of $71 million in 2008. The increase was primarily due to an $11 million net increase in interest expense on long-term debt as the result of a higher amount of outstanding debt.

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Income Tax Expense

PHI’s effective tax rates for the three months ended March 31, 2009 and 2008 were 34.8% and 34.6%, respectively. While the effective rate was consistent between the periods, there were differences in specific items comprising the rate. An increase in the rate resulted from a change in the flow-through of certain book / tax depreciation differences, and changes in estimates and interest related to uncertain and effectively settled tax positions. The increase in the change in estimates and interest related to uncertain and effectively settled tax positions is primarily due to the non-recurring impact of a tax claim filed with the Internal Revenue Service in March 2008. The claim was for the treatment of casualty losses as current deductions (as opposed to being depreciated over their tax lives) on prior year tax returns currently under audit. These increases were offset by other changes, primarily related to an adjustment to prior years’ taxes and tax credits.

Income Tax Adjustments

During the first quarter of 2009, ACE recorded adjustments to correct certain income tax errors related to prior periods. The adjustments, which are not considered material, resulted in a decrease in Income Tax Expense of $1 million for the quarter ended March 31, 2009.

Capital Resources And Liquidity

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

Working Capital

At March 31, 2009, Pepco Holdings’ current assets on a consolidated basis totaled $2.6 billion and its current liabilities totaled $2.2 billion. At December 31, 2008, Pepco Holdings’ current assets totaled $2.6 billion and its current liabilities totaled $2 billion. The decrease in working capital from December 31, 2008 to March 31, 2009 is primarily due to a decrease in the balance of prepaid income taxes and inventories.

At March 31, 2009, Pepco Holdings’ cash and current cash equivalents totaled $580 million of which $538 million was invested in money market funds that invest in U.S. Treasury obligations, and the balance was held as cash and uncollected funds. Current restricted cash (cash that is available to be used only for designated purposes) totaled $10 million. At December 31, 2008, Pepco Holdings’ cash and current cash equivalents totaled $384 million and its current restricted cash totaled $10 million. See “Capital Requirements – Contractual Arrangements with Credit Rating Triggers or Margining Rights” herein for additional information.

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

	As of March 31, 2009
	(millions of dollars)
Type	PHI Parent		Pepco		DPL		ACE		ACE Funding		Conectiv Energy		Pepco Energy Services		PCI		Conectiv		PHI Consolidated
Variable Rate Demand Bonds	$	—	$	—	$	96	$	1	$	—	$	—	$	21	$	—	$	—	$	118
Bonds held under Standby Bond Purchase Agreement		—		—		—		22		—		—		—		—		—		22
Commercial Paper		140		—		—		—		—		—		—		—		—		140
Bank Loans		—		25		150		—		—		—		—		—		—		175
Credit Facility Loans		150		100		—		—		—		—		—		—		—		250
Total Short-Term Debt	$	290	$	125	$	246	$	23	$	—	$	—	$	21	$	—	$	—	$	705
Current Maturities of Long-Term Debt and Project Funding	$	—	$	16	$	—	$	—	$	32	$	—	$	3	$	—	$	—	$	51
	As of December 31, 2008
	(millions of dollars)
Type	PHI Parent		Pepco		DPL		ACE		ACE Funding		Conectiv Energy		Pepco Energy Services		PCI		Conectiv		PHI Consolidated
Variable Rate Demand Bonds	$	—	$	—	$	96	$	1	$	—	$	—	$	21	$	—	$	—	$	118
Bonds held under Standby Bond Purchase Agreement		—		—		—		22		—		—		—		—		—		22
Commercial Paper		—		—		—		—		—		—		—		—		—		—
Bank Loans		—		25		150		—		—		—		—		—		—		175
Credit Facility Loans		50		100		—		—		—		—		—		—		—		150
Total Short-Term Debt	$	50	$	125	$	246	$	23	$	—	$	—	$	21	$	—	$	—	$	465
Current Maturities of Long-Term Debt and Project Funding	$	—	$	50	$	—	$	—	$	32	$	—	$	3	$	—	$	—	$	85

Financing Activity During the Three Months Ended March 31, 2009

PHI and its utility subsidiaries historically have issued commercial paper as required to meet their short-term working capital requirements. As a result of recent disruptions in the commercial paper markets, the companies have borrowed under the $1.5 billion credit facility to create a cash reserve for future short-term operating needs. At March 31, 2009, PHI had an outstanding loan of $150 million, and Pepco had an outstanding loan of $100 million, which was repaid at maturity in April 2009.

In January 2009, ACE Funding made principal payments of $5.7 million on Series 2002-1 Bonds, Class A-2, and $2.1 million on Series 2003-1 Bonds, Class A-1.

In January 2009, Pepco redeemed $50 million of 6.25% medium-term notes at maturity.

In March 2009, Pepco resold $110 million of Pollution Control Revenue Refunding Bonds which previously had been issued for the benefit of Pepco by the Maryland Economic Development Corporation. Pepco purchased the bonds in 2008 in response to disruption in the

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municipal auction rate securities market that made it difficult for the remarketing agent to successfully remarket the bonds. As the owner of the bonds, Pepco received the proceeds of the sale, which it intends to use for general corporate purposes.

Financing Activity Subsequent to March 31, 2009

In April 2009, ACE Funding made principal payments of $5.3 million on Series 2002-1 Bonds, Class A-2, and $2.1 million on Series 2003-1 Bonds, Class A-1.

In April 2009, Pepco repaid, prior to maturity, a $25 million short-term loan.

In April 2009, DPL resold $9 million of its Pollution Control Revenue Refunding bonds issued by the Delaware Economic Development Authority. These bonds were repurchased by DPL in November 2008 in response to disruption in the tax-exempt bond market that made it difficult for the remarketing agent to successfully remarket the bonds. As the owner of the bonds, DPL received the proceeds of the sale and intends to use the proceeds for general corporate purposes.

In May 2009, DPL repaid, prior to maturity, $50 million of a $150 million short-term loan which matures in July 2009.

In May 2009, PHI entered into a $50 million, 18 month bi-lateral credit agreement, which can only be used for the purpose of obtaining letters of credit.

Credit Facilities

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

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

The facility is intended to serve primarily as a source of liquidity to support the commercial paper programs of the respective companies. The companies also are permitted to use the facility to borrow funds for general corporate purposes and issue letters of credit. In order for a borrower to use the facility, certain representations and warranties must be true and correct,

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and the borrower must be in compliance with specified covenants, including (i) the requirement that each borrowing company maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the credit agreement, which calculation excludes from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) a restriction on sales or other dispositions of assets, other than certain sales and dispositions, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than permitted liens. The absence of a material adverse change in the borrower’s business, property, and results of operations or financial condition is not a condition to the availability of credit under the facility. The facility does not include any rating triggers.

In November 2008, PHI entered into a second unsecured credit facility in the amount of $400 million. Under the facility, PHI may obtain revolving loans and swingline loans over the term of the facility, which expires on November 6, 2009. The facility does not provide for the issuance of letters of credit. The interest rate payable on funds borrowed under the facility is, at PHI’s election, based on either (a) the prevailing Eurodollar rate 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 that varies according to the credit rating of PHI. Under the swingline loan sub-facility, PHI may obtain loans for up to seven days in an aggregate principal amount which does not exceed 10% of the aggregate borrowing limit under the facility. In order to obtain loans under the facility, PHI must be in compliance with the same covenants and conditions that it is required to satisfy for utilization of the primary credit facility. The absence of a material adverse change in PHI’s business, property, and results of operations or financial condition is not a condition to the availability of credit under the facility. The facility does not include any ratings triggers.

These two facilities are referred to herein collectively as PHI’s “primary credit facilities.”

Cash and Credit Facilities Available as of March 31, 2009

	Consolidated PHI			PHI Parent			Utility Subsidiaries
	(millions of dollars)
Credit Facilities (Total Capacity)	$	1,900		$	1,275		$	625
Borrowings under Credit Facilities		(250	)		(150	)		(100	)
Letters of Credit		(305	)		(300	)		(5	)
Commercial Paper Outstanding		(140	)		(140	)		—
Remaining Credit Facilities Available		1,205			685			520
Cash Invested in Money Market Funds (a)		538			47			491
Total Cash and Credit Facilities Available	$	1,743		$	732		$	1,011

(a) Cash and cash equivalents reported on the Balance Sheet total $580 million, which includes the $538 million invested in money market funds and $42 million held in cash and uncollected funds.

The recent disruptions in the capital and credit markets, combined with the volatility of energy prices, have had an impact on borrowing capacity and liquidity of PHI and its subsidiaries. To address the challenges posed by the current capital and credit market environment and to ensure that PHI and its subsidiaries will continue to have sufficient access to cash to meet their liquidity needs, PHI and its subsidiaries undertook a number of actions in the first quarter of 2009 (in addition to those actions taken during 2008), including the following:

• In March 2009, Pepco resold $110 million of its Pollution Control Revenue Refunding Bonds issued by the Maryland Economic Development Corporation (see “Financing Activities During the Three Months ended March 31, 2009”), and

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• In March 2009, Pepco Energy Services entered into a credit intermediation arrangement with an investment banking firm to reduce the collateral requirements associated with its retail energy sales business (see “Collateral Requirements of the Competitive Energy Businesses”).

