10-Q

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, 2010

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

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

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

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

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

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

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

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

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

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

Registrant	Number of Shares of Common Stock of              the Registrant Outstanding at March 31, 2010
Pepco Holdings	223,210,345 ($.01 par value)
Pepco	100 ($.01 par value) (a)
DPL	1,000 ($2.25 par value) (b)
ACE	8,546,017 ($3.00 par value) (b)

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

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

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

TABLE OF CONTENTS

		Page
	Glossary of Terms	i
PART I	FINANCIAL INFORMATION	1
Item 1.	- Financial Statements	1
Item 2.	- Management’s Discussion and Analysis of Financial Condition and Results of Operations	96
Item 3.	- Quantitative and Qualitative Disclosures About Market Risk	146
Item 4.	- Controls and Procedures	148
PART II	OTHER INFORMATION	150
Item 1.	- Legal Proceedings	150
Item 1A	- Risk Factors	150
Item 2.	- Unregistered Sales of Equity Securities and Use of Proceeds	151
Item 3.	- Defaults Upon Senior Securities	151
Item 4.	- Reserved	151
Item 5.	- Other Information	151
Item 6.	- Exhibits	152
Signatures		153

GLOSSARY OF TERMS

Term	Definition
ACE	Atlantic City Electric Company
ACE Funding	Atlantic City Electric Transition Funding LLC
ADITC	Accumulated deferred investment tax credits
ALJ	Administrative Law Judge
Ancillary services	Generally, electricity generation reserves and reliability services
AOCL	Accumulated other comprehensive loss
April 2007 Order	Administrative Order and Notice of Civil Administrative Penalty Assessment concerning Deepwater issued in April 2007 by NJDEP
ASC	Accounting Standards Codification
BGS	Basic Generation Service (the supply of electricity by ACE to retail customers in New Jersey who have not elected to purchase electricity from a competitive supplier)
Bondable Transition Property	The principal and interest payments on the Transition Bonds and related taxes, expenses and fees
Bridge Loan Facility	A Credit Agreement dated April 20, 2010, entered into by PHI for an aggregate principal amount of loans of up to $450 million with the Lenders, and Morgan Stanley Senior Funding, Inc., as administrative agent
BSA	Bill Stabilization Adjustment
Calpine	A subsidiary of Calpine Corporation, the purchaser of the Generation Business
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
DEDA	Delaware Economic Development Authority
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
Deepwater	Deepwater generating facility
Delta Project	Conectiv Energy’s 565-megawatt combined cycle generating facility that is under construction
DOE	U.S. Department of Energy
DPL	Delmarva Power & Light Company
DPSC	Delaware Public Service Commission
EDIT	Excess Deferred Income Taxes
EPA	U.S. Environmental Protection Agency
EPS	Earnings per share
EQR	Conectiv Energy’s Electric Quarterly Report filed with FERC
Exchange Act	Securities Exchange Act of 1934, as amended
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission

i

Term	Definition
FHACA	Flood Hazard Area Control Act
GAAP	Accounting principles generally accepted in the United States of America
GCR	Gas Cost Rate
Generation Business	Conectiv Energy’s wholesale power generation business
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
Lenders	Morgan Stanley Bank, N.A. and Credit Suisse AG, Cayman Islands Branch, the lenders for the Bridge Loan Facility
May 2007 Order	The second Administrative Order and Notice of Civil Administrative Penalty Assessment concerning Deepwater issued in May 2007 by NJDEP
MDC	MDC Industries, Inc.
MFVRD	Modified fixed variable rate design
Mirant	Mirant Corporation
MMBtu	One Million British Thermal Units
MSCG	Morgan Stanley Capital Group, Inc.
MPSC	Maryland Public Service Commission
New Jersey Societal Benefit Programs	Various NJBPU - mandated social programs for which ACE receives revenues to recover costs
NJBPU	New Jersey Board of Public Utilities
NJDEP	New Jersey Department of Environmental Protection
Normalization provisions	Sections of the Internal Revenue Code and related regulations that dictate how excess deferred income taxes resulting from the corporate income tax rate reduction enacted by the Tax Reform Act of 1986 and accumulated deferred investment tax credits should be treated for ratemaking purposes
NUGs	Non-utility generators
NYDEC	New York Department of Environmental Conservation
NYMEX	New York Mercantile Exchange
OAL	New Jersey Office of Administrative Law
Panda PPA	PPA between Pepco and Panda-Brandywine, L.P.
PCI	Potomac Capital Investment Corporation and its subsidiaries
Pepco	Potomac Electric Power Company
Pepco Energy Services	Pepco Energy Services, Inc. and its subsidiaries
Pepco Holdings or PHI	Pepco Holdings, Inc.
PHI Retirement Plan	PHI’s noncontributory retirement plan
PJM	PJM Interconnection, LLC

ii

Term	Definition
Power Delivery	PHI’s Power Delivery Business
PPA	Power Purchase Agreement
Prior Bonds	Certain series of tax-exempt bonds previously issued by DEDA for the benefit of DPL
PRP	Potentially responsible party
Purchase Agreement	The agreement dated April 20, 2010, between PHI and Calpine for the purchase of the Generation Business
PUHCA 2005	Public Utility Holding Company Act of 2005, which became effective February 8, 2006
QSPE	Qualifying special purpose entity
RAR	IRS revenue agent’s report
RARC	Regulatory Asset Recovery Charge
RBOB	Reformulated Gasoline Blendstock for Oxygen Blending
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
RECs	Renewable energy credits
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
Revenue Decoupling Adjustment	An adjustment equal to the amount by which revenue from distribution sales differs from the revenue that Pepco and DPL are entitled to earn based on the approved distribution charge per customer
ROE	Return on equity
RPM	Reliability Pricing Model
SEC	Securities and Exchange Commission
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)
Spark spread	The difference between the cost of the fuel required to produce a unit of electricity and the price of that same unit of electricity
Spot	Commodities market in which goods are sold for cash and delivered immediately
Transition Bond Charge	Revenue ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds and related taxes, expenses and fees
Transition Bonds	Transition Bonds issued by ACE Funding
Treasury Rate Locks	A hedging transaction that allows a company to “lock in” a specific interest rate corresponding to the rate of a designated Treasury bond for a determined period of time
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 Income	2	47	63	82
Consolidated Statements of Comprehensive Income	3	N/A	N/A	N/A
Consolidated Balance Sheets	4	48	64	83
Consolidated Statements of Cash Flows	6	50	66	85
Notes to Consolidated Financial Statements	7	51	67	86

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

1

PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended March 31,
	2010			2009
	(millions of dollars, except per share data)
Operating Revenue
Power Delivery	$	1,262		$	1,372
Competitive Energy		1,087			1,139
Other		10			9
Total Operating Revenue		2,359			2,520
Operating Expenses
Fuel and purchased energy		1,654			1,887
Other services cost of sales		137			96
Other operation and maintenance		244			236
Depreciation and amortization		100			96
Other taxes		93			91
Deferred electric service costs		(19	)		(27	)
Effect of settlement of Mirant bankruptcy claims		—			(14	)
Total Operating Expenses		2,209			2,365
Operating Income		150			155
Other Income (Expenses)
Interest and dividend income		—			1
Interest expense		(88	)		(90	)
Loss from equity investments		(1	)		(1	)
Other income		6			4
Total Other Expenses		(83	)		(86	)
Income Before Income Tax Expense		67			69
Income Tax Expense		31			24
Net Income		36			45
Retained Earnings at Beginning of Period		1,268			1,271
Dividends Paid on Common Stock (Note 14)		(60	)		(59	)
Retained Earnings at End of Period	$	1,244		$	1,257
Basic and Diluted Share Information
Weighted average shares outstanding		222			219
Earnings per share of common stock	$	.16		$	.21

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

2

PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(Unaudited)

	Three Months Ended March 31,
	2010			2009
	(millions of dollars)
Net income	$	36		$	45
Other Comprehensive Loss
Losses on commodity derivatives designated as cash flow hedges:
Losses arising during period		(209	)		(256	)
Amount of losses reclassified into income		97			104
Net losses on commodity derivatives		(112	)		(152	)
Losses on Treasury Rate Locks reclassified into income		1			1
Other comprehensive loss, before income taxes		(111	)		(151	)
Income tax benefit		(45	)		(62	)
Other comprehensive loss, net of income taxes		(66	)		(89	)
Comprehensive loss	$	(30	)	$	(44	)

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

3

PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31, 2010			December 31, 2009
	(millions of dollars)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	38		$	46
Restricted cash equivalents		10			11
Accounts receivable, less allowance for uncollectible accounts of $47 million and $45 million, respectively		1,205			1,213
Inventories		226			252
Derivative assets		70			43
Prepayments of income taxes		163			167
Deferred income tax assets, net		110			126
Prepaid expenses and other		52			68
Total Current Assets		1,874			1,926
INVESTMENTS AND OTHER ASSETS
Goodwill		1,407			1,407
Regulatory assets		1,792			1,801
Investment in finance leases held in trust		1,382			1,386
Income taxes receivable		135			141
Restricted cash equivalents		3			4
Assets and accrued interest related to uncertain tax positions		12			12
Derivative assets		64			43
Other		198			196
Total Investments and Other Assets		4,993			4,990
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		13,883			13,717
Accumulated depreciation		(4,918	)		(4,854	)
Net Property, Plant and Equipment		8,965			8,863
TOTAL ASSETS	$	15,832		$	15,779

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

4

PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31, 2010			December 31, 2009
	(millions of dollars, except shares)
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Short-term debt	$	727		$	530
Current portion of long-term debt and project funding		521			536
Accounts payable and accrued liabilities		640			712
Capital lease obligations due within one year		7			7
Taxes accrued		64			48
Interest accrued		92			68
Derivative liabilities		110			104
Other		292			297
Total Current Liabilities		2,453			2,302
DEFERRED CREDITS
Regulatory liabilities		610			613
Deferred income taxes, net		2,550			2,600
Investment tax credits		34			35
Pension benefit obligation		296			290
Other postretirement benefit obligations		412			409
Income taxes payable		7			5
Liabilities and accrued interest related to uncertain tax positions		95			96
Derivative liabilities		85			62
Other		146			158
Total Deferred Credits		4,235			4,268
LONG-TERM LIABILITIES
Long-term debt		4,493			4,470
Transition bonds issued by ACE Funding		359			368
Long-term project funding		16			17
Capital lease obligations		92			92
Total Long-Term Liabilities		4,960			4,947
COMMITMENTS AND CONTINGENCIES (NOTE 14)
EQUITY
Common stock, $.01 par value – authorized 400,000,000 shares, 223,210,345 and 222,269,895 shares outstanding, respectively		2			2
Premium on stock and other capital contributions		3,239			3,227
Accumulated other comprehensive loss		(307	)		(241	)
Retained earnings		1,244			1,268
Total Shareholders’ Equity		4,178			4,256
Non-controlling interest		6			6
Total Equity		4,184			4,262
TOTAL LIABILITIES AND EQUITY	$	15,832		$	15,779

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

5

PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
	2010			2009
	(millions of dollars)
OPERATING ACTIVITIES
Net income	$	36		$	45
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		100			96
Non-cash rents from cross-border energy lease investments		(13	)		(14	)
Effect of settlement of Mirant bankruptcy claims		—			(14	)
Changes in restricted cash equivalents related to Mirant settlement		—			38
Deferred income taxes		42			39
Net unrealized losses on commodity derivatives		2			40
Other		(3	)		(1	)
Changes in:
Accounts receivable		21			147
Inventories		26			28
Prepaid expenses		17			(27	)
Regulatory assets and liabilities, net		(1	)		22
Accounts payable and accrued liabilities		(49	)		(144	)
Pension benefit obligation		18			20
Cash collateral related to derivative activities		(162	)		(258	)
Taxes accrued		(3	)		96
Interest accrued		24			25
Other assets and liabilities		12			(12	)
Net Cash From Operating Activities		67			126
INVESTING ACTIVITIES
Investment in property, plant and equipment		(208	)		(180	)
Changes in restricted cash equivalents		2			—
Net other investing activities		(1	)		—
Net Cash Used By Investing Activities		(207	)		(180	)
FINANCING ACTIVITIES
Dividends paid on common stock		(60	)		(59	)
Common stock issued for the Dividend Reinvestment Plan		8			7
Issuances of common stock		7			8
Issuances of long-term debt		23			110
Reacquisition of long-term debt		(24	)		(58	)
Issuances of short-term debt, net		197			240
Net other financing activities		(19	)		2
Net Cash From Financing Activities		132			250
Net (Decrease) Increase in Cash and Cash Equivalents		(8	)		196
Cash and Cash Equivalents at Beginning of Period		46			384
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	38		$	580
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid (received) for income taxes, net	$	2		$	(98	)

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

6

PEPCO HOLDINGS

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

PEPCO HOLDINGS, INC.

(1) ORGANIZATION

Pepco Holdings, Inc. (PHI or Pepco Holdings), a Delaware corporation incorporated in 2001, is a 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.

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

7

PEPCO HOLDINGS

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.

Conectiv Energy

As further discussed in Note (15), “Subsequent Event,” on April 20, 2010, the Board of Directors of PHI approved a plan for the disposition of Conectiv Energy. The plan consists of the sale of Conectiv Energy’s wholesale power generation business (the Generation Business) and the liquidation of all of Conectiv Energy’s load service supply contracts, energy hedging portfolio, certain tolling agreements and other non-core assets. In accordance with the plan, PHI on the same day entered into an agreement (the Purchase Agreement) to sell the Generation Business to a subsidiary of Calpine Corporation (Calpine). Under the terms of the Purchase Agreement, Calpine will purchase a subsidiary of PHI, which after a reorganization will hold the assets and liabilities of the Generation Business, for a purchase price of $1.65 billion, plus the market value of the fuel oil inventory at closing, and subject to various adjustments, including adjustments for (i) the level of working capital and non-fuel oil inventory at closing and (ii) actual capital expenditures relative to budgeted capital expenditures through the closing date. The targeted closing date for the sale is June 30, 2010.

All of Conectiv Energy’s generating facilities, which have an aggregate generating capacity of 3,860 megawatts, are included in the sale. Calpine is also acquiring Conectiv Energy’s Delta Project, a 565 megawatt combined cycle generating facility that is under construction (the Delta Project), along with a 6-year tolling agreement associated with the Delta Project. The sale does not include the balance of PHI’s Conectiv Energy segment, which includes Conectiv Energy’s load service supply contracts, energy hedging portfolio, certain tolling agreements, and other non-core assets. Under the plan adopted by the board of directors, these contracts and other assets will be liquidated over a period not exceeding 12 months from the date of adoption of the plan.

PHI currently estimates that the sale of the Generation Assets on the terms set forth in the Purchase Agreement and the liquidation of the remaining Conectiv Energy assets will result in a loss through the completion of the liquidation for financial reporting purposes ranging from $60 million to $90 million, after tax. The loss to be recognized in the second quarter of 2010 could exceed this range due to unrealized losses required to be recorded in earnings related to derivative instruments no longer qualifying for cash flow hedge accounting. PHI currently estimates that these unrealized losses will be offset by gains from the liquidation of load service supply contracts over the liquidation period.

The estimated after-tax proceeds from the sale of the Generation Assets and the liquidation of the remaining Conectiv Energy assets and contracts, combined with the return of collateral posted under the contracts, are expected to total approximately $1.75 billion. Taxes on the sale and liquidation of the assets are currently estimated to be approximately $300 million.

Beginning with its financial statements for the quarter ended June 30, 2010, the entire Conectiv Energy segment will be reported in discontinued operations.