At March 31, 2009, the amount of cash, plus borrowing capacity under PHI’s primary credit facilities available to meet the liquidity needs of PHI and its utility subsidiaries on a consolidated basis totaled $1.7 billion, of which $1.0 billion consisted of the combined cash and borrowing capacity of PHI’s utility subsidiaries. At December 31, 2008, the amount of cash, plus borrowing capacity under the syndicated credit facilities available to meet the liquidity needs of PHI on a consolidated basis totaled $1.5 billion, of which $843 million consisted of the combined cash and borrowing capacity of PHI’s utility subsidiaries.

Collateral Requirements of the Competitive Energy Businesses

In conducting its retail energy sales business, Pepco Energy Services, during periods of declining energy prices, has been exposed to the asymmetrical risk of having to post collateral under its wholesale purchase contracts without receiving a corresponding amount of collateral from its retail customers. To partially address these asymmetrical collateral obligations, Pepco Energy Services, in the first quarter of 2009, entered into a credit intermediation arrangement with Morgan Stanley Capital Group, Inc. (MSCG). Under this arrangement, MSCG, in consideration for the payment to MSCG of certain fees, (i) has assumed by novation the electricity purchase obligations of Pepco Energy Services in years 2009 through 2011 under several wholesale purchase contracts and (ii) has agreed to supply electricity to Pepco Energy Services on the same terms as the novated transactions, but without imposing on Pepco Energy Services any associated collateral obligations. As of March 31, 2009, approximately 39% of Pepco Energy Services’ wholesale electricity purchase obligations (measured in megawatt hours) were covered by this credit intermediation arrangement with MSCG. The fees incurred by Pepco Energy Services in the amount of $25 million are being amortized in declining amounts over the life of the arrangement based on the fair value of the underlying contracts at the time of the novation.

In addition to Pepco Energy Services’ retail energy sales business, Conectiv Energy and Pepco Energy Services in the ordinary course of business enter into various contracts to buy and sell electricity, fuels and related products, including derivative instruments, designed to reduce their financial exposure to changes in the value of their assets and obligations due to energy price fluctuations. These contracts also typically have collateral requirements.

Depending on the contract terms, the collateral required to be posted by Pepco Energy Services and Conectiv Energy can be of varying forms, including cash and letters of credit. As of March 31, 2009, the Competitive Energy businesses (including Pepco Energy Services’ retail energy sales business) had posted net cash collateral of $581 million and letters of credit of $296 million. At December 31, 2008, the Competitive Energy businesses had posted net cash collateral of $331 million and letters of credit of $558 million.

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At March 31, 2009, the amount of cash, plus borrowing capacity under PHI’s primary credit facilities available to meet the future liquidity needs of the Competitive Energy businesses totaled $732 million.

Cash Flow Activity

PHI’s cash flows for the three months ended March 31, 2009 and 2008 are summarized below:

	Cash Source
	2009			2008
	(millions of dollars)
Operating Activities	$	126		$	347
Investing Activities		(180	)		(132	)
Financing Activities		250			46
Net increase in cash and cash equivalents	$	196		$	261

Operating Activities

Cash flows from operating activities during the three months ended March 31, 2009 and 2008 are summarized below:

	Cash Source
	2009			2008
	(millions of dollars)
Net Income	$	45		$	99
Non-cash adjustments to net income		192			95
Changes in working capital		(111	)		153
Net cash from operating activities	$	126		$	347

Net cash from operating activities was $221 million lower for the three months ended March 31, 2009, compared to the same period in 2008. In addition to the decrease in net income, the primary contributor was a $376 million increase in cash collateral requirements associated with Competitive Energy activities. The cash collateral requirements of the Competitive Energy businesses fluctuate significantly based on changes in energy market prices.

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Investing Activities

Cash flows from investing activities during the three months ended March 31, 2009 and 2008 are summarized below:

	Cash Use
	2009			2008
	(millions of dollars)
Construction expenditures	$	(180	)	$	(171	)
Cash proceeds from sale of assets		—			51
All other investing cash flows, net		—			(12	)
Net cash used by investing activities	$	(180	)	$	(132	)

Net cash used by investing activities increased $48 million for the three months ended March 31, 2009 compared to the same period in 2008. While construction expenditures remained consistent from 2008 to 2009, cash used by investing activities in 2009 was greater as a result of the inclusion in 2008 of the proceeds from the sale of assets in 2008, which consisted of $51 million received from DPL’s sale of its retail electric distribution assets and its wholesale electric transmission assets in Virginia.

Financing Activities

Cash flows from financing activities during the three months ended March 31, 2009 and 2008 are summarized below:

	Cash Source
	2009			2008
	(millions of dollars)
Dividends paid on common and preferred stock	$	(59	)	$	(54	)
Common stock issued for the Dividend Reinvestment Plan		7			7
Issuance of common stock		8			12
Issuances of long-term debt		110			400
Reacquisition of long-term debt		(58	)		(183	)
Issuances (repayments) of short-term debt, net		240			(102	)
All other financing cash flows, net		2			(34	)
Net cash provided by financing activities	$	250		$	46

Net cash from financing activities increased $204 million for the three months ended March 31, 2009, compared to the same period in 2008.

Common Stock Dividends

Common stock dividend payments were $59 million in the first quarter of 2009 and $54 million in the first quarter of 2008. The increase in common dividends paid in 2009 was the result of additional shares outstanding, primarily from the PHI sale of 16.1 million shares of common stock in November 2008.

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Changes in Outstanding Common Stock

Under the Long-Term Incentive Plan, PHI issued 165,870 shares of common stock during the three months ended March 31, 2009, and 544,704 shares of common stock during the three months ended March 31, 2008. In addition, under PHI’s Shareholder Dividend Reinvestment Plan, 565,117 shares of common stock were issued during the three months ended March 31, 2009 and 289,344 were issued during the three months ended March 31, 2008.

Changes in Outstanding Long-Term Debt

Cash flows from the issuance and redemption of long-term debt for the three months ended March 31, 2009 and for the three months ended March 31, 2008 are summarized in the charts below:

		2009		2008
Issuances		(millions of dollars)
Pepco
	6.5% Senior notes due 2037 (a)	$	—	$	250
	6.2% Tax-exempt bonds (b)		110		—
Total		$	110	$	250	(c)

(a) Secured by an outstanding series of First Mortgage Bonds.

(b) Consists of Pollution Control Revenue Refunding Bonds issued by the Maryland Economic Development Corporation, which were repurchased by Pepco during 2008, but were considered extinguished for accounting purposes and resold in March 2009.

(c) Excludes DPL’s $150 million 2-year bank loan that was converted to a 364-day bank loan.

		2009		2008
Redemptions		(millions of dollars)
Pepco
	6.5% First mortgage bonds due 2008	$	—	$	78
	6.25% Medium-term notes		50		—
		$	50	$	78
DPL
	Auction rate, tax-exempt bonds (a)	$	—	$	58
		$	—	$	58
ACE
	6.79% Medium-term notes due 2008	$	—	$	15
	Auction rate, tax-exempt bonds (a)		—		25
	Securitization bonds due 2008-2009		8		7
		$	8	$	47
Total		$	58	$	183

(a) Consists of tax-exempt bonds issued for the benefit of the indicated company, which are held pending resale to the public. The bonds are considered extinguished for accounting purposes.

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Changes in Short-Term Debt

The $240 million increase in short-term debt during the three months ended March 31, 2009, was primarily due to borrowing under the $1.5 billion credit facility of $100 million by PHI and an increase in commercial paper issued of $140 million to create a cash reserve for future short-term operating needs. At March 31, 2009, PHI had an outstanding loan of $150 million, and Pepco had an outstanding loan of $100 million. The PHI loan matured during April 2009 and was rolled to May 2009 while the Pepco loan was repaid in April. PHI expects to continue to roll its loan monthly until it is able to meet all of its funding needs in the commercial paper market.

Sale of Virginia Retail Electric Distribution and Wholesale Transmission Assets

In January 2008, DPL completed (i) the sale of its retail electric distribution assets on the Eastern Shore of Virginia to A&N Electric Cooperative for a purchase price of approximately $49 million, after closing adjustments, and (ii) the sale of its wholesale electric transmission assets located on the Eastern Shore of Virginia to Old Dominion Electric Cooperative for a purchase price of approximately $5 million, after closing adjustments.

Proceeds from Settlement of Mirant Bankruptcy Claims

In 2000, Pepco sold substantially all of its electricity generating assets to Mirant. As part of the sale, Pepco and Mirant entered into a “back-to-back” arrangement, whereby Mirant agreed to purchase from Pepco the 230 megawatts of electricity and capacity that Pepco was obligated to purchase annually through 2021 from Panda under the Panda PPA at the purchase price Pepco was obligated to pay to Panda. In 2003, Mirant commenced a voluntary bankruptcy proceeding in which it sought to reject certain obligations that it had undertaken in connection with the asset sale. As part of the settlement of Pepco’s claims against Mirant arising from the bankruptcy, Pepco agreed not to contest the rejection by Mirant of its obligations under the “back-to-back” arrangement in exchange for the payment by Mirant of damages corresponding to the estimated amount by which the purchase price that Pepco was obligated to pay Panda for the energy and capacity exceeded the market price. In 2007, Pepco received as damages $414 million in net proceeds from the sale of shares of Mirant common stock issued to it by Mirant. In September 2008, Pepco transferred the Panda PPA to Sempra Energy Trading LLC (Sempra), along with a payment to Sempra, thereby terminating all further rights, obligations and liabilities of Pepco under the Panda PPA. In November 2008, Pepco filed with the District of Columbia Public Service Commission (DCPSC) and the Maryland Public Service Commission (MPSC) proposals to share with customers the remaining balance of proceeds from the Mirant settlement in accordance with divestiture sharing formulas previously approved by the respective commissions.