Pepco Energy Services

On December 7, 2009, PHI announced that it will wind down the retail electric and natural gas supply business, which it conducts through its subsidiary Pepco Energy Services. The retail energy supply business historically has generated a substantial portion of the operating revenues and net income of PHI’s Pepco Energy Services operating segment. Operating revenues related to the retail energy supply business

8

PEPCO HOLDINGS

for the three months ended March 31, 2010 and 2009 were $497 million and $630 million, respectively, while operating income for the same periods was $21 million and $22 million, respectively. In connection with the operation of the retail energy supply business, as of March 31, 2010, Pepco Energy Services provided letters of credit of $181 million and posted net cash collateral of $192 million. These collateral requirements, which are based on existing wholesale energy purchase and sale contracts and current market prices, will decrease as the contracts expire and are expected to be fully released over time by June 1, 2014. The remaining Energy Services business will not be affected by the wind down of the retail energy supply business.

Other Business Operations

Through its subsidiary Potomac Capital Investment Corporation (PCI), PHI maintains a portfolio of cross-border energy lease investments, with a book value at March 31, 2010 of approximately $1.4 billion. This activity constitutes a fourth operating segment for financial reporting purposes, which is designated as “Other Non-Regulated.”

(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, 2009. 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, 2010, 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, 2010 may not be indicative of PHI’s results that will be realized for the full year ending December 31, 2010, since its Power Delivery and Competitive Energy businesses are seasonal.

Use of Estimates

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

Significant matters that involve the use of estimates include the assessment of goodwill and long-lived assets for impairment, fair value calculations for certain derivative instruments, the costs of providing pension and other postretirement benefits, evaluation of the probability of recovery of regulatory assets, estimation of storm restoration accruals, and the recognition of income tax benefits as it relates to investments in finance leases held in trust associated with PHI’s portfolio of cross-border energy lease investments. Additionally, PHI is subject to legal, regulatory, and other proceedings and claims that arise in the ordinary course of its business. PHI records an estimated liability for these proceedings and claims, when the loss is determined to be probable and is reasonably estimable.

During the first quarter of 2010, Pepco, DPL and ACE incurred significant costs associated with the February 2010 severe winter storms that affected their respective service territories. The total costs of the restoration efforts have been estimated at $37 million with $19 million charged to Other Operation and Maintenance expense for repair work and $18 million recorded as capital expenditures. A large portion of

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the costs of the restoration work relate to services provided by outside contractors and other utilities, and billings for such services in most instances have not yet been received and have been estimated. Actual billings may vary significantly from the estimates of such billings.

Consolidation of Variable Interest Entities

In accordance with the provisions of the Financial Accounting Standards Board (FASB) guidance on the consolidation of variable interest entities (Accounting Standards Codification (ASC) 810), Pepco Holdings consolidates those variable interest entities with respect to which Pepco Holdings or a subsidiary is the primary beneficiary. The guidance addresses conditions under which an entity should be consolidated based upon variable interests rather than voting interests. The subsidiaries of Pepco Holdings have contractual arrangements with a number of entities to which the guidance applies.

ACE Purchase Power Agreements (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 PPAs, Pepco Holdings potentially assumes the variability in the operations of the generating facilities related to the NUGs and, therefore, has a variable interest in the entities. Despite exhaustive efforts to obtain information from these entities during the three months ended March 31, 2010, PHI was unable to obtain sufficient information to conduct the analysis required under FASB guidance to determine whether these three entities were variable interest entities or if ACE was the primary beneficiary. As a result, Pepco Holdings has applied the scope exemption from the guidance for enterprises that have conducted exhaustive efforts to obtain the necessary information, but have not been able to obtain such information.

Net purchase activities with the NUGs for the three months ended March 31, 2010 and 2009, were approximately $72 million and $83 million, respectively, of which approximately $67 million and $72 million, respectively, consisted of power purchases under the PPAs. Pepco Holdings does not have loss exposure under the NUGs because the costs are recoverable from ACE’s customers through regulated rates.

DPL Wind Transactions

PHI, through its DPL subsidiary, has entered into four wind PPAs in amounts up to a total of 350 megawatts. Three of the PPAs are with land-based facilities and one of the PPAs is with an offshore facility. As the facilities are completed and become operational, DPL is obligated to purchase energy and renewable energy credits (RECs) from the four wind facilities and capacity from one of the wind facilities. The RECs help DPL fulfill 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 the four agreements, each of which sets forth the prices to be paid by DPL over the life of the contract, and has approved the recovery of DPL’s purchase costs through customer rates.

One of the land-based wind facilities became operational and went into service in December 2009. DPL is obligated to purchase energy and RECs from this facility over 15 years in amounts generated and delivered not to exceed 50.25 megawatts at rates that are fixed. Payments under the other agreements are currently expected to start in the fourth quarter of 2010 for the other two land-based contracts and 2014 for the offshore contract, if the projects are ultimately completed and operational.

The terms of the agreements with wind facilities that are not yet operational range between 20 and 25 years. When they become operational, DPL is obligated to purchase energy and RECs in amounts generated and delivered by the sellers at rates that are primarily fixed under these agreements. Under one of the agreements, DPL is also obligated to purchase the capacity associated with the facility at rates that are generally fixed. The inability of the offshore wind facility developer to obtain all necessary permits and financing commitments could result in setbacks in the construction schedules and the operational start dates of the offshore wind facility. If the wind facilities are not operational by specified dates, DPL has the right to terminate the PPAs.

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DPL concluded that consolidation is not required for any of these PPAs under FASB guidance on the consolidation of variable interest entities (ASC 810).

ACE Transition Funding, LLC

ACE Transition Funding, LLC (ACE Funding) was established in 2001 by ACE solely for the purpose of securitizing authorized portions of ACE’s recoverable stranded costs through the issuance and sale of Transition Bonds. The proceeds of the sale of each series of Transition Bonds have been transferred to ACE in exchange for the transfer by ACE to ACE Funding of the right to collect a non-bypassable transition bond charge from ACE customers pursuant to bondable stranded costs rate orders issued by the New Jersey Board of Public Utilities (NJBPU) in an amount sufficient to fund the principal and interest payments on the Transition Bonds and related taxes, expenses and fees (Bondable Transition Property). ACE collects the transition bond charges from its customers on behalf of ACE Funding and the holders of the Transition Bonds. The assets of ACE Funding, including the Bondable Transition Property, and the Transition Bond charges collected from ACE’s customers, are not available to creditors of ACE. The holders of the Transition Bonds have recourse only to the assets of ACE Funding. ACE owns 100 percent of the equity of ACE Funding and PHI has consolidated ACE Funding in its financial statements. The amendment to the variable interest entity consolidation guidance effective January 1, 2010 resulted in ACE Funding meeting the definition of a variable interest entity. PHI continues to consolidate ACE Funding in its financial statements as ACE is the primary beneficiary of ACE Funding under the amended variable interest entity consolidation guidance.

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 November 1, and whenever an event occurs or circumstances change in the interim that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Factors that may result in an interim impairment test include, but are not limited to: a change in the identified reporting units; an adverse change in business conditions; a decline in PHI’s stock price causing market capitalization to fall further below book value; an adverse regulatory action; or an impairment of long-lived assets in the reporting unit. PHI concluded that an interim impairment test was not required during the three month period ending March 31, 2010 as described in Note (6), “Goodwill.”

Long-Lived Asset Impairment Evaluation

PHI’s policy for impairment of long-lived assets requires the evaluation of long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying value of the assets may not be recoverable.

Based on the available evidence at March 31, 2010, it was more likely than not that the disposal of the assets of the Conectiv Energy segment would occur prior to the end of their estimated lives. Accordingly, as of March 31, 2010, PHI completed an impairment test of the long-lived assets of the Conectiv Energy segment using the probability-weighted approach. This test concluded that the long-lived assets were not impaired as of March 31, 2010.

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Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in Pepco Holdings’ gross revenues were $82 million and $78 million for the three months ended March 31, 2010 and 2009, respectively.

Reclassifications and Adjustments

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

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 was also recorded in the first quarter of 2009. Consequently, there was no impact on consolidated net income as a result of this adjustment.

Income Tax Adjustments

During the first quarter of 2010, ACE recorded an adjustment to correct certain income tax errors related to prior periods. The adjustment resulted in an increase in income tax expense of $6 million for the quarter ended March 31, 2010. The adjustment represents the reversal of erroneously recorded interest income for state income tax purposes related to uncertain and effectively settled tax positions, including $2 million, $3 million and $1 million recorded in 2009, 2008 and 2007, respectively. During the first quarter of 2009, ACE recorded a decrease in income tax expense of $1 million to correct certain income tax errors related to prior periods.

(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Transfers and Servicing (ASC 860)

The FASB issued new guidance that removes the concept of a qualifying special-purpose entity (QSPE) from the current guidance on transfers and servicing and the QSPE scope exception in current guidance on consolidation. The new guidance also changed the requirements for derecognizing financial assets and requires additional disclosures about a transferor’s continuing involvement in transferred financial assets.

The guidance was effective for transfers of financial assets occurring in fiscal periods beginning on January 1, 2010 for PHI. As of January 1, 2010, PHI has adopted the provisions of this guidance and determined that the guidance did not have a material impact on PHI’s overall financial condition, results of operations, or cash flows, nor does it expect it to in the future.

Consolidation of Variable Interest Entities (ASC 810)

The FASB issued new consolidation guidance regarding variable interest entities effective January 1, 2010 that eliminated the existing quantitative analysis requirement and added new qualitative factors to determine whether consolidation is required. The new qualitative factors are applied on a quarterly basis to interests in variable interest entities. Under the new guidance, the holder of the interest with the power to direct the most significant activities of the entity and the right to receive benefits or absorb losses significant to the entity would consolidate. The new guidance retained the existing provision that allows entities created before December 31, 2003 to be scoped out from a consolidation assessment if exhaustive efforts are taken and there is insufficient information to determine the primary beneficiary.

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PHI has adopted the provisions of the new FASB guidance on consolidation of variable interest entities, and it did not have a material impact on PHI’s overall financial condition, results of operations, or cash flows.

Fair Value Measurement and Disclosures (ASC 820)

The FASB issued new disclosure requirements for recurring and non-recurring fair value measurements. The guidance, effective for PHI’s March 31, 2010 financial statements, required the disaggregation of balance sheet items measured at fair value into classes (that is, subsets of balance sheet items) based on the nature and risks of the items. The standard requires description of pricing inputs and valuation methodologies for instruments with Level 2 or 3 valuation inputs. In addition, the standard requires information about any transfers of instruments between Level 1 and 2 valuation categories. These additional disclosures can be found in Note (13), “Fair Value Disclosures.”

Subsequent Events (ASC 855)

The FASB issued new guidance which eliminates the requirement for PHI to disclose the date through which it has evaluated subsequent events beginning with its March 31, 2010 financial statements. PHI has modified its disclosure in Note (2), “Significant Accounting Policies.”

(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Fair Value Measurement and Disclosures (ASC 820)

The new FASB disclosure requirements that will be effective beginning with PHI’s March 31, 2011 financial statements require that the items within the reconciliation of the Level 3 valuation category be presented in separate categories for purchases, sales, issuances, and settlements, if significant. PHI is evaluating the impact of this part of the guidance on PHI’s overall financial statements.

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(5) SEGMENT INFORMATION

Pepco Holdings’ management has identified its operating segments at December 31, 2009 as Power Delivery, Conectiv Energy, Pepco Energy Services, and Other Non-Regulated. Corporate and Other includes unallocated Pepco Holdings’ (parent company) capital costs, such as acquisition financing costs, and the depreciation and amortization expense related to purchase accounting adjustments for the fair value of Conectiv assets and liabilities as of the August 1, 2002 acquisition date. Segment financial information for the three months ended March 31, 2010 and 2009, is as follows:

	Three Months Ended March 31, 2010
	(millions of dollars)
				Competitive Energy Segments
	Power Delivery			Conectiv Energy			Pepco Energy Services		Other Non- Regulated			Corporate and Other  (a)			PHI Consolidated
Operating Revenue	$	1,262		$	603	(b)	$	547	$	13		$	(66	)	$	2,359
Operating Expense (c)		1,169	(b)		583			522		1			(66	)		2,209
Operating Income		93			20			25		12			—			150
Interest Income		—			—			—		1			(1	)		—
Interest Expense		51			5			5		4			23			88
Other Income (Expense)		4			—			1		(1	)		1			5
Preferred Stock Dividends		—			—			—		1			(1	)		—
Income Tax Expense (Benefit)		26	(d)		7			8		3			(13	)(e)		31
Net Income (Loss)		20			8			13		4			(9	)		36
Total Assets		10,223			2,111			757		1,533			1,208			15,832
Construction Expenditures	$	151		$	50		$	1	$	—		$	6		$	208

(a) Includes unallocated Pepco Holdings’ (parent company) capital costs, such as acquisition financing costs, and the depreciation and amortization expense related to purchase accounting adjustments for the fair value of 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. Corporate and Other includes intercompany amounts of $(65) million for Operating Revenue, $(63) million for Operating Expense, $(14) million for Interest Income, $(13) million for Interest Expense, and $(1) million of Preferred Stock Dividends.

(b) Power Delivery purchased electric energy and capacity and natural gas from Conectiv Energy in the amount of $58 million for the three months ended March 31, 2010.

(c) Includes depreciation and amortization expense of $100 million, consisting of $82 million for Power Delivery, $11 million for Conectiv Energy, $4 million for Pepco Energy Services, and $3 million for Corporate and Other.

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

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

	Three Months Ended March 31, 2009
	(millions of dollars)
				Competitive Energy Segments
	Power Delivery			Conectiv Energy			Pepco Energy Services		Other Non- Regulated			Corporate and Other (a)			PHI Consolidated
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 Tax Expense (Benefit)		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

(a) Includes unallocated Pepco Holdings’ (parent company) capital costs, such as acquisition financing costs, and the depreciation and amortization expense related to purchase accounting adjustments for the fair value of 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. Corporate and Other includes 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.

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(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 expense 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 Corporate and Other.

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

(6) GOODWILL

PHI’s goodwill balance of $1.4 billion was unchanged during the three month period ended March 31, 2010. Substantially all of PHI’s $1.4 billion goodwill balance was generated by Pepco’s acquisition of Conectiv in 2002 and is allocated to the Power Delivery reporting unit based on the aggregation of its components for purposes of assessing impairment under FASB guidance on goodwill and other intangibles (ASC 350).

PHI’s annual impairment tests as of July 1, 2009 and November 1, 2009 indicated that goodwill was not impaired. As of March 31, 2010, after review of its significant assumptions in the goodwill impairment analysis, PHI concluded that there were no events requiring it to perform an interim goodwill impairment test. Although PHI’s market capitalization was below book value at March 31, 2010, PHI’s market capitalization has improved compared to earlier periods. PHI performed its previous annual goodwill impairment tests as of November 1, 2009 and July 1, 2009, and interim impairment tests as of March 31, 2009 and December 31, 2008 when its market capitalization was further below book value than at March 31, 2010, and concluded that its goodwill was not impaired at those earlier dates. PHI will continue to closely monitor for indicators of goodwill impairment, including the sustained period of time that PHI’s stock price has been below its book value.

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

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

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(7) LEASING ACTIVITIES

Investment in Finance Leases Held in Trust

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

The components of the cross-border energy lease investments at March 31, 2010 and at December 31, 2009 are summarized below:

	March 31, 2010			December 31, 2009
	(millions of dollars)
Scheduled lease payments to PHI, net of non-recourse debt	$	2,265		$	2,281
Less: Unearned and deferred income		(883	)		(895	)
Investment in finance leases held in trust		1,382			1,386
Less: Deferred income tax liabilities		(747	)		(748	)
Net investment in finance leases held in trust	$	635		$	638

Income recognized from cross-border energy lease investments was comprised of the following for the three months ended March 31, 2010 and 2009:

	Three Months Ended March  31,
	2010		2009
	(millions of dollars)
Pre-tax income from PHI’s cross-border energy lease investments (included in “Other Revenue”)	$	13	$	14
Income tax expense		4		4
Net income from PHI’s cross-border energy lease investments	$	9	$	10

(8) PENSION AND OTHER POSTRETIREMENT BENEFITS

The following Pepco Holdings information is for the three months ended March 31, 2010 and 2009:

	Pension Benefits						Other Postretirement Benefits
	2010			2009			2010			2009
	(millions of dollars)
Service cost	$	11		$	9		$	2		$	2
Interest cost		30			28			10			10
Expected return on plan assets		(33	)		(28	)		(4	)		(4	)
Prior service credit component		—			—			(1	)		(1	)
Gain component		11			12			3			3
Net periodic benefit cost	$	19		$	21		$	10		$	10

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Pension

The pension net periodic benefit cost for the three months ended March 31, 2010, of $19 million includes $4 million for Pepco, $2 million for ACE and $2 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, 2009, of $21 million includes $5 million for Pepco, $2 million for ACE and $3 million for DPL before intercompany allocations.