On March 5, 2009, the DCPSC issued an order approving Pepco’s sharing proposal. Under the order and Pepco’s compliance filing tariff, which was deemed effective on March 20, 2009, approximately $24 million has been reflected in customers’ April 2009 bills as a one-time credit. As a result of this decision, Pepco recorded a pre-tax gain of approximately $14 million for the quarter ended March 31, 2009.

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On February 17, 2009, Pepco, the Maryland Office of People’s Counsel (the Maryland OPC) and the MPSC staff filed a settlement agreement with the MPSC, which, among other things, provides that Pepco would distribute $39 million of the remaining balance of the Mirant settlement to its Maryland customers through a one-time billing credit. If the settlement is approved by the MPSC, Pepco currently estimates that it would result in a pre-tax gain in the range of $15 million to $25 million, which would be recorded when the MPSC issues its final order approving the settlement. A hearing before the MPSC on the settlement is scheduled for May 14, 2009.

Pending the final disposition of these funds in Maryland, as of March 31, 2009, approximately $64 million in remaining proceeds from the Mirant settlement is being accounted for as restricted cash and approximately $88 million is being accounted for as a regulatory liability. The regulatory liability is comprised of approximately $64 million awaiting final regulatory resolution and approximately $24 million relating to the one-time customer credit approved by the DCPSC.

Capital Requirements

Capital Expenditures

Pepco Holdings’ total capital expenditures for the three months ended March 31, 2009 totaled $180 million, of which $67 million was incurred by Pepco, $37 million was incurred by DPL, $28 million was incurred by ACE and $41 million was incurred by Conectiv Energy. The remainder was incurred primarily by Pepco Energy Services. The Power Delivery expenditures were primarily related to capital costs associated with new customer services, distribution reliability, and transmission.

During the first quarter of 2009, PHI updated the projected capital expenditures for the Power Delivery business for 2009. The updated expenditures are as follows:

	2009
	Pepco		DPL		ACE		Total
	(millions of dollars)
Distribution	$	209	$	108	$	97	$	414
Distribution – Blueprint for the Future		9		34		6		49
Distribution – NJ Infrastructure Investment Plan (a)		—		—		13		13
Transmission		45		62		28		135
Transmission – Mid-Atlantic Power Pathway		46		10		—		56
Gas Delivery		—		21		—		21
Other		14		17		8		39
Total	$	323	$	252	$	152	$	727

(a) On April 16, 2009, the New Jersey BPU approved ACE’s proposed Infrastructure Investment Plan and the revenue requirement associated with recovering the cost of these projects, subject to a prudency review in the next rate case. The approved projects will simultaneously enhance reliability of ACE’s system and support economic activity and job growth in New Jersey in the near term. Cost recovery will be through an Infrastructure Investment Surcharge effective on June 1, 2009. This approved plan will add incremental capital spending of approximately $13 million for 2009 and $15 million for 2010. Additionally, ACE is required to file a rate case no later than April 1, 2011. As part of this base rate case, the remaining unamortized amounts associated with these projects will be placed into rate base.

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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 23, 2009, Pepco Holdings’ Board of Directors declared a dividend on common stock of 27 cents per share payable June 30, 2009, to shareholders of record on June 10, 2009.

Energy Contract Net Asset Activity

The following table provides detail on changes in the net asset or liability position of the Competitive Energy businesses (consisting of the activities of the Conectiv Energy and Pepco Energy Services segments) with respect to energy commodity contracts for the three months ended March 31,2009. The balances reflected in the table are stated gross, pre-tax and before the netting of collateral required by FIN 39-1.

	Energy Commodity Activities (a)
	(millions of dollars)
Total Fair Value of Energy Contract Net Liabilities at December 31, 2008	$	(314	)
Current period unrealized gains		9
Effective portion of changes in fair value - recorded in Accumulated Other Comprehensive Loss		(246	)
Cash flow hedge ineffectiveness - recorded in earnings		(6	)
Recognition of realized gains (losses) on settlement of contracts		52
Total Fair Value of Energy Contract Net Liabilities at March 31, 2009	$	(505	)
	Total
Detail of Fair Value of Energy Contract Net Liabilities at March 31, 2009 (see above)
Derivative assets (current assets)	$	112
Derivative assets (non-current assets)		35
Total Fair Value of Energy Contract Assets		147
Derivative Liabilities (current liabilities)		(511	)
Derivative liabilities (non-current liabilities)		(141	)
Total Fair Value of Energy Contract Liabilities		(652	)
Total Fair Value Energy of Contract Net Liabilities	$	(505	)

Notes:

(a) Includes all SFAS No. 133 hedge activity and trading activities recorded at fair value through Accumulated Other Comprehensive Loss (AOCL) or on the Statements of Earnings, as required.

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The $505 million net liability on energy contracts at March 31, 2009 was primarily attributable to losses on power swaps and natural gas futures and swaps designated as hedges of future energy purchases or production under Statement of Financial Accounting Standards (SFAS) No. 133. Prices of electricity and natural gas declined during the first quarter of 2009, which resulted in unrealized losses on the energy contracts of the Competitive Energy businesses. These businesses recorded unrealized losses of $246 million on energy contracts in Accumulated Other Comprehensive Loss as these energy contracts were effective hedges under SFAS No. 133. When these energy contracts settle, the related realized gains or losses are expected to be largely offset by the realized loss or gain on future energy purchases or production that will be used to settle the sales obligations of the Competitive Energy businesses to their customers.

PHI uses its best estimates to determine the fair value of the commodity and derivative contracts that its Competitive Energy businesses hold and sell. The fair values in each category presented below reflect forward prices and volatility factors as of March 31, 2009 and are subject to change as a result of changes in these factors:

	Maturities of Contracts at Fair Value
Source of Fair Value	2009			2010			2011			2012 and Beyond			Total Fair Value
	(millions of dollars)
Energy Commodity Activities, net (a)
Actively Quoted (i.e., exchange-traded) prices	$	(113	)	$	(87	)	$	(14	)	$	(1	)	$	(215	)
Prices provided by other external sources (b)		(153	)		(115	)		(20	)		(10	)		(298	)
Modeled (c)		4			5			(6	)		5			8
Total	$	(262	)	$	(197	)	$	(40	)	$	(6	)	$	(505	)

Notes:

(a) Includes all SFAS No. 133 hedge activity and trading activities recorded at fair value through AOCL or on the Statements of Earnings, 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 is readily observable in the market.

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

Contractual Arrangements with Credit Rating Triggers or Margining Rights

Under certain contractual arrangements entered into by PHI’s subsidiaries in connection with Competitive Energy business and other transactions, the subsidiary may be required to

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provide cash collateral or letters of credit as security for its contractual obligations if the credit ratings of 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, 2009, a one-level downgrade in the unsecured debt credit ratings of PHI and each of its rated subsidiaries which would decrease PHI’s rating to below “investment grade,” would increase the collateral obligation of PHI and its subsidiaries by up to $545 million, $399 million of which is attributable to derivatives 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 Item 1 of this Form 10-Q. The remaining $146 million of the collateral obligation that would be incurred in the event PHI was downgraded 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, 2009, Pepco Holdings’ subsidiaries engaged in Competitive Energy activities and Default Electricity Supply activities provided net cash collateral in the amount of $623 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 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, 2008. There have been no material changes to PHI’s critical accounting policies as disclosed in the Form 10-K, except that the following critical accounting policy supersedes the critical accounting policy with the same heading in the Form 10-K:

Goodwill Impairment Evaluation

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

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Substantially all of PHI’s goodwill was generated by Pepco’s acquisition of Conectiv in 2002 and is allocated to the Power Delivery reporting unit for purposes of assessing impairment under SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS No. 142). Management has identified Power Delivery as a single reporting unit based on the aggregation of components. The first step of the goodwill impairment test under SFAS No. 142 compares the fair value of the reporting unit with its carrying amount, including goodwill. Management uses its best judgment to make reasonable projections of future cash flows for Power Delivery when estimating the reporting unit’s fair value. In addition, PHI selects a discount rate for the associated risk with those estimated cash flows. These judgments are inherently uncertain, and actual results could vary from those used in PHI’s estimates. The impact of such variations could significantly alter the results of a goodwill impairment test, which could materially impact the estimated fair value of Power Delivery and potentially the amount of any impairment recorded in the financial statements.

PHI tests its goodwill for impairment annually as of July 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 identified reporting units; an adverse change in business conditions; a protracted decline in stock price causing market capitalization to fall below book value; an adverse regulatory action; or impairment of long-lived assets in the reporting unit.

PHI’s July 1, 2008 annual impairment test indicated that its goodwill was not impaired. PHI performed an interim test of goodwill for impairment as of March 31, 2009, which updated an interim test performed as of December 31, 2008, as its market capitalization was below its book value for all of first quarter 2009, and had declined significantly from the December 31, 2008 market capitalization. PHI concluded that its goodwill was not impaired at March 31, 2009. Details about the interim test as of March 31, 2009 and the results are included in Note (6), “Goodwill,” to the consolidated financial statements of Pepco Holdings, Inc. set forth in Item 1 of this Form 10-Q.