Pension Contributions

PHI’s funding policy with regard to PHI’s noncontributory retirement plan (the PHI Retirement Plan) is to maintain a funding level that is at least equal to the funding target level under the Pension Protection Act of 2006. During 2009, discretionary tax-deductible contributions totaling $300 million were made to the PHI Retirement Plan which brought plan assets to at least the funding target level for 2009 under the Pension Protection Act. Of this amount, $240 million consisted of tax-deductible contributions made by Pepco, ACE and DPL in the amounts of $170 million, $60 million and $10 million, respectively. The remaining $60 million consisted of tax-deductible contributions made by the PHI Service Company. Although PHI projects there will be no minimum funding requirement under the Pension Protection Act guidelines in 2010, PHI currently estimates it may make discretionary tax-deductible contributions in 2010 of approximately $100 million to bring its plan assets to at least the funding target level for 2010 under the Pension Protection Act.

Other Postretirement Benefits

The other postretirement net periodic benefit cost for the three months ended March 31, 2010, 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, 2009, of $10 million includes $3 million for Pepco, $2 million for ACE and $2 million for DPL before intercompany allocations.

(9) DEBT

Credit Facilities

PHI’s principal credit source is an unsecured $1.5 billion syndicated credit facility, which can be used by PHI and its utility subsidiaries to borrow funds, obtain letters of credit and support the issuance of commercial paper. This facility is in effect until May 2012 and consists of commitments from 16 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 unsecured credit facility in the amount of $400 million with a syndicate of nine lenders, which was amended and restated in October 2009 to extend the facility termination date to October 15, 2010. Under the facility, PHI has access to revolving and swingline loans over the term of the facility. The facility does not provide for the issuance of letters of credit. These two facilities are referred to collectively as PHI’s “primary credit facilities.”

At March 31, 2010 and December 31, 2009, the amount of cash plus borrowing capacity under PHI’s primary credit facilities available to meet the future liquidity needs of PHI and its utility subsidiaries on a consolidated basis totaled $1.2 billion and $1.4 billion, respectively. PHI’s utility subsidiaries had a combined cash and borrowing capacity under the $1.5 billion credit facility of $546 million and $582 million, respectively.

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In May 2009, PHI entered into a $50 million, 18-month bilateral credit agreement, which only can be used for the purpose of obtaining letters of credit. As of March 31, 2010, $25 million in letters of credit were outstanding under the agreement.

Other Financing Activities

In January 2010, ACE Funding made principal payments of $5.9 million on Series 2002-1 Bonds, Class A-2, and $2.3 million on Series 2003-1 Bonds, Class A-2.

In March 2010, Pepco redeemed at maturity, $16 million of Prince George’s County 5.75% Pollution Control Revenue Refunding Bonds Series 1995.

In March 2010, ACE resold $23.2 million in aggregate principal amount of Pollution Control Revenue Refunding Bonds Series 2004A due June 1, 2029 issued by The Pollution Control Financing Authority of Salem County. The bonds were repurchased by ACE in April 2008 in response to the 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, ACE received the proceeds of the sale, which it intends to use for general corporate purposes. The bonds bear interest at the fixed rate of 4.875% per annum, payable each March 1 and September 1, commencing September 1, 2010.

Financing Activity Subsequent to March 31, 2010

In April 2010, 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-2.

In April 2010, DPL completed a tax-exempt bond financing in which The Delaware Economic Development Authority (DEDA) issued and sold $78.4 million of its Gas Facilities Refunding Revenue Bonds, Series 2010, due February 1, 2031. The proceeds from the issuance of the bonds were loaned by DEDA to DPL pursuant to a loan agreement, dated as of April 1, 2010, between DEDA and DPL. The payment obligations under the loan agreement correspond to the payments of principal, premium, if any, and interest when and as due on the bonds. The bonds bear interest at the fixed rate of 5.40% per annum, payable each February 1 and August 1, commencing August 1, 2010. Beginning on August 1, 2020, the bonds are subject to optional redemption at the direction of DPL, in whole or in part, at a redemption price equal to the principal amount thereof, plus accrued interest, if any, to the redemption date.

DPL used the proceeds of the bonds to effect the redemption of all outstanding amounts of the following series of tax-exempt bonds previously issued by DEDA for the benefit of DPL (such bonds collectively are referred to as the Prior Bonds):

• $11.15 million of Exempt Facilities Refunding Revenue Bonds (Delmarva Power & Light Company Project) Series 2000A;

• $27.75 million of Exempt Facilities Refunding Revenue Bonds (Delmarva Power & Light Company Project) Series 2000B;

• $20 million of Exempt Facilities Refunding Revenue Bonds (Delmarva Power & Light Company Project) Series 2001A;

• $4.5 million of Exempt Facilities Refunding Revenue Bonds (Delmarva Power & Light Company Project) Series 2001B; and

• $15 million of Exempt Facilities Refunding Revenue Bonds (Delmarva Power & Light Company Project) Series 2002A.

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The Prior Bonds were repurchased by DPL in 2008 in response to the 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 from the redemption of the Prior Bonds, which it intends to use for general corporate purposes.

On April 20, 2010, PHI entered into a Credit Agreement for an aggregate principal amount of loans of up to $450 million with Morgan Stanley Bank, N.A. and Credit Suisse AG, Cayman Islands Branch, and Morgan Stanley Senior Funding, Inc., as administrative agent (the Bridge Loan Facility). PHI is entitled to make up to two draws under the Bridge Loan Facility at any time on or before June 1, 2010. The Bridge Loan Facility matures on April 19, 2011. All indebtedness incurred under the Bridge Loan Facility is unsecured. For additional information see Note (15), “Subsequent Event.”

Collateral Requirements of the Competitive Energy Business

In conducting its retail energy supply business, Pepco Energy Services, during periods of declining energy prices, has been exposed to the asymmetrical risk of having to post collateral under its wholesale purchase contracts without receiving a corresponding amount of collateral from its retail customers. To partially address these asymmetrical collateral obligations, Pepco Energy Services, in the first quarter of 2009, entered into a credit intermediation arrangement with Morgan Stanley Capital Group, Inc. (MSCG). Under this arrangement, MSCG, in consideration for the payment to MSCG of certain fees: (i) 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 obligation to post collateral based on changes in electricity prices. As of March 31, 2010, approximately 12% 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 into expense in declining amounts over the life of the arrangement based on the fair value of the underlying contracts at the time of novation. For the three months ended March 31, 2010 and 2009, approximately $2 million and $1 million, respectively, of the fees have been amortized and reflected in interest expense.

In addition to Pepco Energy Services’ retail energy supply 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, 2010, Pepco Energy Services and Conectiv Energy had posted net cash collateral of $192 million and $325 million, respectively, and letters of credit of $181 million and $19 million, respectively. At December 31, 2009, Pepco Energy Services and Conectiv Energy had posted net cash collateral of $123 million and $240 million, respectively, and letters of credit of $157 million and $22 million, respectively.

At March 31, 2010 and December 31, 2009, the aggregate amount of cash, plus borrowing capacity under PHI credit facilities available to meet the future liquidity needs of the Competitive Energy business totaled $631 million and $820 million, respectively.

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(10) INCOME TAXES

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

	Three Months Ended March  31,
	2010		2009
Federal statutory rate	35.0	%	35.0	%
Increases (decreases) resulting from:
State income taxes, net of federal effect	6.9		5.8
Change in estimates and interest related to uncertain and effectively settled tax positions	13.3		(3.5	)
Depreciation	1.8		2.2
Tax credits	(1.5	)	(1.6	)
Cross-border energy lease investments	(1.8	)	(1.9	)
Release of valuation allowance	(11.5	)	—
Medicare Part D subsidy	6.3		—
Other, net	(2.2	)	(1.2	)
Consolidated Effective Income Tax Rate	46.3	%	34.8	%

PHI’s effective tax rates for the three months ended March 31, 2010 and 2009 were 46.3% and 34.8%, respectively. A portion of the increase in the rate resulted from changes in estimates and interest related to uncertain and effectively settled tax positions, primarily related to a $2 million reversal of accrued interest income on state income tax positions that PHI no longer believes is more likely than not to be realized and the reversal of $6 million of erroneously accrued interest income on uncertain and effectively settled state income tax positions, as discussed in Note 2, “Significant Accounting Policies.”

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

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

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In March 2009, the Internal Revenue Service (IRS) issued a Revenue Agent’s Report (RAR) for the audit of PHI’s consolidated federal income tax returns for the calendar years 2003 to 2005. The IRS has proposed adjustments to PHI’s tax returns, including adjustments to PHI’s deductions related to cross-border energy lease investments, the capitalization of overhead costs for tax purposes and the deductibility of certain casualty losses. PHI has appealed certain of the proposed adjustments and believes it has adequately reserved for the adjustments proposed in the RAR. See Note (14), “Commitments and Contingencies – PHI’s Cross-Border Energy Lease Investments” for additional discussion. 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).

(11) EARNINGS PER SHARE

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

	Three Months Ended March  31,
	2010		2009
	(millions of dollars, except per share data)
Income (Numerator):
Earnings Applicable to Common Stock	$	36	$	45
Shares (Denominator):
Weighted average shares outstanding for basic computation:
Average shares outstanding		222		219
Adjustment to shares outstanding		—		—
Weighted Average Shares Outstanding for Computation of Basic Earnings Per Share of Common Stock		222		219
Net effect of potentially dilutive shares (a)		—		—
Weighted Average Shares Outstanding for Computation of Diluted Earnings Per Share of Common Stock		222		219
Basic earnings per share of common stock	$	.16	$	.21
Diluted earnings per share of common stock	$	.16	$	.21

(a) The number of options to purchase shares of common stock that were excluded from the calculation of diluted EPS because they were anti- dilutive were 285,266 and 363,366 for the three months ended March 31, 2010 and 2009, respectively.

(12) DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

PHI’s Competitive Energy business uses derivative instruments primarily to reduce its financial exposure to changes in the value of its assets and obligations due to commodity price fluctuations. The derivative instruments used by the Competitive Energy business include forward contracts, futures, swaps, and exchange-traded and over-the-counter options. The Competitive Energy business also manages 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 generating facilities and the revenue received from the sale of the power produced by those facilities, and (ii) to manage the spread between retail sales commitments and the cost of supply used to service those commitments to ensure stable cash flows and lock in favorable prices and margins when they become available.

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

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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 generating facilities. Conectiv Energy accounts for most of its futures, swaps and certain forward contracts as cash flow hedges of forecasted transactions. Derivative contracts purchased or sold in excess of probable amounts of forecasted hedge transactions are marked-to-market through current earnings. All option contracts are marked-to-market through current earnings. Certain natural gas and oil futures and swaps are used as fair value hedges to protect the value of natural gas transportation contracts and physical fuel inventory. Some forward contracts are accounted for using standard accrual accounting since these contracts meet the requirements for normal purchase and normal sale accounting.

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 normal 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 normal sale accounting.

In the Power Delivery business, DPL uses derivative instruments in the form of forward contracts, futures, swaps, and exchange-traded and over-the-counter options primarily to reduce gas commodity price volatility and limit its customers’ exposure to increases in the market price of gas. DPL also manages commodity risk with physical natural gas and capacity contracts that are not classified as derivatives. All premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all gains and losses related to hedging activities, are deferred under FASB guidance on regulated operations (ASC 980) until recovered based on the fuel adjustment clause approved by the DPSC.

PHI and its subsidiaries also use derivative instruments from time to time to mitigate the effects of fluctuating interest rates on debt incurred in connection with the operation of their businesses. In June 2002, PHI entered into several treasury rate lock transactions in anticipation of the issuance of several series of fixed-rate debt commencing in July 2002. Upon issuance of the fixed rate debt, the rate locks were terminated at a loss. The loss has been deferred in accumulated other comprehensive loss and is being recognized in income over the life of the debt issued.

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The tables below identify the balance sheet location and fair values of derivative instruments as of March 31, 2010 and December 31, 2009:

	As of March 31, 2010
Balance Sheet Caption	Derivatives Designated as Hedging Instruments			Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting			Net Derivative Instruments
	(millions of dollars)
Derivative Assets (current assets)	$	208		$	1,156		$	1,364		$	(1,294	)	$	70
Derivative Assets (non-current assets)		79			129			208			(144	)		64
Total Derivative Assets		287			1,285			1,572			(1,438	)		134
Derivative Liabilities (current liabilities)		(588	)		(1,195	)		(1,783	)		1,673			(110	)
Derivative Liabilities (non-current liabilities)		(172	)		(114	)		(286	)		201			(85	)
Total Derivative Liabilities		(760	)		(1,309	)		(2,069	)		1,874			(195	)
Net Derivative (Liability) Asset	$	(473	)	$	(24	)	$	(497	)	$	436		$	(61	)

	As of December 31, 2009
Balance Sheet Caption	Derivatives Designated as Hedging Instruments			Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting			Net Derivative Instruments
	(millions of dollars)
Derivative Assets (current assets)	$	152		$	628		$	780		$	(737	)	$	43
Derivative Assets (non-current assets)		67			65			132			(89	)		43
Total Derivative Assets		219			693			912			(826	)		86
Derivative Liabilities (current liabilities)		(470	)		(645	)		(1,115	)		1,011			(104	)
Derivative Liabilities (non-current liabilities)		(102	)		(62	)		(164	)		102			(62	)
Total Derivative Liabilities		(572	)		(707	)		(1,279	)		1,113			(166	)
Net Derivative (Liability) Asset	$	(353	)	$	(14	)	$	(367	)	$	287		$	(80	)

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

	March 31, 2010			December 31, 2009
	(millions of dollars)
Cash collateral pledged to counterparties with the right to reclaim (a)	$	443		$	293
Cash collateral received from counterparties with the obligation to return		(7	)		(6	)

(a) Includes cash deposits on commodity brokerage accounts

As of March 31, 2010 and December 31, 2009, PHI had no cash collateral pledged or received related to derivative instruments 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 loss (AOCL) and is reclassified into income in the same period or periods during which the hedged transactions affect income. Gains and losses on the derivative representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current income. This information for the activity during the three months ended March 31, 2010 and 2009 is provided in the tables below:

	Three Months Ended March 31,
	2010			2009
	(millions of dollars)
Amount of net pre-tax (loss) gain arising during the period included in accumulated other comprehensive loss (a)	$	(209	)	$	(256	)
Amount of net pre-tax (loss) gain reclassified into income:
Effective portion:
Competitive Energy Revenue		2			4
Fuel and Purchased Energy		(93	)		(102	)
Total		(91	)		(98	)
Ineffective portion: (b)
Competitive Energy Revenue		(3	)		(1	)
Fuel and Purchased Energy		(3	)		(5	)
Total		(6	)		(6	)
Total net (loss) gain reclassified into income		(97	)		(104	)
Net pre-tax (loss) gain on commodity derivatives included in accumulated other comprehensive loss	$	(112	)	$	(152	)

(a) Included in the $(256) million loss for the three months ended March 31, 2009 is a $(4) million loss realized on a derivative transaction but not yet recognized in income.

(b) For the three months ended March 31, 2010 and 2009, amounts of $1 million and $2 million, respectively, were reclassified from AOCL to income because forecasted transactions were deemed no longer probable.