In order to estimate the fair value of the Power Delivery reporting unit, PHI reviews the results from two discounted cash flow models. The models differ in the method used to calculate the terminal value of the reporting unit. One model estimates terminal value based on a constant annual cash flow growth rate that is consistent with Power Delivery’s long-term view of the business, and the other model estimates terminal value based on a multiple of earnings before interest, taxes, depreciation, and amortization (EBITDA) that management believes is consistent with EBITDA multiples for comparable utilities. The models use a cost of capital appropriate for a regulated utility as the discount rate for the estimated cash flows associated with the reporting unit. PHI has consistently used this valuation model to estimate the fair value of Power Delivery since the adoption of SFAS No. 142.

The estimation of fair value is dependent on a number of factors that are sourced from the Power Delivery reporting unit’s business forecast, including but not limited to interest rates, growth assumptions, returns on rate base, operating and capital expenditure requirements, and other factors, changes in which could materially impact the results of impairment testing. Assumptions and methodologies used in the models were consistent with historical experience. A hypothetical 10 percent decrease in fair value of the Power Delivery reporting unit at March 31, 2009 would result in the Power Delivery reporting unit failing the first step of the impairment

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test as defined in SFAS No. 142, as the estimated fair value of the reporting unit would be below its carrying value by approximately $150 million. If this were to occur, PHI would be required to perform the second step of the impairment test prescribed by SFAS No. 142. This step would involve allocating the fair value of the Power Delivery reporting unit, as determined in the first step, to all of the assets and liabilities of the Power Delivery reporting unit. The fair value in excess of the allocated amount is attributable to goodwill. An impairment charge must be recorded to the extent that the goodwill, as so determined, exceeds the carrying value. This impairment charge may be more or less than the amount by which the carrying value of the Power Delivery reporting unit exceeded its fair value as determined by the first step of the impairment test. At December 31, 2008, a hypothetical 10 percent decrease in the estimate of the fair value would not have resulted in the Power Delivery reporting unit failing the first step of the impairment test. The decrease in the estimated fair value of the Power Delivery reporting unit from December 31, 2008 to March 31, 2009 was primarily due to updates in the assumptions used to calculate cash flow from operations and market assumptions used to calculate fair value. Further deterioration of the market-related factors or significant changes in other impairment test variables could result in an impairment charge, which could be material. Sensitive, interrelated and uncertain variables that could decrease the estimated fair value of the Power Delivery reporting unit include utility sector market performance, sustained adverse business conditions, change in forecasted revenues, higher operating and capital expenditure requirements, a significant increase in the cost of capital, and other factors.

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 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 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:

• Prevailing 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 plant facilities, recovery of purchased power expenses, and present or prospective wholesale and retail competition;

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

• Weather conditions;

• Population growth rates and demographic patterns;

• Competition for retail and wholesale customers;

• General economic conditions, including potential negative impacts resulting from an economic downturn;

• Growth in demand, sales and capacity to fulfill demand;

• Changes in tax rates or policies or in rates of inflation;

• Changes in accounting standards or practices;

• Changes in project costs;

• Unanticipated changes in operating expenses and capital expenditures;

• The ability to obtain funding in the capital markets on favorable terms;

• Rules and regulations imposed by Federal and/or state regulatory commissions, PJM and other regional transmission organizations (New York Independent System Operator, ISONE), the North American Electric Reliability Corporation and other applicable electric reliability organizations;

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

• Pace of entry into new markets;

• Volatility in market demand and prices for energy, capacity and fuel;

• Interest rate fluctuations and credit and capital market conditions; 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 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

General Overview

Potomac Electric Power Company (Pepco) is engaged in the transmission and distribution of electricity in Washington, D.C. 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 supplier. Default Electricity Supply is known as Standard Offer Service in both the District of Columbia and Maryland. Pepco’s service territory covers approximately 640 square miles and has a population of approximately 2.1 million. As of March 31, 2009, approximately 58% of delivered electricity sales were to Maryland customers and approximately 42% were to Washington, D.C. customers.

In connection with its approval of new electric service distribution base rates for Pepco in Maryland, effective in June 2007 (the 2007 Maryland Rate Order), the Maryland Public Service Commission (MPSC) approved a bill stabilization adjustment mechanism (BSA) for retail customers. For customers to which 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 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 which 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 has no impact on reported 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 under PUHCA 2005.

Results Of Operations

The following results of operations discussion compares the three months ended March 31, 2009, to the three months ended March 31, 2008. Other than this disclosure, information under this item has been omitted in accordance with General Instruction H to the Form 10-Q. All amounts in the tables (except sales and customers) are in millions of dollars.

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Operating Revenue

	2009		2008		Change
Regulated T&D Electric Revenue	$	212	$	218	$	(6	)
Default Supply Revenue		356		299		57
Other Electric Revenue		9		8		1
Total Operating Revenue	$	577	$	525	$	52

The table above shows the amount of Operating Revenue earned that is subject to price regulation (Regulated Transmission and Distribution (T&D) Electric Revenue and Default Supply Revenue) and that which is not subject to price regulation (Other Electric Revenue).

Regulated T&D Electric Revenue includes revenue from the delivery of electricity, including the delivery 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).

Default Supply Revenue is the revenue received for Default Electricity Supply. The costs related to Default Electricity Supply are included in Purchased Energy.

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

Regulated T&D Electric

Regulated T&D Electric Revenue	2009		2008		Change
Residential	$	60	$	57	$	3
Commercial and industrial		126		119		7
Other		26		42		(16	)
Total Regulated T&D Electric Revenue	$	212	$	218	$	(6	)

Other Regulated T&D Electric Revenue consists primarily of (i) transmission service revenue and (ii) revenue from the resale of energy and capacity under power purchase agreements between Pepco and unaffiliated third parties in the PJM Regional Transmission Organization (PJM RTO) market.

Regulated T&D Electric Sales (Gigawatt hours (GWh))	2009	2008	Change
Residential	2,193	2,067	126
Commercial and industrial	4,453	4,411	42
Other	45	45	—
Total Regulated T&D Electric Sales	6,691	6,523	168

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Regulated T&D Electric Customers (in thousands)	2009	2008	Change
Residential	695	687	8
Commercial and industrial	73	73	—
Other	—	—	—
Total Regulated T&D Electric Customers	768	760	8

Regulated T&D Electric Revenue decreased by $6 million primarily due to:

• A decrease of $15 million in Other Regulated T&D Electric Revenue (offset in Purchased Energy) due to the absence of revenues from the resale of energy and capacity purchased under the power purchase agreement between Panda-Brandywine, L.P. and Pepco (the Panda PPA) as the result of the transfer of the Panda PPA to an unaffiliated third party in September 2008.

The decrease was partially offset by:

• An increase of $4 million due to a distribution rate change in the District of Columbia that became effective in February 2008.

• An increase of $4 million due to higher pass-through revenue primarily resulting from a tax rate increase in Montgomery County, Maryland (primarily offset in Other Taxes).

Default Electricity Supply

Default Supply Revenue	2009		2008		Change
Residential	$	239	$	200	$	39
Commercial and industrial		115		97		18
Other		2		2		—
Total Default Supply Revenue	$	356	$	299	$	57
Default Electricity Supply Sales (GWh)	2009		2008		Change
Residential		2,083		1,965		118
Commercial and industrial		1,073		916		157
Other		3		3		—
Total Default Electricity Supply Sales		3,159		2,884		275

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Default Electricity Supply Customers (in thousands)	2009	2008	Change
Residential	662	658	4
Commercial and industrial	53	52	1
Other	—	—	—
Total Default Electricity Supply Customers	715	710	5

Default Supply Revenue, which is substantially offset in Purchased Energy, increased by $57 million primarily due to:

• An increase of $28 million as the result of higher Default Electricity Supply rates.

• An increase of $16 million due to higher sales as a result of colder weather.

• An increase of $15 million primarily due to commercial customer migration from competitive suppliers to Default Electricity Supply.

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.

	2009		2008
Sales to District of Columbia customers	36	%	32	%
Sales to Maryland customers	55	%	53	%

Operating Expenses

Purchased Energy

Purchased Energy, which is primarily associated with Default Electricity Supply sales, increased by $41 million to $349 million in 2009 from $308 million in 2008. The increase was primarily due to the following:

• An increase of $27 million due to a higher rate of recovery of electric supply costs resulting in a change in the Default Electric Supply deferral balance.

• An increase of $16 million due to higher sales as the result of colder weather.

• An increase of $12 million primarily due to commercial customer migration from competitive suppliers to Default Electricity Supply.

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The aggregate amount of these increases was partially offset by:

• A decrease of $15 million due to the termination of energy and capacity purchased under the Panda PPA.

Purchased Energy expense is substantially offset in Regulated T&D Electric Revenue and Default Supply Revenue.

Other Operation and Maintenance

Other Operation and Maintenance increased by $9 million to $79 million in 2009 from $70 million in 2008. Excluding an increase of $2 million primarily related to bad debt and administrative expenses that are deferred and recoverable, Other Operation and Maintenance expense increased by $7 million. The $7 million increase was primarily due to the following:

• An increase of $3 million due to higher pension expenses.