As of March 31, 2010 and December 31, 2009, PHI’s Competitive Energy business 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, 2010	December 31, 2009
Forecasted Purchases Hedges
Coal (Tons)	435,000	325,000
Natural gas (One Million British Thermal Units (MMBtu))	94,995,000	97,510,000
Electricity (Megawatt hours (MWh))	17,624,223	20,467,763
Heating oil (Barrels)	82,000	89,000
Forecasted Sales Hedges
Coal (Tons)	485,000	255,000
Natural gas (MMBtu)	—	3,859,643
Electricity (MWh)	11,295,152	13,024,007
Electric capacity (MW-Days)	173,940	203,640
Financial transmission rights (MWh)	325,159	48,014
Heating oil (Barrels)	70,000	—

Power Delivery

As described above, all premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all of DPL’s gains and losses related to hedging activities, are deferred under FASB guidance on regulated operations until recovered based on the fuel adjustment clause approved by the DPSC. The following table indicates the amounts deferred as regulatory assets or liabilities and the location in the consolidated statements of income of amounts reclassified to income through the fuel adjustment clause for the three months ended March 31, 2010 and 2009:

	Three Months Ended March  31,
	2010			2009
	(millions of dollars)
Net Loss Deferred as a Regulatory Asset or Liability	$	(5	)	$	—
Net Loss Reclassified from Regulatory Asset or Liability to Fuel and Purchased Energy Expense		(2	)		(16	)

As of March 31, 2010 and December 31, 2009, Power Delivery had the following outstanding commodity forward contracts that were entered into to hedge forecasted transactions:

	Quantities
Commodity	March 31, 2010	December 31, 2009
Forecasted Purchases Hedges:
Natural Gas (MMBtu)	4,957,500	5,695,000

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Cash Flow Hedges Included in Accumulated Other Comprehensive Loss

The tables below provide details regarding effective cash flow hedges included in PHI’s consolidated balance sheet as of March 31, 2010 and 2009. Cash flow hedges are marked-to-market on the balance sheet with corresponding adjustments to AOCL. The data in the tables indicate the cumulative net loss after-tax related to effective cash flow hedges by contract type included in AOCL, the portion of AOCL expected to be reclassified to income during the next 12 months, and the maximum hedge or deferral term:

As of March 31, 2010 Contracts	Accumulated Other Comprehensive Loss After-tax (a)		Portion Expected to be Reclassified to Income during the Next 12 Months		Maximum Term
	(millions of dollars)
Energy Commodity (b)	$	269	$	276	50 months
Interest Rate		21		3	269 months
Total	$	290	$	279

(a) Accumulated other comprehensive loss on PHI’s consolidated balance sheet as of March 31, 2010, includes a $17 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 largely 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 FASB guidance on derivatives and hedging, or they are not derivative contracts. Under accrual accounting, no asset is recorded on the balance sheet for these contracts, and revenue is not recognized until the period of delivery.

As of March 31, 2009 Contracts	Accumulated Other Comprehensive Loss After-tax (a)		Portion Expected to be Reclassified to Income during the Next 12 Months		Maximum Term
	(millions of dollars)
Energy Commodity (b)	$	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 largely 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 FASB guidance on derivatives and hedging, or they are not derivative contracts. Under accrual accounting, no asset is recorded on the balance sheet for these contracts, and revenue is not recognized until the period of delivery.

Fair Value Hedges

In connection with its energy commodity activities, the Competitive Energy business designates certain derivatives as fair value hedges. For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative as well as the offsetting gain or loss on the hedged item attributable to the hedged risk is recognized in current income. For the three months ended March 31, 2010 and 2009, the amount of the derivative net gain (loss) on energy commodity contracts recognized for hedges, by consolidated statements of income line item, is as follows:

Consolidated Statements of Income Line Item	Net Gain (Loss) on Derivatives Recognized in Income				Net Gain (Loss) on Hedged Items Recognized in Income
	Three Months Ended March 31,
	2010		2009		2010		2009
	(millions of dollars)
Competitive Energy Revenue	$	—	$	—	$	—	$	—
Fuel and Purchased Energy Expense		—		2		—		(2	)
Total	$	—	$	2	$	—	$	(2	)

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As of March 31, 2010 and December 31, 2009, PHI’s Competitive Energy business had the following outstanding commodity forward contract volumes and net position on derivatives that were accounted for as fair value hedges of fuel inventory and natural gas transportation:

Commodity	March 31, 2010		December 31, 2009
	Quantity	Net Position	Quantity	Net Position
Natural Gas (MMBtu)	—	—	1,180,000	Short

Other Derivative Activity

Competitive Energy Business

In connection with its energy commodity activities, the Competitive Energy business holds certain derivatives that do not qualify as hedges. Under FASB guidance on derivatives and hedging, these derivatives are recorded at fair value through income with corresponding adjustments on the balance sheet.

For the three months ended March 31, 2010 and 2009, the amount of the derivative gain (loss) for the Competitive Energy business recognized in income is provided in the table below:

	Three Months Ended March 31, 2010								Three Months Ended March 31, 2009
	Competitive Energy Revenue			Fuel and Purchased Energy Expense		Total			Competitive Energy Revenue			Fuel and Purchased Energy Expense			Total
	(millions of dollars)
Realized mark-to-market gains (losses)	$	1		$	2	$	3		$	63		$	(16	)	$	47
Unrealized mark-to-market (losses) gains		(2	)		—		(2	)		(40	)		—			(40	)
Total net mark-to-market (losses) gains	$	(1	)	$	2	$	1		$	23		$	(16	)	$	7

As of March 31, 2010 and December 31, 2009, PHI’s Competitive Energy business had the following net outstanding commodity forward contract volumes and net position on derivatives that did not qualify for hedge accounting:

	March 31, 2010		December 31, 2009
Commodity	Quantity	Net Position	Quantity	Net Position
Coal (Tons)	10,000	Long	60,000	Long
Emissions (Tons)	25,000	Short	—	—
Natural gas (MMBtu)	2,874,417	Long	2,268,024	Long
Natural gas basis (MMBtu)	24,010,000	Long	12,445,000	Long
Heating oil (Barrels)	115,000	Short	139,000	Short
RBOB UL gasoline (Barrels)	92,000	Short	—	—
Electricity (MWh)	330,480	Long	76,324	Long
Financial transmission rights (MWh)	1,286,808	Short	708,681	Short

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Power Delivery

DPL holds certain derivatives that do not qualify as hedges. These derivatives are recorded at fair value on the balance sheet with the gain or loss recorded in income. In accordance with FASB guidance on regulated operations, offsetting regulatory assets or regulatory liabilities are recorded on the balance sheet and the recognition of the gain or recovery of the loss is deferred. For the three months ended March 31, 2010 and 2009, the amount of the derivative loss recognized by line item in the consolidated statements of income is provided in the table below:

	Three Months Ended March  31,
	2010			2009
	(millions of dollars)
Loss Deferred as a Regulatory Asset or Liability	$	(6	)	$	(14	)
Loss Reclassified from Regulatory Asset or Liability to Fuel and Purchased Energy Expense		(7	)		(3	)

As of March 31, 2010 and December 31, 2009, DPL had the following net outstanding natural gas commodity forward contracts that did not qualify for hedge accounting:

	March 31, 2010		December 31, 2009
Commodity	Quantity	Net Position	Quantity	Net Position
Natural Gas (MMBtu)	11,468,875	Long	10,442,546	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 may declare an early termination and liquidation of all transactions entered into under the ISDA, including foreclosure against any collateral security. In addition, some of the ISDAs have cross default provisions under which a default by a party under another commodity or derivative contract, or the breach by a party of another borrowing obligation in excess of a specified threshold, is a breach under the ISDA.

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

The gross fair value of PHI’s derivative liabilities, excluding the impact of offsetting transactions or collateral under master netting agreements, with credit risk-related contingent features on March 31, 2010 and December 31, 2009, was $445 million and $287 million, respectively. As of those dates, PHI had posted cash collateral of $50 million and $23 million, respectively, in the normal course of business against the gross derivative liability resulting in a net liability of $395 million and $264 million, respectively, before giving effect to offsetting transactions that are encompassed within master netting agreements that would reduce this amount. PHI’s net settlement amount in the event of a downgrade of PHI and DPL below “investment grade” as of March 31, 2010 and December 31, 2009, would have been approximately

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$313 million and $246 million, respectively, after taking into consideration the master netting agreements. The offsetting transactions or collateral that would reduce PHI’s obligation to the net settlement amount include derivatives and normal purchase and normal sale contracts in a gain position as well as letters of credit already posted as collateral.

PHI’s primary sources for posting cash collateral or letters of credit are its credit facilities. At March 31, 2010 and December 31, 2009, the aggregate amount of cash plus borrowing capacity under PHI credit facilities available to meet the future liquidity needs of PHI totaled $1.2 billion and $1.4 billion, respectively, of which $631 million and $820 million, respectively, was available for the Competitive Energy business.

(13) FAIR VALUE DISCLOSURES

Fair Value of Assets and Liabilities Excluding Debt

PHI has adopted FASB guidance on fair value measurement and disclosures (ASC 820) which established a framework for measuring fair value and expanded disclosures about fair value measurements. As defined in the guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). PHI utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. Accordingly, PHI utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurement) and the lowest priority to unobservable inputs (level 3 measurement). PHI classifies its fair value balances in the fair value hierarchy based on the observability of the inputs used in the fair value calculation as follows:

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

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

The instruments primarily consist of electricity derivatives and wholesale gas futures and swaps at March 31, 2010. Level 2 power swaps are priced at liquid trading hub prices or valued using the liquid hub prices plus a congestion adder that is calculated using historical regression analysis. Natural gas futures and swaps are valued using broker quotes in liquid markets, and other observable pricing data.

Executive deferred compensation plan assets and liabilities include life insurance policies that are categorized as level 2 assets because they are priced based on the underlying assets in the policy. The underlying assets of these life insurance contracts consist of short term cash equivalents and fixed income securities that are priced using observable market data. The level 2 liability of the life insurance contract represents deferred compensation obligation, the value of which are tracked via underlying insurance sub-accounts. The sub-accounts are designed to track and mirror existing mutual funds and money market funds that are observable and actively traded.

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

The level 3 instruments with the most significant amount of fair value at March 31, 2010 are electricity derivatives. The majority of Conectiv Energy’s pricing information for these level 3 valuations was obtained from a third party pricing system used widely throughout the energy industry. A portion of these electricity derivatives are comprised of load service contracts valued using liquid hub prices, a zonal congestion adder that is calculated using historical regression, historical ancillary service costs, and a series of modeled risk adders.

Derivative instruments categorized as level 3 that are derivative liabilities also include natural gas options purchased by DPL as part of a natural gas hedging program approved by the DPSC. Some non-standard assumptions are used in their forward valuation to adjust for the pricing; otherwise, most of the options follow NYMEX valuation. A few of the options have no significant NYMEX components, and have to be priced using internal volatility assumptions.

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

The following tables set forth, by level within the fair value hierarchy, PHI’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2010 and December 31, 2009. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. PHI’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

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	Fair Value Measurements at March 31, 2010
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Derivative instruments
Coal (e)	$	5	$	—		$	5		$	—
Natural Gas (f)		7		—			7			—
Electricity (g)		101		—			27	(a)		74	(b)
Capacity		9		9			—			—
Cash equivalents
Treasury Fund		30		30			—			—
Other (e.g. Commercial Paper)		1		1			—			—
Executive deferred compensation plan assets
Money Market Funds		12		12			—			—
Life Insurance Contracts		62		—			43			19
	$	227	$	52		$	82		$	93
LIABILITIES
Derivative instruments
Coal (e)	$	4	$	—		$	4		$	—
Natural Gas (f)		274		199	(c)		38	(d)		37
Electricity (g)		337		—			337			—
Oil (h)		3		3			—			—
Capacity		1		1			—			—
Executive deferred compensation plan liabilities
Life Insurance Contracts		30		—			30			—
	$	649	$	203		$	409		$	37

(a) Includes a contra-asset balance of $5 million related to the impact of netting certain counterparties across the levels of the fair value hierarchy.

(b) Includes a contra-asset balance of $9 million related to the impact of netting certain counterparties across the levels of the fair value hierarchy.

(c) Includes a contra-liability balance of $11 million related to the impact of netting certain counterparties across the levels of the fair value hierarchy.

(d) Includes a contra-liability balance of $1 million related to the impact of netting certain counterparties across the levels of the fair value hierarchy.

(e) Assets represent forward coal transactions and liabilities represent over-the-counter swaps that are part of fuel input for PHI’s generation strategy.

(f) Represents wholesale gas futures and swaps that are used mainly as part of PHI’s generation and energy marketing strategy.

(g) Represents power swaps priced (Level 2) and long-dated power swaps (Level 3) that are mainly part of PHI’s power output generation strategy and PJM Load service strategy.

(h) Represents oil futures that are mainly part of PHI’s fuel input generation strategy and energy marketing strategy.

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	Fair Value Measurements at December 31, 2009
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Derivative instruments
Coal (b)	$	8	$	—		$	8	$	—
Natural Gas (c)		4		—			4		—
Electricity (d)		55		—			25		30
Capacity (e)		8		8			—		—
Cash equivalents
Treasury Fund		36		36			—		—
Other (e.g. Commercial Paper)		1		1			—		—
Executive deferred compensation plan assets
Money Market Funds		13		13			—		—
Life Insurance Contracts		62		—			43		19
	$	187	$	58		$	80	$	49
LIABILITIES
Derivative instruments
Coal (b)	$	6	$	—		$	6	$	—
Natural Gas (c)		187		136	(a)		22		29
Electricity (d)		242		—			239		3
Oil (f)		5		4			1		—
Capacity (e)		2		2			—		—
Executive deferred compensation plan liabilities
Life Insurance Contracts		32		—			32		—
	$	474	$	142		$	300	$	32

(a) Includes a contra-liability balance of $6 million related to the impact of netting certain counterparties across the levels of the fair value hierarchy.

(b) Assets represent forward coal transactions and liabilities represent over-the-counter swaps that are part of fuel input for PHI’s generation strategy.

(c) Represents wholesale gas futures and swaps that are used mainly as part of PHI’s generation and energy marketing strategy.

(d) Represents power swaps priced (Level 2) and long-dated power swaps (Level 3) that are mainly part of PHI’s power output generation strategy and PJM Load service strategy.

(e) Assets represent capacity swaps which were used in PHI’s power output generation strategy and PJM Load service strategy.

(f) Represents oil futures that are mainly part of PHI’s fuel input generation strategy and energy marketing strategy.

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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, 2010 and 2009 are shown below:

	Three Months Ended March 31, 2010
	Electricity			Natural Gas			Life Insurance Contracts
	(millions of dollars)
Beginning balance as of January 1, 2010	$	27		$	(29	)	$	19
Total gains or (losses) (realized and unrealized)
Included in income		69	(a)		—			1
Included in accumulated other comprehensive loss		5			—			—
Included in regulatory liabilities		—			(12	)		—
Purchases and issuances		—			—			(1	)
Settlements		(27	)		4			—
Transfers in (out) of Level 3		—			—			—
Ending balance as of March 31, 2010	$	74		$	(37	)	$	19

(a) These gains relate primarily to load sale contracts where energy prices have fallen since contractual prices were set.

	Operating Revenue		Other Operation and Maintenance Expense
	(millions of dollars)
Gains or (losses) (realized and unrealized) included in income for the period above are reported in Operating Revenue and Other Operation and Maintenance Expense as follows:
Total gains (losses) included in income for the period above	$	69	$	1
Change in unrealized gains (losses) relating to assets still held at reporting date	$	56	$	1

	Three Months Ended March 31, 2009
	Electricity			Natural Gas			Life Insurance Contracts
	(millions of dollars)
Beginning balance as of January 1, 2009	$	2		$	(24	)	$	18
Total gains or (losses) (realized and unrealized)
Included in income		1			—			1
Included in accumulated other comprehensive loss		6			—			—
Included in regulatory liabilities		—			(17	)		—
Purchases and issuances		—			—			(1	)
Settlements		(1	)		3			—
Transfers in (out) of Level 3		—			—			—
Ending balance as of March 31, 2009	$	8		$	(38	)	$	18

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

Fair Value of Debt Instruments

The estimated fair values of PHI’s non-derivative financial instruments at March 31, 2010 and December 31, 2009 are shown below:

	March 31, 2010				December 31, 2009
	(millions of dollars)
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	4,975	$	5,350	$	4,969	$	5,350
Transition Bonds issued by ACE Funding		393		424		402		427
Long-Term Project Funding		21		21		20		20
Redeemable Serial Preferred Stock		6		5		6		4

The methods and assumptions described below were used to estimate, as of March 31, 2010 and December 31, 2009, the fair value of each class of non-derivative financial instruments shown above for which it is practicable to estimate a value.