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

• An increase of $2 million in regulatory expenses due to an adjustment in 2008 for recoverable District of Columbia distribution rate case costs.

• An increase of $1 million primarily due to corrective maintenance and emergency restoration costs.

Effect of Settlement of Mirant Bankruptcy Claims

In September 2008, Pepco transferred the Panda PPA to an unaffiliated third party. In March 2009, the District of Columbia Public Service Commission approved an allocation between Pepco and its District of Columbia customers of the District of Columbia portion of the Mirant bankruptcy settlement proceeds remaining after the transfer of the Panda PPA. As a result, Pepco recorded a pre-tax gain of $14 million reflecting the District of Columbia proceeds retained by Pepco. A proposed settlement allocating the Maryland portion of the remaining Mirant Corporation bankruptcy settlement proceeds between Pepco and its Maryland customers is pending before the Maryland Public Service Commission.

Other Income (Expenses)

Other Expenses (which are net of Other Income) increased by $4 million to a net expense of $22 million in 2009 from a net expense of $18 million in 2008. The increase was primarily due to a $5 million net increase in interest expense on long-term debt as the result of a higher amount of outstanding debt.

Income Tax Expense

Pepco’s effective tax rates for the three months ended March 31, 2009 and 2008 were 42.4% and 40.2%, respectively. The increase in the rate resulted from decreases in asset removal costs and the amortization of Investment Tax Credits and an increase in the change in estimates

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and interest related to uncertain and effectively settled tax positions, offset by decreases in the flow-through of certain book tax depreciation and software amortization differences. The increase in the change in estimates and interest related to uncertain and effectively settled tax positions is primarily due to the non-recurring impact of a tax claim filed with the Internal Revenue Service in March 2008. The claim was for the treatment of casualty losses as current deductions (as opposed to being depreciated over their tax lives) on prior year tax returns currently under audit.

Capital Requirements

Liquidity

The continued disruptions in the capital and credit markets, combined with the volatility of energy prices, have had an impact on the borrowing capacity and liquidity of Pepco. Since the third quarter of 2008, to address the challenges posed by the current capital and credit market environment and to ensure that Pepco will continue to have sufficient access to cash to meet its liquidity needs, Pepco has taken several measures to reduce expenditures, issued $250 million in long-term debt securities and resold $110 million of Pollution Control Revenue Refunding Bonds (as discussed above).

Capital Expenditures

Pepco’s capital expenditures for the three months ended March 31, 2009, totaled $67 million. These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission.

During the first quarter of 2009, Pepco updated its projection of capital expenditures for 2009. Total capital expenditures for 2009 are expected to be approximately $323 million, with $209 million of distribution projects, $9 million of distribution projects specifically related to the Blueprint for the Future, $45 million of transmission projects, $46 million of transmission projects specifically related to the Mid-Atlantic Power Pathway and $14 million of other capital projects.

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

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factors that may cause Pepco’s actual results, levels of activity, performance or achievements to be materially different from any future results, levels of activity, performance or achievements expressed or implied by such forward-looking statements.

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

• Prevailing 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 plant facilities, recovery of purchased power expenses, and present or prospective wholesale and retail competition;

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

• Weather conditions;

• Population growth rates and demographic patterns;

• Competition for retail and wholesale customers;

• General economic conditions, including potential negative impacts resulting from an economic downturn;

• Growth in demand, sales and capacity to fulfill demand;

• Changes in tax rates or policies or in rates of inflation;

• Changes in accounting standards or practices;

• Changes in project costs;

• Unanticipated changes in operating expenses and capital expenditures;

• The ability to obtain funding in the capital markets on favorable terms;

• 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 influence Pepco’s business and profitability;

• Volatility in market demand and prices for energy, capacity and fuel;

• Interest rate fluctuations and credit and capital market conditions; 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 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

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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.

143

DPL

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

Delmarva Power & Light Company

General Overview

Delmarva Power & Light Company (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 territories who do not elect to purchase electricity from a competitive supplier. Default Electricity Supply is known as Standard Offer Service in both Delaware and Maryland. DPL’s electricity distribution service territory covers approximately 5,000 square miles and has a population of approximately 1.3 million. As of March 31, 2009, approximately 65% of delivered electricity sales were to Delaware customers and approximately 35% were to Maryland customers. In northern Delaware, DPL also supplies and distributes natural gas to retail customers and provides transportation-only services to retail customers 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.

Effective January 2, 2008, DPL sold its retail electric distribution assets and its wholesale electric transmission assets in Virginia.

In connection with its approval of new electric service distribution base rates for DPL in Maryland, effective in June, 2007 (the 2007 Maryland Rate Order), the Maryland Public Service Commission (MPSC) approved a bill stabilization adjustment mechanism (BSA) for retail customers. For customers to which the BSA applies, DPL 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 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 which 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 has no impact on reported 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 under PUHCA 2005.

Results Of Operations

The following results of operations discussion compares the three months ended March 31, 2009, to the three months ended March 31, 2008. Other than this disclosure, information under this item has been omitted in accordance with General Instruction H to the Form 10-Q. All amounts in the tables (except sales and customers) are in millions of dollars.

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Electric Operating Revenue

	2009		2008		Change
Regulated T&D Electric Revenue	$	91	$	87	$	4
Default Supply Revenue		225		203		22
Other Electric Revenue		5		5		—
Total Electric Operating Revenue	$	321	$	295	$	26

The table above shows the amount of Electric Operating Revenue earned that is subject to price regulation (Regulated Transmission and Distribution (T&D) Electric Revenue and Default Supply Revenue) and that which is not subject to price regulation (Other Electric Revenue).

Regulated T&D Electric Revenue includes revenue from the delivery of electricity, including the delivery 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).

Default Supply Revenue is the revenue received for Default Electricity Supply. The costs related to Default Electricity Supply are included in Purchased Energy.

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

Regulated T&D Electric

Regulated T&D Electric Revenue	2009		2008		Change
Residential	$	45	$	44	$	1
Commercial and industrial		25		25		—
Other		21		18		3
Total Regulated T&D Electric Revenue	$	91	$	87	$	4

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

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Regulated T&D Electric Sales (Gigawatt hours (GWh))	2009	2008	Change
Residential	1,496	1,397	99
Commercial and industrial	1,807	1,857	(50	)
Other	12	12	—
Total Regulated T&D Electric Sales	3,315	3,266	49
Regulated T&D Electric Customers (in thousands)	2009	2008	Change
Residential	439	437	2
Commercial and industrial	59	59	—
Other	1	1	—
Total Regulated T&D Electric Customers	499	497	2

Regulated T&D Electric Revenue increased by $4 million primarily due to:

• An increase of $3 million primarily due to a transmission rate change in June 2008.

• An increase of $1 million due to higher sales in Delaware as the result of colder weather. Due to the adoption of a BSA, weather in the Maryland service territory no longer affects distribution revenue.

Default Electricity Supply

Default Supply Revenue	2009		2008		Change
Residential	$	162	$	142	$	20
Commercial and industrial		60		58		2
Other		3		3		—
Total Default Supply Revenue	$	225	$	203	$	22
Default Electricity Supply Sales (GWh)	2009		2008		Change
Residential		1,470		1,359		111
Commercial and industrial		578		608		(30	)
Other		11		10		1
Total Default Electricity Supply Sales		2,059		1,977		82

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Default Electricity Supply Customers (in thousands)	2009	2008	Change
Residential	431	428	3
Commercial and industrial	48	48	—
Other	1	1	—
Total Default Electricity Supply Customers	480	477	3

Default Supply Revenue, which is substantially offset in Purchased Energy, increased by $22 million primarily due to:

• An increase of $14 million as the result of higher Default Electricity Supply rates.

• An increase of $11 million due to higher sales as the result of colder weather.

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

	2009		2008
Sales to Delaware customers	58	%	56	%
Sales to Maryland customers	71	%	70	%

Natural Gas Operating Revenue

	2009		2008		Change
Regulated Gas Revenue	$	119	$	92	$	27
Other Gas Revenue		12		24		(12	)
Total Natural Gas Operating Revenue	$	131	$	116	$	15

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. 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.

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Regulated Gas Revenue

Regulated Gas Revenue	2009		2008		Change
Residential	$	75	$	57	$	18
Commercial and industrial		42		33		9
Transportation and Other		2		2		—
Total Regulated Gas Revenue	$	119	$	92	$	27
Regulated Gas Sales (billion cubic feet)	2009		2008		Change
Residential		4		4		—
Commercial and industrial		3		2		1
Transportation and Other		2		3		(1	)
Total Regulated Gas Sales		9		9		—
Regulated Gas Customers (in thousands)	2009		2008		Change
Residential		114		113		1
Commercial and industrial		9		9		—
Transportation and Other		—		—		—
Total Regulated Gas Customers		123		122		1

Regulated Gas Revenue increased by $27 million primarily due to:

• An increase of $14 million primarily due to a Gas Cost Rate change effective November 2008 (offset in Gas Purchased expense).

• An increase of $9 million due to higher sales as the result of colder weather.

• An increase of $8 million due to the recording of the unbilled portion of Gas Cost Rate revenue as discussed below (offset in Gas Purchased expense).

The aggregate amount of these increases was partially offset by:

• A decrease of $4 million due to a net decrease in customer usage.