The fair value of long-term debt issued by PHI and its utility subsidiaries was based on actual trade prices as of March 31, 2010 and December 31, 2009, or bid prices obtained from brokers if actual trade prices were not available. The fair values of Transition Bonds issued by ACE Funding, including amounts due within one year, were derived based on bid prices obtained from brokers if actual trade prices were not available or were based on discounted cash flows using current rates for similar issues with similar credit ratings, terms, and remaining maturities for issues with no market price available.

The fair value of the Redeemable Serial Preferred Stock, excluding amounts due within one year, was derived based on quoted market prices or discounted cash flows using current rates for preferred stock with similar terms.

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

(14) COMMITMENTS AND CONTINGENCIES

Regulatory and Other Matters

Proceeds from Settlement of Mirant Bankruptcy Claims

In 2007, Pepco received proceeds from the settlement of its Mirant Corporation (Mirant) bankruptcy claims relating to a power purchase agreement between Pepco and Panda-Brandywine L.P. (Panda PPA). In September 2008, Pepco transferred the Panda PPA to an unaffiliated third party, along with a payment to the third party of a portion of the settlement proceeds. In March 2009, the District of Columbia Public

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Service Commission (DCPSC) approved an allocation between Pepco and its District of Columbia customers of the District of Columbia portion of the Mirant bankruptcy settlement proceeds remaining after the transfer of the Panda PPA. As a result, Pepco recorded a pre-tax gain of $14 million in the first quarter of 2009 reflecting the District of Columbia proceeds retained by Pepco.

On April 20, 2010, the DCPSC issued an order concluding that there are no remaining issues to be resolved in the Mirant bankruptcy proceeding, and requested parties to file requests identifying additional unresolved issues, if any, by April 30, 2010. Because no such requests were received by the deadline, the DCPSC closed the proceeding without further action.

Rate Proceedings

In recent electric service distribution base rate cases, PHI’s utility subsidiaries have proposed the adoption of revenue decoupling methods for retail customers. To date:

• A bill stabilization adjustment mechanism (BSA) has been approved and implemented for both Pepco and DPL electric service in Maryland and for Pepco electric service in the District of Columbia.

• A modified fixed variable rate design (MFVRD) has been approved in concept for DPL electric service in Delaware and a settlement among the parties to the ongoing base rate proceeding (as described below) has been submitted to the DPSC, which provides for the implementation of the MFVRD after the conclusion of DPL’s pending electric base rate case (under Delaware law, the MFVRD must be in place by December 31, 2010).

• An MFVRD has been approved in concept for DPL natural gas service in Delaware and may be implemented either in the context of a pending decoupling case or DPL’s next Delaware natural gas distribution base rate case (under Delaware law, the MFVRD must be in place by December 31, 2010).

• A proposed BSA remains pending for ACE in New Jersey.

Under the BSA, customer delivery rates are subject to adjustment (through a credit or surcharge mechanism), depending on whether actual distribution revenue per customer exceeds or falls short of the revenue-per-customer amount approved by the applicable public service commission. The BSA increases rates if actual distribution revenues fall below the approved level and decreases rates if actual distribution revenues are above the approved level. The result is that, over time, the utility collects its authorized revenues for distribution deliveries. As a consequence, a BSA “decouples” distribution revenue from unit sales consumption and ties the growth in distribution revenues to the growth in the number of customers. Some advantages of the BSA are that it (i) eliminates revenue fluctuations due to weather and changes in customer usage patterns and, therefore, provides for more predictable distribution revenues that are better aligned with costs, (ii) provides for more reliable fixed-cost recovery, (iii) tends to stabilize customers’ delivery bills, and (iv) removes any disincentives for the regulated utilities to promote energy efficiency programs for their customers, because it breaks the link between overall sales volumes and distribution revenues. The MFVRD adopted in Delaware provides for a fixed customer charge (i.e., not tied to the customer’s volumetric consumption) to recover the utility’s fixed costs, plus a reasonable rate of return. Although different from the BSA, PHI views the MFVRD as an appropriate distribution revenue decoupling mechanism.

Delaware

In August 2009, DPL submitted its 2009 GCR filing, which permits DPL to recover gas procurement costs through customer rates, to the DPSC. The filing requested a 10.2% decrease in the level of GCR, to become effective on a temporary basis on November 1, 2009. This rate proposal was approved by the DPSC on September 9, 2009, subject to refund and pending final DPSC approval.

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In September 2009, DPL submitted an application with the DPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $28 million (subsequently lowered to approximately $26.2 million), assuming approval of the implementation of the MFVRD, based on a requested return on equity (ROE) of 10.75%. DPL placed an increase of approximately $2.5 million annually into effect on a temporary basis in November 2009, subject to refund and pending final DPSC approval of the entirety of the requested increase. As permitted by Delaware law, DPL placed the remaining $23.7 million of the requested increase into effect on April 19, 2010, subject to refund and pending the final DPSC order. On April 16, 2010, all of the parties to the proceeding, including DPL, the DPSC staff, the Division of the Public Advocate, the Delaware Department of Natural Resources and Environmental Control, and the Delaware Energy Users Group, which represents large industrial consumers of electricity, signed a settlement agreement regarding implementation of the MFVRD. The settlement agreement, which has been submitted to the Hearing Examiner, provides for implementation of the MFVRD after the conclusion of this proceeding (under Delaware law, the MFVRD must be in place by December 31, 2010). Hearings on the unresolved issues in the case were begun in April 2010. Due to the unavailability of a key witness, the remainder of the hearings was postponed and it is expected that they will be concluded by the end of May 2010. A DPSC decision is expected in the third quarter of 2010.

In June 2009, DPL filed an application requesting approval for the implementation of the MFVRD for gas distribution rates. On August 4, 2009, the DPSC issued an order opening a docket for the matter. Under Delaware law, the MFVRD must be in place by December 31, 2010.

District of Columbia

In January 2008, the DCPSC approved, effective in February 2008, a revenue requirement increase for Pepco of approximately $28 million, based on an authorized return on rate base of 7.96%, including a 10% ROE. 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 order, which was denied by the DCPSC. In August 2008, the DC OPC filed with the District of Columbia Court of Appeals a petition for review of the DCPSC’s order denying its motion for reconsideration. On February 18, 2010, the Court of Appeals issued a decision affirming the decision of the DCPSC.

In May 2009, Pepco submitted an application to the DCPSC to increase electric distribution base rates. The filing sought approval of an annual rate increase of approximately $50 million with the BSA, based on a requested ROE of 11.25% (subsequently revised by Pepco to approximately $44.5 million, based on a requested ROE of 10.75%). The filing also proposed recovery of pension expenses and uncollectible expenses through a surcharge mechanism, which would have reduced the increase request by approximately $3 million. On March 2, 2010, the DCPSC authorized an electric distribution rate increase of $19.8 million, based on an ROE of 9.625%, effective on March 23, 2010, and denied the proposed surcharge mechanism. On March 23, 2010, Pepco filed a request for reconsideration of certain issues decided unfavorably to Pepco, including the level of ROE. On April 1, 2010, the DC OPC and the District of Columbia Water and Sewer Authority also filed separate requests for reconsideration contesting certain issues. On April 22, 2010, the DCPSC issued an order delaying the deadline for ruling on these matters until May 24, 2010.

Maryland

In May 2009, DPL filed an electric distribution base rate case in Maryland. The filing sought approval of an annual rate increase of approximately $14 million, based on a requested ROE of 11.25%. The filing also proposed recovery of pension expenses, other postretirement benefits (OPEB) and uncollectible expenses through a surcharge mechanism, which would have reduced the increase request by approximately $4 million. In December 2009, the Maryland Public Service Commission (MPSC) approved an annual increase of approximately $7.5 million, based on an overall rate of return of 7.96%, including an ROE of 10% and denied the proposed surcharge mechanism for pension, OPEB and uncollectible expenses. The rate increase was implemented through rates that are effective for electric usage on and after December 2, 2009.

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In December 2009, Pepco filed an electric distribution base rate case in Maryland. The filing seeks approval of an annual rate increase of approximately $40 million, based on a requested ROE of 10.75% (revised to approximately $32.2 million in March 2010 to reflect an updated test period). Evidentiary hearings are scheduled to begin in mid-May 2010 and a decision by the MPSC is expected by the end of July 2010.

New Jersey

In August 2009, ACE submitted a petition to the NJBPU to increase its electric distribution base rates, including a request for the implementation of a BSA. Based on a test year ending December 31, 2009, adjusted for known and measurable changes, ACE requested an annual net increase in its current retail distribution rates for electric service in the amount of approximately $54 million (which includes a reduction to its Regulatory Asset Recovery Charge (RARC)) based on a requested ROE of 11.50% (or an increase of approximately $52 million, based on an ROE of 11.25%, if the BSA were approved). Excluding any adjustment to the RARC, as well as sales and use taxes, the amounts in the original application would be approximately $51.6 million without the BSA and $49.8 million with the BSA. On February 19, 2010, ACE made a filing based on an updated test period, adjusting the requested increase to approximately $45.8 million without the BSA and $44.1 million with the BSA (excluding any adjustment to the RARC, as well as sales and use taxes). On April 28, 2010, all of the parties to the proceeding, including ACE, the NJBPU Staff, the New Jersey Department of the Public Advocate, Division of Rate Counsel, the Natural Resources Defense Council, and Wal-Mart Stores East, LP and Sam’s East, signed a settlement agreement and submitted it to the Administrative Law Judge (ALJ) in the proceeding for review. The settlement agreement provides for an increase in electric distribution rates, effective for service rendered on and after June 1, 2010, of approximately $20 million (excluding any adjustment to the RARC, as well as sales and use taxes), based on a stated ROE of 10.30%. The agreement also provides that the BSA and certain other issues will be considered in a Phase II proceeding. On April 30, 2010, the ALJ issued an initial decision ordering the parties to comply with the settlement terms. The settlement agreement is subject to final review and approval by the NJBPU. The parties have requested that the NJBPU consider the matter at the public meeting currently scheduled for May 12, 2010. If the settlement is not approved, the matter will be scheduled for hearings.

District of Columbia Divestiture Case

In June 2000, the DCPSC approved a divestiture settlement under which Pepco is required to share with its District of Columbia customers the net proceeds realized by Pepco from the sale of its generation-related assets. 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, 2010, the District of Columbia allocated portions of EDIT and ADITC associated with the divested generating assets were approximately $6 million each.

Pepco believes that a sharing of EDIT and ADITC with its District of Columbia customers 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. Also, 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, 2010), as well as its District of Columbia jurisdictional transmission and distribution-related ADITC balance ($3 million as of March 31, 2010), 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.

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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.

Pepco believes that its calculation of the District of Columbia customers’ share of divestiture proceeds is correct. Nevertheless, if Pepco is required by the DCPSC to share its EDIT and ADITC balances with its District of Columbia customers, the additional gain-sharing payments, along with any required ADITC-related payments to the IRS, could have a material adverse effect on Pepco’s and PHI’s results of operations for periods in which the payments are required to be made. However, neither PHI nor Pepco believes that such payments would have a material adverse impact on its financial position or cash flows.

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. The claim for indemnification seeks payment from ACE in the event the TSA is held not to be enforceable against Citgo.

RC Cape May commenced an arbitration proceeding against Citgo seeking a determination that the TSA remains in effect and notified ACE of the proceedings. On July 1, 2009, the arbitrator issued its interim award, ruling that the TSA remains in effect and is enforceable by RC Cape May against Citgo. PHI believes this ruling invalidates RC Cape May’s indemnification claim against ACE, but cannot predict whether RC Cape May will continue to pursue indemnification.

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

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successfully dismissed with prejudice, either voluntarily by the plaintiff or by the court. As of March 31, 2010, there are approximately 180 cases still pending against Pepco in the State Courts of Maryland, of which approximately 90 cases were filed after December 19, 2000, and were tendered to Mirant for defense and indemnification 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 condition, results of operations or cash flows. However, if an unfavorable decision were rendered against Pepco, it could have a material adverse effect on Pepco’s and PHI’s financial condition, results of operations and cash flows.

Environmental Litigation

PHI, through its subsidiaries, is subject to regulation by various federal, regional, state, and local authorities with respect to the environmental effects of its operations, including air and water quality control, solid and hazardous waste disposal, and limitations on land use. In addition, federal and state statutes authorize governmental agencies to compel responsible parties to clean up certain abandoned or unremediated hazardous waste sites. PHI’s subsidiaries may incur costs to clean up currently or formerly owned facilities or sites found to be contaminated, as well as other facilities or sites that may have been contaminated due to past disposal practices. Although penalties assessed for violations of environmental laws and regulations are not recoverable from customers of the operating utilities, environmental clean-up costs incurred by Pepco, DPL and ACE would be included by each company in its respective cost of service for ratemaking purposes.

Frontier Chemical Site. In June 2007, ACE received a letter from the New York Department of Environmental Conservation (NYDEC) identifying ACE as a potentially responsible party (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. In February 2010, ACE accepted the PRP group’s offer of a de minimis cash-out settlement under which ACE paid a total of $16,000 to receive a release from liability from the PRP group and be relieved from any further involvement at the site.

Franklin Slag Pile Site. On November 26, 2008, ACE received a general notice letter from the U.S. Environmental Protection Agency (EPA) concerning the Franklin Slag Pile site in Philadelphia, Pennsylvania, asserting that ACE is a 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 as of the date of the letter, EPA’s 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.

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

Peck Iron and Metal Site. EPA informed Pepco in a May 20, 2009 letter that Pepco may be a PRP under CERCLA with respect to the cleanup of the Peck Iron and Metal site in Portsmouth, Virginia, or for costs EPA has incurred in cleaning up the site. EPA’s letter states that Peck Iron and Metal purchased, processed, stored and shipped metal scrap from military bases, governmental agencies and businesses and that Peck’s metal scrap operations resulted in the improper storage and disposal of hazardous substances. EPA bases its allegation that Pepco arranged for disposal or treatment of hazardous substances sent to the site on information provided by Peck Iron and Metal personnel, who informed the EPA that Pepco was a customer at the site. Pepco has advised the EPA by letter that its records show no evidence of any sale of scrap metal by Pepco to the site. Even if EPA has such records and such sales did occur, Pepco believes that any such scrap metal sales are entitled to the recyclable material exemption from CERCLA liability. At this time Pepco cannot predict how EPA will proceed regarding this matter, or what portion, if any, of the Peck Iron and Metal Site response costs EPA would seek to recover from Pepco. In a notice published on November 4, 2009, EPA placed the Peck Iron and Metal Site on the National Priorities List.

Ward Transformer Site. In April 2009, a group of PRPs with respect to the Ward Transformer site in Raleigh, North Carolina, filed a complaint in the U.S. District Court for the Eastern District of North Carolina, alleging cost recovery and/or contribution claims against ACE, DPL and Pepco with respect to past and future response costs incurred by the PRP group in performing a removal action at the site. With the court’s permission, the plaintiffs filed amended complaints on September 1, 2009. ACE, DPL and Pepco, as part of a group of defendants, filed a motion to dismiss on October 13, 2009. In a March 24, 2010 order, the court denied the defendants’ motion to dismiss. Although it is too early in the process to characterize the magnitude of the potential liability at this site, it does not appear that any of the three PHI utilities had extensive business transactions, if any, with the Ward Transformer site.

Deepwater Generating Facility. In December 2005, the New Jersey Department of Environmental Protection (NJDEP) issued a Title V operating permit (the Title V Permit) to Deepwater generating facility (Deepwater) owned by Conectiv Energy. In January 2006, Conectiv Energy filed an appeal (the Title V Appeal) with the New Jersey Office of Administrative Law (OAL) challenging several provisions of the Title V Permit, including newly imposed hourly and annual limits on unit heat input (the amount of energy introduced to the boiler in a specified time period). In an October 2007 order, the OAL ALJ granted a summary decision in favor of Conectiv Energy, finding that NJDEP does not have the authority to use hourly heat input as a basis to condition or limit electric generating operations, which order the ALJ subsequently amended also to include annual heat limitations (as amended, the October 2007 Order).

On July 29, 2009, the ALJ issued an initial decision incorporating the October 2007 Order, an intervening December 2008 order regarding other challenged permit conditions and the parties’ partial stipulation of settlement, and transmitted the matter to the NJDEP Commissioner for a final decision. On December 8, 2009, the NJDEP Commissioner issued a final decision rejecting the ALJ’s initial October 2007 Order as it related to hourly and annual heat input limits and remanding to the ALJ for further consideration Conectiv Energy’s challenge to NJDEP’s asserted legal basis for including annual fuel use limits in the Title V Permit. Upon resolution of the fuel use limit issue, Conectiv Energy will evaluate whether to appeal the NJDEP Commissioner’s decision.

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In April 2007, NJDEP initiated enforcement action by issuing an Administrative Order and Notice of Civil Administrative Penalty Assessment (the April 2007 Order) alleging that on several occasions Deepwater Unit 1 exceeded the maximum allowable hourly heat input in calendar year 2005 and that Unit 6/8 exceeded its maximum allowable hourly heat input in calendar years 2005 and 2006. The April 2007 Order required Conectiv Energy to operate the Deepwater units in compliance with their hourly heat input limits and assessed a penalty of approximately $1 million. In May 2007, NJDEP initiated a second enforcement action (the May 2007 Order, and collectively with the April 2007 Order, the Enforcement Orders) alleging that each of the Deepwater units exceeded its maximum allowable hourly heat input in calendar year 2004. The May 2007 Order required Conectiv Energy to operate the units in compliance with their hourly heat input limits and assessed a penalty of $811,600. Conectiv Energy appealed the Enforcement Orders in the OAL. Because the ALJ for the OAL was already reviewing NJDEP’s authority to impose heat input limits as part of the Deepwater Title V appeal, the ALJ placed the appeal of the Enforcement Orders on inactive status. The ALJ has indicated that the Enforcement Orders will remain inactive pending resolution, including any appeal of Conectiv Energy’s challenge to the NJDEP’s authority to impose heat input limits as a basis to condition or limit electric generating operations. Any penalty associated with resolution of these Enforcement Orders is a retained environmental liability under the Purchase Agreement with Calpine. Additional information about the Purchase Agreement can be found in Note (15), “Subsequent Event.”

Appeal of New Jersey Flood Hazard Regulations. In November 2007, NJDEP adopted amendments to the agency’s regulations under the Flood Hazard Area Control Act (FHACA) to minimize damage to life and property from flooding caused by development in flood plains. The amended regulations impose a new regulatory program to mitigate flooding and related environmental impacts from a broad range of construction and development activities, including electric utility transmission and distribution construction that was previously unregulated under the FHACA. These regulations impose restrictions on construction of new electric transmission and distribution facilities and increase the time and personnel resources required to obtain permits and conduct maintenance activities. In November 2008, ACE filed an appeal of these regulations with the Appellate Division of the Superior Court of New Jersey. The grounds for ACE’s appeal include the lack of administrative record justification for the FHACA regulations and conflict between the FHACA regulations and other state and federal regulations and standards for maintenance of electric power transmission and distribution facilities. The case is currently in the briefing process before the appellate court.

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 generating facilities and natural gas distribution networks) located outside of the United States. Each of these investments is structured as a sale and leaseback transaction commonly referred to as a sale-in/lease-out or SILO transaction. PHI’s current annual tax benefits from these eight cross-border energy lease investments are approximately $59 million. As of March 31, 2010, PHI’s equity investment in its cross-border energy leases was approximately $1.4 billion, which included the impact of the reassessments discussed below. From January 1, 2001, the earliest year that remains open to audit, to March 31, 2010, PHI has derived approximately $531 million in federal and state income tax benefits from the depreciation and interest deductions in excess of rental income with respect to these cross-border energy lease investments.

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In 2005, the Treasury Department and IRS issued Notice 2005-13 identifying sale-leaseback transactions with certain attributes entered into with tax-indifferent parties as tax avoidance transactions, and the IRS announced its intention to disallow the associated tax benefits claimed by the investors in these transactions. PHI’s cross-border energy lease investments, each of which is with a tax-indifferent party, have been under examination by the IRS as part of the normal PHI federal income tax audits. In the final RARs issued in June 2006 and in March 2009 in connection with the audit of PHI’s 2001-2002, and 2003-2005 income tax returns, respectively, the IRS disallowed the depreciation and interest deductions in excess of rental income claimed by PHI with respect to each of its cross-border energy lease investments. In addition, the IRS has sought to recharacterize each of the leases as loan transactions as to which PHI would be subject to original issue discount income. PHI disagrees with the IRS’ proposed adjustments and filed tax protests in August 2006 and May 2009 in connection with the audit of PHI’s 2001-2002 and 2003-2005 income tax returns, respectively. Both cases have been forwarded to and are under review by the IRS Appeals Office.

PHI believes that it is unlikely that a resolution will be reached with the Appeals Office and, therefore, PHI currently intends to pursue litigation against the IRS to defend its tax position, which, absent a settlement, may take several years to resolve. In the last several years, IRS challenges to certain cross-border lease transactions have been the subject of litigation, including several decisions in favor of the IRS which were factored into PHI’s decision to adjust the lease values in June 2008. On October 21, 2009, the U.S. Court of Federal Claims issued a decision in favor of a taxpayer regarding a cross-border lease transaction. PHI views this ruling as a favorable development in PHI’s dispute with the IRS because the transaction that is the subject of the ruling is similar in many respects to PHI’s cross-border energy lease investments.

At December 31, 2009, PHI modified its tax cash flow assumptions under its cross-border energy lease investments for the period 2010-2012 to reflect the anticipated timing of potential litigation with the IRS concerning the investments. As a result of the recalculation of the equity investment, PHI recorded a $2 million after-tax non-cash earnings charge in 2009, and expects to record a $3 million after-tax non-cash earnings benefit in 2010.

In the event that the IRS were to be successful in disallowing 100% of the tax benefits associated with these leases and recharacterizing these leases as loans, PHI estimates that, as of March 31, 2010, it would be obligated to pay approximately $636 million in additional federal and state taxes and $112 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 re-characterization of the leases as loans would be recoverable in the form of lower taxes over the remaining terms of the affected leases. Moreover, the entire amount of any additional tax would not be due immediately. Rather, the federal and state taxes would be payable when the open audit years are closed and PHI amends subsequent tax returns not then under audit. To mitigate the taxes due in the event of a total disallowance of tax benefits, PHI could, were it to so elect, choose to liquidate all or a portion of its cross-border energy lease portfolio, which PHI estimates could be accomplished over a period of six months to one year. Based on current market values, PHI estimates that liquidation of the entire portfolio would generate sufficient cash proceeds to cover the estimated $748 million in federal and state taxes and interest due as of March 31, 2010, in the event of a total disallowance of tax benefits and a recharacterization of the transactions as loans. If payments of additional taxes and interest preceded the receipt of liquidation proceeds, the payments would be funded by currently available sources of liquidity.

To the extent that PHI does not prevail in this matter and suffers a disallowance of the tax benefits and incurs imputed original issue discount income due to the recharacterization of the leases as loans, PHI would be required under FASB guidance on leases (ASC 840 and ASC 850) to recalculate the timing of the tax benefits generated by the cross-border energy lease investments and adjust the equity value of the investments, which would result in a non-cash charge to earnings.

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District of Columbia Tax Legislation

On December 24, 2009, the Mayor of the District of Columbia approved legislation adopted by the City Council that imposes mandatory combined unitary business reporting effective for tax year 2011, and revises the District’s related party expense disallowance effective for tax year 2009. The legislation was transmitted to Congress on January 5, 2010. In March, the Congressional review period expired without action and the legislation became law. Because the City Council must still write and pass further legislation providing guidance on how to implement unitary reporting before this provision is effective, PHI believes that the legislative process was not complete as of March 31, 2010, and, therefore, the effect of the legislation for combined unitary business tax reporting has not been accounted for as of March 31, 2010. However, since the City Council is not required to enact any further legislation related to the provisions for the disallowance of related party transactions, PHI accrued $0.5 million of additional income tax expense during the quarter ended March 31, 2010.

The legislation does not define the term “unitary business” and does not specify how combined tax reporting would differ from our current consolidated tax reporting in the District of Columbia. However, based upon PHI’s interpretation of combined unitary business tax reporting in other taxing jurisdictions, the legislation would likely result in a change in PHI’s overall state income tax rate and, therefore, would likely require an adjustment to PHI’s net deferred income tax liabilities. Further, to the extent that the change in rate increases net deferred income tax liabilities, PHI must determine if these increased tax liabilities are probable of recovery in future rates. No timetable has been established by the City Council to write and pass further legislation and, therefore, uncertainty exists as to whether combined unitary reporting will be effective for PHI.

Management continues to analyze the impact that the unitary business tax reporting aspect of this legislation, if completed, may have on the financial position, results of operations and cash flows of PHI and its subsidiaries.

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

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

As of March 31, 2010, Pepco Holdings and its subsidiaries were parties to a variety of agreements pursuant to which they were guarantors for standby letters of credit, performance residual value, and other commitments and obligations. The commitments and obligations, in millions of dollars, were as follows:

	Guarantor
	PHI		DPL		ACE		Pepco		Total
Energy marketing obligations of Conectiv Energy (a)	$	153	$	—	$	—	$	—	$	153
Energy procurement obligations of Pepco Energy Services (a)		465		—		—		—		465
Guaranteed lease residual values (b)		—		4		2		1		7
Other (c)		1		—		—		—		1
Total	$	619	$	4	$	2	$	1	$	626

(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, 2010, obligations under the guarantees were approximately $7 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.

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(c) Pepco Holdings has guaranteed a subsidiary building lease of $1 million. Pepco Holdings does not expect to fund the full amount of the exposure under the guarantee.

Pepco Holdings and certain of its subsidiaries have entered into various indemnification agreements related to purchase and sale agreements and other types of contractual agreements with vendors and other third parties. These indemnification agreements typically cover environmental, tax, litigation and other matters, as well as breaches of representations, warranties and covenants set forth in these agreements. Typically, claims may be made by third parties under these indemnification agreements over various periods of time depending on the nature of the claim. The maximum potential exposure under these indemnification agreements can range from a specified dollar amount to an unlimited amount depending on the nature of the claim and the particular transaction. The total maximum potential amount of future payments under these indemnification agreements is not estimable due to several factors, including uncertainty as to whether or when claims may be made under these indemnities.

Dividends

On April 22, 2010, Pepco Holdings’ Board of Directors declared a dividend on common stock of 27 cents per share payable June 30, 2010, to shareholders of record on June 10, 2010.

(15) SUBSEQUENT EVENT

On April 20, 2010, the Board of Directors of PHI approved a plan for the disposition of Conectiv Energy. The plan consists of the sale of Conectiv Energy’s Generation Business and the liquidation of all of Conectiv Energy’s load service supply contracts, energy hedging portfolio, certain tolling agreements and non-core assets. In accordance with the plan, PHI on the same day entered into the Purchase Agreement. Under the terms of the Purchase Agreement, Calpine will purchase a subsidiary of PHI, which after a reorganization will hold the assets and liabilities of the Generation Business, for a purchase price of $1.65 billion, plus the market value of the fuel oil inventory at closing, and subject to various adjustments, including adjustments for (i) the level of working capital and non-fuel oil inventory at closing and (ii) actual capital expenditures relative to budgeted capital expenditures through the closing date.

The targeted closing date for the sale is June 30, 2010. Beginning July 1, 2010, and until the closing occurs, the purchase price will be reduced by a specified amount per day. The amount of the per diem reduction is (i) $360,000 in July, (ii) $363,500 in August, (iii) $237,500 in September, (iv) $195,000 in October, (v) $189,500 in November, and (vi) $219,500 in December. If the closing does not occur on or before December 31, 2010, either PHI or Calpine may elect to terminate the Purchase Agreement so long as the inability to close the transaction as of that date is not the result of either party’s failure to fulfill any of its obligations under the Purchase Agreement.

Completion of the transaction requires the approval of the Federal Energy Regulatory Commission and satisfaction of the requirements of the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended. Each party’s obligation to complete the sale also is contingent on other customary closing conditions, including the material accuracy of the other party’s representations and warranties and the compliance by the other party with its covenants. The obligation of Calpine to complete the purchase is also subject to various other conditions, including the condition that subsequent to April 20, 2010, no event, condition or development shall have occurred that has or is reasonably likely to have a material adverse effect (i) on the Generation Business as a whole, (ii) on any of Conectiv Energy’s principal generating facilities or (iii) on any combination of Conectiv Energy’s other generating facilities that together constitute 50% of the generating capacity of those other generating facilities.

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Either PHI or Calpine can elect to terminate the transaction if the other party breaches a representation, warranty or covenant (generally after being afforded a period to cure the breach). If the breach is willful and intentional, the terminating party will be entitled to a payment in the amount of $175 million as liquidated damages. If the breach is negligent, the terminating party will be entitled to a payment in the amount of $40 million as liquidated damages. If PHI’s breach is neither willful and intentional nor negligent, Calpine will be entitled to a payment in the amount of $20 million as liquidated damages. Calpine also is entitled to terminate the transaction, and receive a payment in the amount of $40 million as liquidated damages, if (i) PHI fails to obtain by June 1, 2010, the lender consents required under its credit facilities to effect the transaction, (ii) PHI has not delivered to Calpine by June 1, 2010, audited financial statements for the Conectiv Energy segment for the year ended December 31, 2009, that are not materially different from the unaudited financial statements for the same period previously delivered to Calpine, (iii) DPL and ACE have not by June 15, 2010, executed and delivered certain amended and restated easement agreements, or (iv) DPL and ACE have not by June 15, 2010 (subject to a 45 day cure period), obtained the releases of certain property and rights from the liens of their respective mortgages.

All of Conectiv Energy’s generating facilities, which have an aggregate generating capacity of 3,860 megawatts, are included in the sale. Calpine is also acquiring the Delta Project, along with a 6-year tolling agreement associated with the Delta Project. Under the plan adopted by the board of directors, all of the remaining assets and liabilities of the Conectiv Energy segment, including Conectiv Energy’s load service supply contracts, energy hedging portfolio, certain tolling agreements and other non-core assets, will be liquidated over a period not exceeding 12 months from the date of the adoption of the plan.

PHI currently estimates that the sale of the Generation Assets on the terms set forth in the Purchase Agreement and the liquidation of the remaining Conectiv Energy assets will result in a loss through the completion of the liquidation for financial reporting purposes ranging from $60 million to $90 million, after tax. The loss to be recognized in the second quarter of 2010 could exceed this range due to unrealized losses required to be recorded in earnings related to derivative instruments no longer qualifying for cash flow hedge accounting. PHI currently estimates that these unrealized losses will be offset by gains from the liquidation of load service supply contracts over the liquidation period.

The estimated after-tax proceeds from the sale of the Generation Assets and the liquidation of the remaining Conectiv Energy assets and contracts, combined with the return of collateral posted under the contracts, are expected to total approximately $1.75 billion. Taxes on the sale and liquidation of the assets are currently estimated to be approximately $300 million.