During the first quarter of 2009, DPL recorded additional revenue of $8 million related to the unbilled portion of its Gas Cost Rate (GCR) revenue, which was not previously recognized. Because the GCR revenue is deferred, an additional deferred gas expense was also recorded in the first quarter of 2009 (see Gas Purchased expense). Consequently, there is no impact on net earnings as a result of this adjustment.

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Other Gas Revenue

Other Gas Revenue, which is substantially offset in Gas Purchased expense, decreased by $12 million primarily due to lower revenue from off-system sales, the result of a decrease in market prices. Off-system sales are made possible when low demand for natural gas by regulated customers creates excess pipeline capacity.

Operating Expenses

Purchased Energy

Purchased Energy, which is primarily associated with Default Electricity Supply sales, increased by $24 million to $219 million in 2009 from $195 million in 2008. The increase was primarily due to:

• An increase of $12 million due to a higher rate of recovery of electric supply costs resulting in a change in the Default Electric Supply deferral balance.

• An increase of $11 million due to higher sales as the result of colder weather.

Purchased Energy expense is substantially offset in Default Supply Revenue.

Gas Purchased

Total Gas Purchased, which is primarily offset in Regulated Gas Revenue and Other Gas Revenue, increased by $13 million to $101 million in 2009 from $88 million in 2008. The increase is primarily due to:

• An increase of $18 million from the settlement of financial hedges (entered into as part of DPL’s regulated natural gas hedge program).

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

The aggregate amount of these increases was partially offset by:

• A decrease of $11 million in the cost of gas purchases for off-system sales, the result of lower average gas prices.

• A decrease of $5 million in the cost of gas purchases for system sales, the result of lower average gas prices and volumes purchased.

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Other Operation and Maintenance

Other Operation and Maintenance increased by $3 million to $59 million in 2009 from $56 million in 2008. Excluding an increase of $2 million primarily related to bad debt expense and administrative expenses that are deferred and recoverable, Other Operation and Maintenance expense increased by $1 million. The $1 million increase was primarily due to:

• An increase of $4 million due to higher pension expenses.

The increase was partially offset by:

• A decrease of $1 million in preventative maintenance costs.

Gain on Sale of Assets

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

Income Tax Expense

DPL’s effective tax rates for the three months ended March 31, 2009 and 2008 were 36.4% and 33.2%, respectively. The increase in the rate resulted from the change in estimates and interest related to uncertain and effectively settled tax positions. The increase in the change in estimates and interest related to uncertain and effectively settled tax positions is primarily due to the non-recurring impact of a tax claim filed with the Internal Revenue Service in March 2008. The claim was for the treatment of casualty losses as current deductions (as opposed to being depreciated over their tax lives) on prior year tax returns currently under audit.

Capital Requirements

Liquidity

The continued disruptions in the capital and credit markets, combined with the volatility of energy prices, have had an impact on the borrowing capacity and liquidity of DPL. Since the third quarter of 2008, to address the challenges posed by the current capital and credit market environment and to ensure that DPL will continue to have sufficient access to cash to meet its liquidity needs, DPL has taken several measures to reduce expenditures, issued $250 million in long-term debt securities and resold $9 million of Pollution Control Revenue Refunding Bonds (as discussed above).

Capital Expenditures

DPL’s capital expenditures for the three months ended March 31, 2009, totaled $37 million. These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission.

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During the first quarter of 2009, DPL updated its projection of capital expenditures for 2009. Total capital expenditures for 2009 are expected to be approximately $252 million, with $108 million of distribution projects, $34 million of distribution projects related to the Blueprint for the Future, $62 million of transmission projects, $10 million of transmission projects specifically related to the Mid-Atlantic Power Pathway, $21 million of gas delivery projects and $17 million of other capital projects.

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:

• Prevailing 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 plant facilities, recovery of purchased power expenses, and present or prospective wholesale and retail competition;

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

• Weather conditions;

• Population growth rates and demographic patterns;

• Competition for retail and wholesale customers;

• General economic conditions, including potential negative impacts resulting from an economic downturn;

• Growth in demand, sales and capacity to fulfill demand;

• Changes in tax rates or policies or in rates of inflation;

• Changes in accounting standards or practices;

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• Changes in project costs;

• Unanticipated changes in operating expenses and capital expenditures;

• The ability to obtain funding in the capital markets on favorable terms;

• 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 influence DPL’s business and profitability;

• Volatility in market demand and prices for energy, capacity and fuel;

• Interest rate fluctuations and credit and capital market conditions; 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 and DPL undertakes no obligation to update any forward-looking statements to reflect events or circumstances after the date on which such statements are made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for DPL to predict all 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.

152

ACE

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

Atlantic City Electric Company

General Overview

Atlantic City Electric Company (ACE) is engaged in the transmission and distribution of electricity in southern New Jersey. ACE 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 supplier. Default Electricity Supply is also 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 under PUHCA 2005.

Results Of Operations

The following results of operations discussion compares the three months ended March 31, 2009, to the three months ended March 31, 2008. Other than this disclosure, information under this item has been omitted in accordance with General Instruction H to the Form 10-Q. All amounts in the tables (except sales and customers) are in millions of dollars.

Operating Revenue

	2009		2008		Change
Regulated T&D Electric Revenue	$	84	$	74	$	10
Default Supply Revenue		255		283		(28	)
Other Electric Revenue		5		4		1
Total Operating Revenue	$	344	$	361	$	(17	)

The table above shows the amount of Operating Revenue earned that is subject to price regulation (Regulated Transmission and Distribution (T&D) Electric Revenue and Default Supply Revenue) and that which is not subject to price regulation (Other Electric Revenue).

Regulated T&D Electric Revenue includes revenue from the delivery of electricity, including the delivery 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).

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Default Supply Revenue is the revenue received for Default Electricity Supply. The costs related to Default Electricity Supply are included in Purchased Energy. Default Supply Revenue also includes revenue from transition bond charges and other restructuring related revenues.

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

Regulated T&D Electric

Regulated T&D Electric Revenue	2009		2008		Change
Residential	$	39	$	32	$	7
Commercial and industrial		29		25		4
Other		16		17		(1	)
Total Regulated T&D Electric Revenue	$	84	$	74	$	10

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

Regulated T&D Electric Sales (Gigawatt hours (GWh))	2009	2008	Change
Residential	1,085	1,021	64
Commercial and industrial	1,233	1,297	(64	)
Other	13	13	—
Total Regulated T&D Electric Sales	2,331	2,331	—

Regulated T&D Electric Customers (in thousands)	2009	2008	Change
Residential	481	480	1
Commercial and industrial	65	64	1
Other	1	1	—
Total Regulated T&D Electric Customers	547	545	2

Regulated T&D Electric Revenue increased by $10 million primarily due to:

• An increase of $9 million due to a distribution rate change as part of a higher New Jersey Societal Benefit Charge that became effective in June 2008 (substantially offset in Deferred Electric Service Costs).

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ACE

Default Electricity Supply

Default Supply Revenue	2009		2008		Change
Residential	$	116	$	109	$	7
Commercial and industrial		85		93		(8	)
Other		54		81		(27	)
Total Default Supply Revenue	$	255	$	283	$	(28	)

Other Default Supply Revenue consists primarily of revenue from the resale of energy and capacity under non-utility generating contracts (NUGs) between ACE and unaffiliated third parties in the PJM Regional Transmission Organization (PJM RTO) market.

Default Electricity Supply Sales (GWh)	2009	2008	Change
Residential	1,085	1,021	64
Commercial and industrial	821	816	5
Other	13	13	—
Total Default Electricity Supply Sales	1,919	1,850	69
Default Electricity Supply Customers (in thousands)	2009	2008	Change
Residential	481	480	1
Commercial and industrial	65	64	1
Other	1	1	—
Total Default Electricity Supply Customers	547	545	2

Default Supply Revenue, which is substantially offset in Purchased Energy and Deferred Electric Service Costs, decreased by $28 million primarily due to:

• A decrease of $27 million in wholesale energy revenues due to the sale at lower market prices of electricity purchased from NUGs.

• A decrease of $9 million as the result of lower Default Electricity Supply rates.

The aggregate amount of these decreases was partially offset by:

• An increase of $5 million primarily due to industrial and commercial customer migration from competitive suppliers to Default Electricity Supply.

• An increase of $5 million due to higher sales as the result of colder weather.

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ACE

For the three months ended March 31, 2009 and 2008, the percentage of ACE’s total distribution sales that are derived from customers receiving Default Electricity Supply are 82% and 79% respectively.

Operating Expenses

Purchased Energy

Purchased Energy, which is primarily associated with Default Electricity Supply sales, increased by $32 million to $277 million in 2009 from $245 million in 2008. The increase was primarily due to:

• An increase of $22 million in average energy prices, the result of new Default Electricity Supply contracts.

• An increase of $7 million due to higher sales as the result of colder weather.

Purchased Energy is substantially offset in Default Supply Revenue and Deferred Electric Service Costs.

Other Operation and Maintenance

Other Operation and Maintenance increased by $2 million to $48 million in 2009 from $46 million in 2008. Excluding an increase of $2 million primarily related to bad debt expenses that are deferred and recoverable, Other Operation and Maintenance expense did not change.