Bridge Loan Facility

On April 20, 2010, PHI entered into a Credit Agreement for an aggregate principal amount of loans of up to $450 million with Morgan Stanley Bank, N.A. and Credit Suisse AG, Cayman Islands Branch (collectively, the Lenders), and Morgan Stanley Senior Funding, Inc., as administrative agent (the Bridge Loan Facility). PHI is entitled to make up to two draws under the Bridge Loan Facility at any time on or before June 1, 2010. The Bridge Loan Facility matures on April 19, 2011. All indebtedness incurred under the Bridge Loan Facility is unsecured.

The interest rate payable by PHI on funds borrowed under the Bridge Loan Facility is, at its election, based on either (a) the corresponding 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 in each case a margin that varies according to the credit rating of PHI.

PHI may use the proceeds of loans drawn under the Bridge Loan Facility solely to repay $200 million in aggregate principal amount of its 4.00% Notes due May 15, 2010 and $250 million in aggregate principal amount of its Floating Rate Notes due June 1, 2010. Subject to certain exceptions, the Bridge Loan Facility requires PHI to make mandatory prepayments upon the receipt by PHI of cash proceeds from (i) certain

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issuances of equity interests by PHI, (ii) the issuance of debt securities in a public or private debt or capital markets transaction with a maturity of greater than one year, (iii) the borrowing by PHI under a credit facility not currently in effect, and (iv) certain asset sales, including the sale of the Conectiv Energy wholesale power generation assets.

Under the terms of the Bridge Loan Facility, PHI must be in compliance with specified covenants, including (i) the requirement that PHI maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the Bridge Loan Facility, 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 permitted sales and dispositions, and (iii) a restriction on the incurrence of liens on the assets of PHI or any of its significant subsidiaries other than permitted liens. 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 Bridge Loan Facility. The Bridge Loan Facility does not include any ratings triggers.

The failure to satisfy any of the covenants or the occurrence of other specified events that constitute an event of default could result in the acceleration of the repayment obligations of PHI. The events of default include (i) the failure of PHI or any of its significant subsidiaries to pay when due, or the acceleration of, certain indebtedness under other borrowing arrangements, (ii) certain bankruptcy events, judgments or decrees against PHI or its significant subsidiaries, and (iii) a change in control (as defined in the Bridge Loan Facility) of PHI or the failure of PHI to own all of the voting stock of Pepco, DPL and ACE.

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POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended March 31,
	2010			2009
	(millions of dollars)
Operating Revenue	$	552		$	577
Operating Expenses
Purchased energy		315			349
Other operation and maintenance		88			79
Depreciation and amortization		38			35
Other taxes		75			73
Effect of settlement of Mirant bankruptcy claims		—			(14	)
Total Operating Expenses		516			522
Operating Income		36			55
Other Income (Expenses)
Interest and dividend income		—			1
Interest expense		(25	)		(25	)
Other income		3			2
Total Other Expenses		(22	)		(22	)
Income Before Income Tax Expense		14			33
Income Tax Expense		6			14
Net Income		8			19
Retained Earnings at Beginning of Period		730			624
Dividends Paid to Parent		(25	)		—
Retained Earnings at End of Period	$	713		$	643

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

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POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

(Unaudited)

	March 31, 2010			December 31, 2009
	(millions of dollars)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	200		$	213
Restricted cash equivalents		—			1
Accounts receivable, less allowance for uncollectible accounts of $17 million and $17 million, respectively		352			354
Inventories		47			43
Prepayments of income taxes		67			79
Prepaid expenses and other		26			48
Total Current Assets		692			738
INVESTMENTS AND OTHER ASSETS
Regulatory assets		163			166
Prepaid pension expense		292			295
Investment in trust		25			25
Income taxes receivable		63			64
Other		70			70
Total Investments and Other Assets		613			620
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		5,925			5,865
Accumulated depreciation		(2,514	)		(2,481	)
Net Property, Plant and Equipment		3,411			3,384
TOTAL ASSETS	$	4,716		$	4,742

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

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POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

(Unaudited)

	March 31, 2010		December 31, 2009
	(millions of dollars, except shares)
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Current portion of long-term debt	$	—	$	16
Accounts payable and accrued liabilities		149		154
Accounts payable due to associated companies		93		111
Capital lease obligations due within one year		7		7
Taxes accrued		36		37
Interest accrued		37		18
Other		126		124
Total Current Liabilities		448		467
DEFERRED CREDITS
Regulatory liabilities		151		145
Deferred income taxes, net		897		893
Investment tax credits		8		8
Other postretirement benefit obligation		71		71
Income taxes payable		5		5
Liabilities and accrued interest related to uncertain tax positions		30		29
Other		57		58
Total Deferred Credits		1,219		1,209
LONG-TERM LIABILITIES
Long-term debt		1,539		1,539
Capital lease obligations		92		92
Total Long-Term Liabilities		1,631		1,631
COMMITMENTS AND CONTINGENCIES (NOTE 10)
EQUITY
Common stock, $.01 par value, 200,000,000 shares authorized, 100 shares outstanding		—		—
Premium on stock and other capital contributions		705		705
Retained earnings		713		730
Total Equity		1,418		1,435
TOTAL LIABILITIES AND EQUITY	$	4,716	$	4,742

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

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POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
	2010			2009
	(millions of dollars)
OPERATING ACTIVITIES
Net income	$	8		$	19
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		38			35
Effect of settlement of Mirant bankruptcy claims		—			(14	)
Changes in restricted cash equivalents related to Mirant settlement		—			38
Deferred income taxes		16			8
Changes in:
Accounts receivable		2			14
Inventories		(4	)		(4	)
Regulatory assets and liabilities, net		8			28
Accounts payable and accrued liabilities		(15	)		(16	)
Taxes accrued		13			91
Interest accrued		19			20
Other assets and liabilities		12			5
Net Cash From Operating Activities		97			224
INVESTING ACTIVITIES
Investment in property, plant and equipment		(65	)		(67	)
Changes in restricted cash equivalents		1			—
Net other investing activities		—			2
Net Cash Used By Investing Activities		(64	)		(65	)
FINANCING ACTIVITIES
Dividends paid to Parent		(25	)		—
Issuances of long-term debt		—			110
Reacquisition of long-term debt		(16	)		(50	)
Net other financing activities		(5	)		(9	)
Net Cash (Used by) From Financing Activities		(46	)		51
Net (Decrease) Increase in Cash and Cash Equivalents		(13	)		210
Cash and Cash Equivalents at Beginning of Period		213			146
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	200		$	356
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash received for income taxes (includes payments to PHI for Federal income taxes)	$	23		$	81

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

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NOTES TO FINANCIAL STATEMENTS

POTOMAC ELECTRIC POWER COMPANY

(1) ORGANIZATION

Potomac Electric Power Company (Pepco) is engaged in the transmission and distribution of electricity in the District of Columbia and major portions of Prince George’s County and Montgomery County in suburban Maryland. Pepco also provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its 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, 2009. 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, 2010, 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, 2010 may not be indicative of results that will be realized for the full year ending December 31, 2010 since the sales of electric energy are seasonal.

Use of Estimates

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

Significant matters that involve the use of estimates include the assessment of contingencies, the calculation of future cash flows and fair value amounts for use in asset impairment evaluations, pension and other postretirement benefits assumptions, unbilled revenue calculations, the assessment of the probability of recovery of regulatory assets, estimation of storm restoration accruals, and income tax provisions and reserves. Additionally, Pepco is subject to legal, regulatory, and other proceedings and claims that arise in the ordinary course of its business. Pepco records an estimated liability for these proceedings and claims when the loss is determined to be probable and is reasonably estimable.

During the first quarter of 2010, Pepco incurred significant costs associated with the February 2010 severe winter storms that affected its service territories. The total costs of the restoration efforts have been estimated at $15 million with $11 million charged to Other Operation and Maintenance expense for repair work and $4 million recorded as capital expenditures. A large portion of the costs of the restoration work relate to services provided by outside contractors and other utilities, and billings for such services in most instances have not yet been received and have been estimated. Actual billings may vary significantly from the estimates of such billings.

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Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in Pepco’s gross revenues were $63 million and $61 million for the three months ended March 31, 2010 and 2009, respectively.

Reclassifications and Adjustments

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

(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Transfers and Servicing (Accounting Standards Codification (ASC) 860)

The Financial Accounting Standards Board (FASB) issued new guidance that removes the concept of a qualifying special-purpose entity (QSPE) from the current guidance on transfers and servicing and the QSPE scope exception in current guidance on consolidation. The new guidance also changed the requirements for derecognizing financial assets and requires additional disclosures about a transferor’s continuing involvement in transferred financial assets.

The guidance was effective for transfers of financial assets occurring in fiscal periods beginning on January 1, 2010 for Pepco. As of January 1, 2010, Pepco has adopted the provisions of this guidance and determined that the guidance did not have a material impact on Pepco’s overall financial condition, results of operations, or cash flows, nor does it expect it to in the future.

Consolidation of Variable Interest Entities (ASC 810)

The FASB issued new consolidation guidance regarding variable interest entities effective January 1, 2010 that eliminated the existing quantitative analysis requirement and added new qualitative factors to determine whether consolidation is required. The new qualitative factors are applied on a quarterly basis to interests in variable interest entities. Under the new guidance, the holder of the interest with the power to direct the most significant activities of the entity and the right to receive benefits or absorb losses significant to the entity would consolidate. The new guidance retained the existing provision that allows entities created before December 31, 2003 to be scoped out from a consolidation assessment if exhaustive efforts are taken and there is insufficient information to determine the primary beneficiary.

Pepco has adopted the provisions of the new FASB guidance on consolidation of variable interest entities, and it did not have a material impact on Pepco’s overall financial condition, results of operations, or cash flows.

Fair Value Measurement and Disclosures (ASC 820)

The FASB issued new disclosure requirements for recurring and non-recurring fair value measurements. The guidance, effective for Pepco’s March 31, 2010 financial statements, required the disaggregation of balance sheet items measured at fair value into classes (that is, subsets of balance sheet items) based on the nature and risks of the items. The standard requires description of pricing inputs and valuation methodologies for instruments with Level 2 or 3 valuation inputs. In addition, the standard requires information about any transfers of instruments between Level 1 and 2 valuation categories. These additional disclosures can be found in Note (9), “Fair Value Disclosures.”

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Subsequent Events (ASC 855)

The FASB issued new guidance which eliminates the requirement for Pepco to disclose the date through which it has evaluated subsequent events beginning with its March 31, 2010 financial statements. Pepco has modified its disclosure in Note (2), “Significant Accounting Policies.”

(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Fair Value Measurement and Disclosures (ASC 820)

The new FASB disclosure requirements that will be effective beginning with Pepco’s March 31, 2011 financial statements require that the items within the reconciliation of the Level 3 valuation category be presented in separate categories for purchases, sales, issuances, and settlements, if significant. Pepco is evaluating the impact of this part of the guidance on Pepco’s overall financial statements.

(5) SEGMENT INFORMATION

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

(6) PENSION AND OTHER POSTRETIREMENT BENEFITS

Pepco accounts for its participation in the Pepco Holdings benefit plans as participation in a multi-employer plan. PHI’s pension and other postretirement net periodic benefit cost for the three months ended March 31, 2010 before intercompany allocations from the PHI Service Company, of $29 million, included $7 million for Pepco’s allocated share. 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, included $8 million for Pepco’s allocated share.

(7) DEBT

Credit Facilities

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

At March 31, 2010 and December 31, 2009, the amount of cash plus borrowing capacity under PHI’s $1.5 billion credit facility available to meet the liquidity needs of PHI’s utility subsidiaries was $546 million and $582 million, respectively.

Other Financing Activities

During the three months ended March 31, 2010, the following financing activity occurred:

In March 2010, Pepco redeemed at maturity, $16 million of Prince George’s County 5.75% Pollution Control Revenue Refunding Bonds Series 1995.

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(8) INCOME TAXES

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

	Three Months Ended March  31,
	2010		2009
Federal statutory rate	35.0	%	35.0	%
Increases (decreases) resulting from:
Depreciation	8.6		3.6
Asset removal costs	(3.5	)	(1.8	)
State income taxes, net of federal effect	5.7		5.8
Software amortization	—		1.2
Tax credits	(2.9	)	(1.2	)
Change in estimates and interest related to uncertain and effectively settled tax positions	7.1		1.8
Permanent differences related to deferred compensation funding	(1.4	)	(0.6	)
Other, net	(5.7	)	(1.4	)
Effective Income Tax Rate	42.9	%	42.4	%

Pepco’s effective tax rates for the three months ended March 31, 2010 and 2009 were 42.9% and 42.4% respectively. The increase in the rate primarily resulted from changes in estimates and interest relating to uncertain and effectively settled positions, partially offset by the effect of certain permanent and flow through tax differences as a percentage of pre-tax income.

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

(9) FAIR VALUE DISCLOSURES

Fair Value of Assets and Liabilities Excluding Debt

Pepco has adopted FASB guidance on fair value measurement and disclosures (ASC 820) which established a framework for measuring fair value and expanded disclosures about fair value measurements. As defined in the guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Pepco utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. Accordingly, Pepco utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurement) and the lowest priority to unobservable inputs (level 3 measurement). Pepco classifies its fair value balances in the fair value hierarchy based on the observability of the inputs used in the fair value calculation as follows:

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

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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 data. Level 2 also includes those financial instruments that are valued using internally developed methodologies that have been corroborated by observable market data through correlation or by other means. Significant assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

Executive deferred compensation plan assets and liabilities include life insurance policies that are categorized as level 2 assets because they are priced based on the underlying assets in the policy. The underlying assets of these life insurance contracts consist of short term cash equivalents and fixed income securities that are priced using observable market data. The level 2 liability of the life insurance contract represents deferred compensation obligation, the value of which are tracked via underlying insurance sub-accounts. The sub-accounts are designed to track and mirror existing mutual funds and money market funds that are observable and actively traded.

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

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

The following tables set forth, by level within the fair value hierarchy, Pepco’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2010 and December 31, 2009. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Pepco’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Fair Value Measurements at March 31, 2010
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Executive deferred compensation plan assets
Money Market Funds	$	9	$	9	$	—	$	—
Life Insurance Contracts		55		—		37		18
	$	64	$	9	$	37	$	18
LIABILITIES
Executive deferred compensation plan liabilities
Life Insurance Contracts	$	12	$	—	$	12	$	—
	$	12	$	—	$	12	$	—

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	Fair Value Measurements at December 31, 2009
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Executive deferred compensation plan assets
Money Market Funds	$	9	$	9	$	—	$	—
Life Insurance Contracts		55		—		37		18
	$	64	$	9	$	37	$	18
LIABILITIES
Executive deferred compensation plan liabilities
Life Insurance Contracts	$	13	$	—	$	13	$	—
	$	13	$	—	$	13	$	—

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, 2010 and 2009 are shown below:

	Three Months Ended March 31, 2010
	Life Insurance Contracts
	(millions of dollars)
Beginning balance as of January 1, 2010	$	18
Total gains or (losses) (realized and unrealized)
Included in income		1
Included in accumulated other comprehensive (losses) income		—
Purchases and issuances		(1	)
Settlements		—
Transfers in (out) of Level 3		—
Ending balance as of March 31, 2010	$	18
	Other Operation and Maintenance Expense
	(millions of dollars)
Gains or (losses) (realized and unrealized) included in income for the period above are reported in Other Operation and Maintenance Expense as follows:
Total gains included in income for the period above	$	1
Change in unrealized gains relating to assets still held at reporting date	$	1

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	Three Months Ended March 31, 2009
	Life Insurance Contracts
	(millions of dollars)
Beginning balance as of January 1, 2009	$	17
Total gains or (losses) (realized and unrealized)
Included in income		1
Included in accumulated other comprehensive (losses) income		—
Purchases and issuances		(1	)
Settlements		—
Transfers in (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 income for the period above are reported in Other Operation and Maintenance Expense as follows:
Total gains (losses) included in income for the period above	$	1
Change in unrealized gains (losses) relating to assets still held at reporting date	$	1

Fair Value of Debt Instruments

The estimated fair values of Pepco’s non-derivative financial instruments at March 31, 2010 and December 31, 2009 are shown below:

	March 31, 2010				December 31, 2009
	(millions of dollars)
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	1,539	$	1,685	$	1,555	$	1,707

The methods and assumptions described below were used to estimate, as of March 31, 2010 and December 31, 2009, the fair value of non-derivative financial instruments shown above for which it is practicable to estimate a value.