Deferred Electric Service Costs

Deferred Electric Service Costs decreased by $52 million to income of $27 million in 2009 from an expense of $25 million in 2008. The decrease was primarily due to:

• A decrease of $57 million due to a lower rate of recovery of costs associated with energy and capacity purchased under the NUGs.

• A decrease of $7 million due to a lower rate of recovery associated with deferred energy costs.

The aggregate amount of these decreases was partially offset by:

• An increase of $8 million due a higher rate of recovery associated with New Jersey Societal Benefit program costs.

• An increase of $3 million due to a higher rate of recovery associated with deferred transmission costs.

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ACE

Deferred Electric Service Costs are substantially offset in Regulated T&D Electric Revenue, Default Supply Revenue and Purchased Energy.

Other Income (Expense)

Other Expenses (which are net of Other Income) increased by $3 million to a net expense of $16 million in 2009 from a net expense of $13 million in 2008. The increase was primarily due to a $3 million net increase in interest expense on long-term debt as the result of a higher amount of outstanding debt.

Income Tax Expense

ACE’s income before income tax for the three months ended March 31, 2009 was less than $1 million; therefore, the consolidated effective income tax rate for the period is not meaningful. The income tax benefit in 2009 was primarily the result of the change in estimates and interest related to uncertain and effectively settled tax positions and the non-recurring adjustment to prior years’ taxes. The income tax benefit in the 2008 period was primarily the result of the change in estimates and interest related to uncertain and effectively settled tax positions due to the non-recurring impact of a tax claim filed with the Internal Revenue Service in March 2008 for the current deduction of casualty losses on prior year tax returns currently under audit.

During the first quarter of 2009, ACE recorded adjustments to correct certain income tax errors related to prior periods. The adjustments, which are not considered material, resulted in a decrease in Income Tax Expense of $1 million for the quarter ended March 31, 2009.

Capital Requirements

Liquidity

The continued disruptions in the capital and credit markets, combined with the volatility of energy prices, have had an impact on the borrowing capacity and liquidity of ACE. Since the third quarter of 2008, to address the challenges posed by the current capital and credit market environment and to ensure that ACE will continue to have sufficient access to cash to meet its liquidity needs, ACE has taken several measures to reduce expenditures and issued $250 million in long-term debt securities.

Capital Expenditures

ACE’s capital expenditures for the three months ended March 31, 2009, totaled $28 million. These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission.

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ACE

During the first quarter of 2009, ACE updated its projection of capital expenditures for 2009. Total capital expenditures for 2009 are expected to be approximately $152 million, with $97 million of distribution projects, $6 million of distribution projects specifically related to the Blueprint for the Future, $13 million of distribution projects specifically related to ACE’s recently approved Infrastructure Investment Plan, $28 million of transmission projects and $8 million of other capital projects.

On April 16, 2009, the New Jersey BPU approved ACE’s proposed Infrastructure Investment Plan and the revenue requirement associated with recovering the cost of these projects, subject to a prudency review in the next rate case. The approved projects will simultaneously enhance reliability of ACE’s distribution system and support economic activity and job growth in New Jersey in the near term. Cost recovery will be through an Infrastructure Investment Surcharge effective on June 1, 2009. This approved plan will add incremental capital spending of approximately $13 million for 2009 and $15 million for 2010. ACE is required to file a rate case no later than April 1, 2011. As part of this base rate case the remaining unamortized amounts associated with these projects will be placed into rate base.

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:

• Prevailing 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 plant facilities, recovery of purchased power expenses, and present or prospective wholesale and retail competition;

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

• Weather conditions;

• Population growth rates and demographic patterns;

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ACE

• Competition for retail and wholesale customers;

• General economic conditions, including potential negative impacts resulting from an economic downturn;

• Growth in demand, sales and capacity to fulfill demand;

• Changes in tax rates or policies or in rates of inflation;

• Changes in accounting standards or practices;

• Changes in project costs;

• Unanticipated changes in operating expenses and capital expenditures;

• The ability to obtain funding in the capital markets on favorable terms;

• 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 influence ACE’s business and profitability;

• Volatility in market demand and prices for energy, capacity and fuel;

• Interest rate fluctuations and credit and capital market conditions; 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 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 (17) “Use of Derivatives in Energy and Interest Rate Hedging Activities, and Item 7A, “Quantitative and Qualitative Disclosures About Market Risk” in the Consolidated Financial Statements of PHI included in its Annual Report on Form 10-K for the year ended December 31, 2008.

Pepco Holdings, Inc.

Commodity Price Risk

The Competitive Energy segments actively engage in commodity risk management activities to reduce their financial exposure to changes in the value of their assets and obligations due to commodity price fluctuations. Certain of these risk management activities are conducted using instruments classified as derivatives under Statement of Financial Accounting Standards (SFAS) No. 133. The Competitive Energy segments also manage commodity risk with contracts that are not classified as derivatives. The Competitive Energy segments’ primary risk management objectives are (1) to manage the spread between the cost of fuel used to operate their electric generation plants and the revenue received from the sale of the power produced by those plants by selling forward a portion of their projected plant output and buying forward a portion of their projected fuel supply requirements and (2) to manage the spread between wholesale and retail sales commitments and the cost of supply used to service those commitments in order to ensure stable and known cash flows and fix favorable prices and margins when they become available.

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 the Competitive Energy businesses’ 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 its Competitive Energy segments’ energy commodity activities. 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. On January 22, 2009, PHI changed its VaR estimation model from a delta-normal variance / covariance model to a delta-gamma model. The other parameters, a 95 percent, one-tailed confidence level and a one-day holding period, remained the same. Since VaR is an estimate, it is not necessarily indicative of actual results that may occur.

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Value at Risk Associated with Energy Contracts

For the Three Months Ended March 31, 2009

(millions of dollars)

	VaR for Competitive Energy Commodity Activity (a)
95% confidence level, one-day holding period, one-tailed Period end	$	4
Average for the period	$	5
High	$	8
Low	$	2
Notes: (a)     This column represents all energy derivative contracts, normal purchase and sales contracts, modeled generation output and fuel requirements and modeled customer load obligations for PHI’s energy commodity activities.

Conectiv Energy economically hedges both the estimated plant output and fuel requirements as the estimated levels of output and fuel needs change. Economic hedge percentages include the estimated electricity output of Conectiv Energy’s generation plants and any associated financial or physical commodity contracts (including derivative contracts that are classified as cash flow hedges under SFAS No. 133, other derivative instruments, wholesale normal purchase and sales contracts, and default electricity supply contracts).

Conectiv Energy maintains a forward 36 month program with targeted ranges for economically hedging its projected plant output combined with its energy purchase commitments. The disclosure shows the percentage of its entire expected plant output and energy purchase commitments for all hours that are hedged. Conectiv Energy is including default electricity supply contracts and associated hedges in ISONE. The hedge percentages for all expected plant output and purchase commitment (based on the then current forward electricity price curve) are as follows:

Month	Target Range
1-12	50-100%
13-24	25-75%
25-36	0-50%

The primary purpose of the risk management program is to improve the predictability and stability of margins by selling forward a portion of projected plant output, and buying forward a portion of projected fuel supply requirements. Within each period, hedged percentages can vary significantly above or below the average reported percentages.

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As of March 31, 2009, the electricity sold forward by Conectiv Energy as a percentage of projected plant output combined with energy purchase commitments was 89%, 82%, and 41% for the 1-12 month, 13-24 month and 25-36 month forward periods, respectively. The amount of forward sales during the 1-12 month period represents 24% of Conectiv Energy’s combined total generating capability and energy purchase commitments. The volumetric percentages for the forward periods can vary and may not represent the amount of expected value hedged.

Not all of the value associated with Conectiv Energy’s generation activities can be hedged such as the portion attributable to ancillary services and fuel switching due to the lack of market products, market liquidity, and other factors. Also, the hedging of locational value can be limited.

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 delivery 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. Its forward contracts are accounted for using standard accrual accounting since these contracts meet the requirements for normal purchase and sale accounting under SFAS No. 133.

Credit and Nonperformance Risk

This table provides information on the Competitive Energy businesses’ credit exposure, net of collateral, to wholesale counterparties.

Schedule of Credit Risk Exposure on Competitive Wholesale Energy Contracts

March 31, 2009

(millions of dollars)

Rating (a)	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	$	282	$	—	$	282	1	$	98
Non-Investment Grade		19		6		13	—		—
No External Ratings		46		12		34	—		—
Credit reserves					$	1

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

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

(c) Credit collateral - the face amount of cash deposits, letters of credit and performance bonds received from counterparties, not adjusted for probability of default, and, if applicable, property interests (including oil and 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, 2008.

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, 2009 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, 2009, 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.

On January 1, 2009, Conectiv Energy Holding Company, a subsidiary of Pepco Holdings, completed implementation of new software that enhances the accumulation and extraction of information needed for accounting and reporting the fair value of financial derivative instruments.

Item 4T. CONTROLS AND PROCEDURES

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, 2009, and, based upon this evaluation, the chief executive officer and the chief financial officer of Pepco have

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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, 2009, 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 disclosure controls and procedures as of March 31, 2009, 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, 2009, 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, 2009, 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.

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Changes in Internal Control Over Financial Reporting

During the three months ended March 31, 2009, 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.

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 (10), “Commitments and Contingencies—Legal Proceedings,” to the financial statements of ACE included herein.

Item 1A. RISK FACTORS

Pepco Holdings

For a discussion of Pepco Holdings’ risk factors, please refer to Item 1A “Risk Factors” in Pepco Holdings’ Annual Report on Form 10-K for the year ended December 31, 2008. There have been no material changes to Pepco Holdings’ risk factors as disclosed in the 10-K, except that:

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(1) The following risk factor supersedes the risk factor with the same heading in the Form 10-K:

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

PCI maintains a portfolio of eight cross-border energy lease investments, which as of March 31, 2009, had an equity value of approximately $1.3 billion and from which PHI currently derives approximately $56 million per year in tax benefits in the form of interest and depreciation deductions in excess of rental income. In 2005, the Treasury Department and IRS issued a notice 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 connection with the audit of PHI’s 2001 and 2002 income tax returns, the IRS disallowed the depreciation and interest deductions in excess of rental income claimed by PHI with respect to six of its cross-border energy lease investments. In addition, the IRS has sought to recharacterize the six leases as loan transactions as to which PHI would be subject to original issue discount income. On March 31, 2009, the IRS issued its Revenue Agents Report for the calendar years 2003 to 2005 which proposes to disallow the depreciation and interest deductions in excess of rental income claimed by PHI with respect to all eight of its cross-border energy lease investments and recharacterize the eight leases as loan transactions. PHI plans to file a timely protest with respect to these proposed adjustments.

PHI believes that its tax position with regard to its cross-border energy lease investments is appropriate based on applicable statutes, regulations and case law and is protesting the IRS adjustments and the unresolved audit issues have been forwarded to the Appeals Office of the IRS. In the event that PHI were not to prevail and were to suffer a total disallowance of the tax benefits and incur imputed original issue discount income due to the recharacterization of the leases as loans, as of March 31, 2009, PHI would have been obligated to pay approximately $520 million in additional federal and state taxes and $88 million of interest. In addition, the IRS could require PHI to pay a penalty of up to 20% on the amount of additional taxes due. PHI anticipates, however that any additional taxes that it would be required to pay as a result of the disallowance of prior deductions or a recharacterization of leases as loans would be recoverable in the form of lower taxes over the remaining term of the investments.

For further discussion of this matter, see Item 1 “Financial Statements — Note (15), “Commitments and Contingencies — Regulatory and Other Matters — PHI’s Cross-Border Energy Lease Investments” of this Form 10-Q.

(2) The following risk factor supersedes, as it relates to PHI, the risk factor in the Form 10-K with the heading having as its introductory sentence, “PHI and its subsidiaries are dependent on their ability to successfully access capital markets”:

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

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

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and bank financing as sources of liquidity that are not met by cash flow from their operations. Adverse business developments or market disruptions could increase the cost of financing or prevent the companies from accessing one or more financial markets.

The financing costs of each of PHI, Pepco, DPL and ACE are closely linked, directly or indirectly, to its credit rating. The collateral requirements of the Competitive Energy businesses also depend in part on the unsecured debt rating of PHI. Negative ratings actions by one or more of the credit rating agencies resulting from a change in PHI’s operating results or prospects would increase funding costs and collateral requirements and could make financing more difficult to obtain.

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

Events that could cause or contribute to a disruption of the financial markets include, but are not limited to:

• a recession or an economic slowdown;

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

• a significant change in energy prices;

• a terrorist attack or threatened attacks; or

• a significant electricity transmission disruption.

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

(3) The following risk factor is an additional risk factor:

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

PHI has a goodwill balance of approximately $1.4 billion primarily attributable to Pepco’s acquisition of Conectiv in 2002. Under generally accepted accounting principles, if the carrying value of goodwill, as shown on the consolidated balance sheet, exceeds its fair value, an

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impairment loss must be recognized in an amount equal to the excess. PHI is required to test goodwill for impairment at least annually and whenever events or changes in circumstances indicate that the carrying value may not be recoverable. Factors that may result in an interim impairment test include a protracted decline in stock price causing market capitalization to fall below book value. If PHI determines that its’ goodwill is impaired, PHI would be required to reduce its goodwill balance by the amount of the impairment and record a corresponding non-cash charge to earnings. Depending on the amount of the impairment, an impairment determination could have a material adverse effect on PHI’s financial condition and results of operations, but would not have an impact on cash flow.

Pepco

For a discussion of Pepco’s risk factors, please refer to Item 1A “Risk Factors” in Pepco’s Annual Report on Form 10-K for the year ended December 31, 2008. There have been no material changes to Pepco’s risk factors as disclosed in the 10-K, except that the following risk factor supersedes, as it relates to Pepco, the risk factor in the Form 10-K with the heading having as its introductory sentence, “PHI and its subsidiaries are dependent on their ability to successfully access capital markets”:

Pepco is dependent on access to capital markets and bank funding to satisfy its capital and liquidity requirements. The inability to obtain required financing would have an adverse effect on its business.

Pepco has significant capital requirements, including the funding of construction expenditures and the refinancing of maturing debt. The company relies primarily on cash flow from operations and access to the capital markets to meet these financing needs. The operating activities of the company also require access to short-term money markets and bank financing as sources of liquidity that are not met by cash flow from its operations. Adverse business developments or market disruptions could increase the cost of financing or prevent the company from accessing one or more financial markets.

The financing costs of Pepco are closely linked, directly or indirectly, to its credit rating. Negative ratings actions by one or more of the credit rating agencies resulting from a change in Pepco’s operating results or prospects would increase funding costs and collateral requirements and could make financing more difficult to obtain.

Events that could cause or contribute to a disruption of the financial markets include, but are not limited to:

• a recession or an economic slowdown;

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

• a significant change in energy prices;

• a terrorist attack or threatened attacks; or

• a significant electricity transmission disruption.

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

DPL

For a discussion of DPL’s risk factors, please refer to Item 1A “Risk Factors” in DPL’s Annual Report on Form 10-K for the year ended December 31, 2008. There have been no material changes to DPL’s risk factors as disclosed in the 10-K, except that the following risk factor supersedes, as it relates to DPL, the risk factor in the Form 10-K with the heading as its introductory sentence, “PHI and its subsidiaries are dependent on their ability to successfully access capital markets”:

DPL is dependent on access to capital markets and bank funding to satisfy its capital and liquidity requirements. The inability to obtain required financing would have an adverse effect on its business.

DPL has significant capital requirements, including the funding of construction expenditures and the refinancing of maturing debt. The company relies primarily on cash flow from operations and access to the capital markets to meet these financing needs. The operating activities of the company also require access to short-term money markets and bank financing as sources of liquidity that are not met by cash flow from its operations. Adverse business developments or market disruptions could increase the cost of financing or prevent the company from accessing one or more financial markets.

The financing costs of DPL are closely linked, directly or indirectly, to its credit rating. Negative ratings actions by one or more of the credit rating agencies resulting from a change in DPL’s operating results or prospects would increase funding costs and collateral requirements and could make financing more difficult to obtain.

Events that could cause or contribute to a disruption of the financial markets include, but are not limited to:

• a recession or an economic slowdown;

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

• a significant change in energy prices;

• a terrorist attack or threatened attacks; or

• a significant electricity transmission disruption.

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

ACE

For a discussion of ACE’s risk factors, please refer to Item 1A “Risk Factors” in ACE’s Annual Report on Form 10-K for the year ended December 31, 2008. There have been no material changes to ACE’s risk factors as disclosed in the 10-K, except that the following risk factor supersedes, as it relates to ACE, the risk factor in the Form 10-K with the heading having an introductory sentence, “PHI and its subsidiaries are dependent on their ability to successfully access capital markets”:

ACE is dependent on access to capital markets and bank funding to satisfy its capital and liquidity requirements. The inability to obtain required financing would have an adverse effect on its business.

ACE has significant capital requirements, including the funding of construction expenditures and the refinancing of maturing debt. The company relies primarily on cash flow from operations and access to the capital markets to meet these financing needs. The operating activities of the company also require access to short-term money markets and bank financing as sources of liquidity that are not met by cash flow from its operations. Adverse business developments or market disruptions could increase the cost of financing or prevent the company from accessing one or more financial markets.

The financing costs of ACE are closely linked, directly or indirectly, to its credit rating. Negative ratings actions by one or more of the credit rating agencies resulting from a change in ACE’s operating results or prospects would increase funding costs and collateral requirements and could make financing more difficult to obtain.

Events that could cause or contribute to a disruption of the financial markets include, but are not limited to:

• a recession or an economic slowdown;

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

• a significant change in energy prices;

• a terrorist attack or threatened attacks; or

• a significant electricity transmission disruption.

In accordance with the requirements of the Sarbanes-Oxley Act of 2002 and the SEC rules thereunder, ACE’s management is responsible for establishing and maintaining internal control

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over financial reporting and is required to assess annually the effectiveness of these controls. The inability to certify the effectiveness of these controls due to the identification of one or more material weaknesses in these controls also could increase financing costs or could adversely affect the ability to access one or more financial markets.

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. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

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 5. OTHER INFORMATION

Pepco Holdings

None.

Pepco

None.

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DPL

None.

ACE

None.

Item 6. EXHIBITS

The documents listed below are being filed or furnished 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
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.

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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 7, 2009	By	/s/ P. H. BARRY
		Paul H. Barry
		Senior Vice President and Chief Financial Officer, PHI, Pepco and DPL Chief Financial Officer, ACE

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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