The fair value of long-term debt issued by Pepco was based on actual trade prices as of March 31, 2010 and December 31, 2009, or bid prices obtained from brokers if actual trade prices were not available.

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

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(10) COMMITMENTS AND CONTINGENCIES

Regulatory and Other Matters

Proceeds from Settlement of Mirant Bankruptcy Claims

In 2007, Pepco received proceeds from the settlement of its Mirant Corporation (Mirant) bankruptcy claims relating to a power purchase agreement between Pepco and Panda-Brandywine L.P. (Panda PPA). In September 2008, Pepco transferred the Panda PPA to an unaffiliated third party, along with a payment to the third party of a portion of the settlement proceeds. In March 2009, the District of Columbia Public Service Commission (DCPSC) approved an allocation between Pepco and its District of Columbia customers of the District of Columbia portion of the Mirant bankruptcy settlement proceeds remaining after the transfer of the Panda PPA. As a result, Pepco recorded a pre-tax gain of $14 million in the first quarter of 2009 reflecting the District of Columbia proceeds retained by Pepco.

On April 20, 2010, the DCPSC issued an order concluding that there are no remaining issues to be resolved in the Mirant bankruptcy proceeding, and requested parties to file requests identifying additional unresolved issues, if any, by April 30, 2010. Because no such requests were received by the deadline, the DCPSC closed the proceeding without further action.

Rate Proceedings

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

District of Columbia

In January 2008, the DCPSC approved, effective in February 2008, a revenue requirement increase for Pepco of approximately $28 million, based on an authorized return on rate base of 7.96%, including a 10% return on equity (ROE). 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 order, which was denied by the DCPSC. In August 2008, the DC OPC filed with the District of Columbia Court of Appeals a petition for review of the DCPSC’s order denying its motion for reconsideration. On February 18, 2010, the Court of Appeals issued a decision affirming the decision of the DCPSC.

In May 2009, Pepco submitted an application to the DCPSC to increase electric distribution base rates. The filing sought approval of an annual rate increase of approximately $50 million with the BSA, based on a requested ROE of 11.25% (subsequently revised by Pepco to approximately $44.5 million, based on a requested ROE of 10.75%). The filing also proposed recovery of pension expenses and uncollectible expenses through a surcharge mechanism, which would have reduced the increase request by approximately $3 million. On March 2, 2010, the DCPSC authorized an electric distribution rate increase of $19.8 million, based on an ROE of 9.625%, effective on March 23, 2010, and denied the proposed surcharge mechanism.

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On March 23, 2010, Pepco filed a request for reconsideration of certain issues decided unfavorably to Pepco, including the level of ROE. On April 1, 2010, the DC OPC and the District of Columbia Water and Sewer Authority also filed separate requests for reconsideration contesting certain issues. On April 22, 2010, the DCPSC issued an order delaying the deadline for ruling on these matters until May 24, 2010.

Maryland

In December 2009, Pepco filed an electric distribution base rate case in Maryland. The filing seeks approval of an annual rate increase of approximately $40 million, based on a requested ROE of 10.75% (revised to approximately $32.2 million in March 2010 to reflect an updated test period). Evidentiary hearings are scheduled to begin in mid-May 2010 and a decision by the Maryland Public Service Commission is expected by the end of July 2010.

District of Columbia Divestiture Case

In June 2000, the DCPSC approved a divestiture settlement under which Pepco is required to share with its District of Columbia customers the net proceeds realized by Pepco from the sale of its generation-related assets. 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, 2010, the District of Columbia allocated portions of EDIT and ADITC associated with the divested generating assets were approximately $6 million each.

Pepco believes that a sharing of EDIT and ADITC with its District of Columbia customers 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. Also, 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, 2010), as well as its District of Columbia jurisdictional transmission and distribution-related ADITC balance ($3 million as of March 31, 2010), 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.

Pepco believes that its calculation of the District of Columbia customers’ share of divestiture proceeds is correct. Nevertheless, if Pepco is required by the DCPSC to share its EDIT and ADITC balances with its District of Columbia customers, the additional gain-sharing payments, along with any required ADITC-related payments to the IRS, could have a material adverse effect on Pepco’s and PHI’s results of operations for periods in which the payments are required to be made. However, neither PHI nor Pepco believes that such payments would have a material adverse impact on its financial position or cash flows.

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General Litigation

In 1993, Pepco was served with Amended Complaints filed in the state Circuit Courts of Prince George’s County, Baltimore City and Baltimore County, Maryland in separate ongoing, consolidated proceedings known as “In re: Personal Injury Asbestos Case.” Pepco and other corporate entities were brought into these cases on a theory of premises liability. Under this theory, the plaintiffs argued that Pepco was negligent in not providing a safe work environment for employees or its contractors, who allegedly were exposed to asbestos while working on Pepco’s property. Initially, a total of approximately 448 individual plaintiffs added Pepco to their complaints. While the pleadings are not entirely clear, it appears that each plaintiff sought $2 million in compensatory damages and $4 million in punitive damages from each defendant.

Since the initial filings in 1993, additional individual suits have been filed against Pepco, and significant numbers of cases have been dismissed. As a result of two motions to dismiss, numerous hearings and meetings and one motion for summary judgment, Pepco has had approximately 400 of these cases successfully dismissed with prejudice, either voluntarily by the plaintiff or by the court. As of March 31, 2010, there are approximately 180 cases still pending against Pepco in the State Courts of Maryland, of which approximately 90 cases were filed after December 19, 2000, and were tendered to Mirant for defense and indemnification 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 condition, results of operations or cash flows. However, if an unfavorable decision were rendered against Pepco, it could have a material adverse effect on Pepco’s and PHI’s financial condition, results of operations and cash flows.

Environmental Litigation

Pepco is subject to regulation by various federal, regional, state, and local authorities with respect to the environmental effects of its operations, including air and water quality control, solid and hazardous waste disposal, and limitations on land use. In addition, federal and state statutes authorize governmental agencies to compel responsible parties to clean up certain abandoned or unremediated hazardous waste sites. Pepco may incur costs to clean up currently or formerly owned facilities or sites found to be contaminated, as well as other facilities or sites that may have been contaminated due to past disposal practices. Although penalties assessed for violations of environmental laws and regulations are not recoverable from Pepco’s customers, environmental clean-up costs incurred by Pepco would be included in its cost of service for ratemaking purposes.

Peck Iron and Metal Site. The U.S. Environmental Protection Agency (EPA) informed Pepco in a May 20, 2009 letter that Pepco may be a potentially responsible party (PRP) under CERCLA with respect to the cleanup of the Peck Iron and Metal site in Portsmouth, Virginia, or for costs EPA has incurred in cleaning up the site. EPA’s letter states that Peck Iron and Metal purchased, processed, stored and shipped metal scrap from military bases, governmental agencies and businesses and that Peck’s metal scrap operations resulted in the improper storage and disposal of hazardous substances. EPA bases its allegation that Pepco arranged for disposal or treatment of hazardous substances sent to the site on information provided by Peck Iron and Metal personnel, who informed the EPA that Pepco was a customer at the site. Pepco has advised the EPA by letter that its records show no evidence of any sale of scrap metal by Pepco to the site. Even if EPA has such records and such sales did occur, Pepco believes that any such scrap metal sales are entitled to the recyclable material exemption from CERCLA liability. At this time Pepco cannot predict how EPA will proceed regarding this matter, or what portion, if any, of the Peck Iron and Metal Site response costs EPA would seek to recover from Pepco. In a notice published on November 4, 2009, EPA placed the Peck Iron and Metal Site on the National Priorities List.

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Ward Transformer Site. In April 2009, a group of PRPs with respect to the Ward Transformer site in Raleigh, North Carolina, filed a complaint in the U.S. District Court for the Eastern District of North Carolina, alleging cost recovery and/or contribution claims against Pepco with respect to past and future response costs incurred by the PRP group in performing a removal action at the site. With the court’s permission, the plaintiffs filed amended complaints on September 1, 2009. Pepco, as part of a group of defendants, filed a motion to dismiss on October 13, 2009. In a March 24, 2010 order, the court denied the defendants’ motion to dismiss. Although it is too early in the process to characterize the magnitude of the potential liability at this site, it does not appear that Pepco had extensive business transactions, if any, with the Ward Transformer site.

District of Columbia Tax Legislation

On December 24, 2009, the Mayor of the District of Columbia approved legislation adopted by the City Council that imposes mandatory combined unitary business reporting effective for tax year 2011, and revises the District’s related party expense disallowance effective for tax year 2009. The legislation was transmitted to Congress on January 5, 2010. In March, the Congressional review period expired without action and the legislation became law. Because the City Council must still write and pass further legislation providing guidance on how to implement unitary reporting before this provision is effective, PHI believes that the legislative process was not complete as of March 31, 2010, and, therefore, the effect of the legislation for combined unitary business tax reporting has not been accounted for as of March 31, 2010.

The legislation does not define the term “unitary business” and does not specify how combined tax reporting would differ from our current consolidated tax reporting in the District of Columbia. However, based upon PHI’s interpretation of combined unitary business tax reporting in other taxing jurisdictions, the legislation would likely result in a change in PHI’s overall state income tax rate and, therefore, would likely require an adjustment to PHI’s net deferred income tax liabilities. Further, to the extent that the change in rate increases net deferred income tax liabilities, PHI must determine if these increased tax liabilities are probable of recovery in future rates. No timetable has been established by the City Council to write and pass further legislation and, therefore, uncertainty exists as to whether combined unitary reporting will be effective for PHI.

Management continues to analyze the impact that the unitary business tax reporting aspect of this legislation, if completed, may have on the financial position, results of operations and cash flows of PHI and its subsidiaries.

(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, 2010 and 2009 were approximately $45 million and $43 million, respectively.

Certain subsidiaries of Pepco Energy Services perform utility maintenance services, including services that are treated as capital costs, for Pepco. Amounts charged to Pepco by these companies for the three months ended March 31, 2010 and 2009 were approximately $1 million and $2 million, respectively.

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As of March 31, 2010 and December 31, 2009, Pepco had the following balances on its balance sheets due to related parties:

	March 31, 2010			December 31, 2009
Asset (Liability)	(millions of dollars)
Payable to Related Party (current) (a)
PHI Parent Company	$	—		$	(8	)
PHI Service Company		(20	)		(3	)
Pepco Energy Services (b)		(73	)		(99	)
Other		—			(1	)
Total	$	(93	)	$	(111	)
Money Pool Balance with Pepco Holdings (included in Cash and cash equivalents)	$	194		$	203
(a)    These amounts are included in the “Accounts payable due to associated companies” balances on the balance sheet. (b)    Pepco bills customers on behalf of Pepco Energy Services where customers have selected Pepco Energy Services as their alternative 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 INCOME

(Unaudited)

	Three Months Ended March  31,
	2010			2009
	(millions of dollars)
Operating Revenue
Electric	$	299		$	321
Natural Gas		95			131
Total Operating Revenue		394			452
Operating Expenses
Purchased energy		201			219
Gas purchased		66			101
Other operation and maintenance		61			59
Depreciation and amortization		20			19
Other taxes		10			10
Total Operating Expenses		358			408
Operating Income		36			44
Other Income (Expenses)
Interest and dividend income		—			—
Interest expense		(10	)		(11	)
Other income		1			—
Total Other Expenses		(9	)		(11	)
Income Before Income Tax Expense		27			33
Income Tax Expense		13			12
Net Income		14			21
Retained Earnings at Beginning of Period		472			448
Dividends Paid to Parent		—			(28	)
Retained Earnings at End of Period	$	486		$	441

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

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DELMARVA POWER & LIGHT COMPANY

BALANCE SHEETS

(Unaudited)

	March 31, 2010			December 31, 2009
	(millions of dollars)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	24		$	26
Accounts receivable, less allowance for uncollectible accounts of $14 million and $12 million, respectively		191			193
Inventories		35			40
Prepayments of income taxes		54			64
Prepaid expenses and other		16			19
Total Current Assets		320			342
INVESTMENTS AND OTHER ASSETS
Goodwill		8			8
Regulatory assets		220			207
Prepaid pension expense		155			157
Other		31			28
Total Investments and Other Assets		414			400
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		2,846			2,807
Accumulated depreciation		(872	)		(860	)
Net Property, Plant and Equipment		1,974			1,947
TOTAL ASSETS	$	2,708		$	2,689

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

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DELMARVA POWER & LIGHT COMPANY

BALANCE SHEETS

(Unaudited)

	March 31, 2010		December 31, 2009
	(millions of dollars, except shares)
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Short-term debt	$	105	$	105
Current portion of long-term debt		31		31
Accounts payable and accrued liabilities		76		106
Accounts payable due to associated companies		24		14
Taxes accrued		4		3
Interest accrued		13		6
Derivative liabilities		21		15
Other		64		64
Total Current Liabilities		338		344
DEFERRED CREDITS
Regulatory liabilities		302		290
Deferred income taxes, net		490		489
Investment tax credits		7		7
Other postretirement benefit obligation		24		23
Above-market purchased energy contracts and other electric restructuring liabilities		17		17
Liabilities and accrued interest related to uncertain tax positions		19		20
Derivative liabilities		12		13
Other		22		23
Total Deferred Credits		893		882
LONG-TERM LIABILITIES
Long-term debt		655		655
COMMITMENTS AND CONTINGENCIES (NOTE 12)
EQUITY
Common stock, $2.25 par value, 1,000 shares authorized, 1,000 shares outstanding		—		—
Premium on stock and other capital contributions		336		336
Retained earnings		486		472
Total Equity		822		808
TOTAL LIABILITIES AND EQUITY	$	2,708	$	2,689

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

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DELMARVA POWER & LIGHT COMPANY

STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
	2010			2009
	(millions of dollars)
OPERATING ACTIVITIES
Net income	$	14		$	21
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		20			19
Deferred income taxes		—			12
Changes in:
Accounts receivable		2			(12	)
Inventories		5			16
Regulatory assets and liabilities, net		13			35
Accounts payable and accrued liabilities		(25	)		(35	)
Taxes accrued		12			(2	)
Interest accrued		7			7
Other assets and liabilities		5			5
Net Cash From Operating Activities		53			66
INVESTING ACTIVITIES
Investment in property, plant and equipment		(48	)		(37	)
Net other investing activities		(1	)		—
Net Cash Used By Investing Activities		(49	)		(37	)
FINANCING ACTIVITIES
Dividends paid to Parent		—			(28	)
Net other financing activities		(6	)		(2	)
Net Cash Used By Financing Activities		(6	)		(30	)
Net Decrease in Cash and Cash Equivalents		(2	)		(1	)
Cash and Cash Equivalents at Beginning of Period		26			138
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	24		$	137
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash (received) paid for income taxes (includes payments to PHI for Federal income taxes)	$	(1	)	$	5

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

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NOTES TO FINANCIAL STATEMENTS

DELMARVA POWER & LIGHT COMPANY

(1) ORGANIZATION

Delmarva Power & Light Company (DPL) is engaged in the transmission and distribution of electricity in Delaware and portions of Maryland and provides gas distribution service in northern Delaware. Additionally, DPL provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its territories who do not elect to purchase electricity from a competitive supplier, in both Delaware and Maryland. Default Electricity Supply is known as Standard Offer Service in both Delaware and Maryland. DPL is a wholly owned subsidiary of Conectiv, which is wholly owned by Pepco Holdings, Inc. (Pepco Holdings or PHI).

(2) SIGNIFICANT ACCOUNTING POLICIES

Financial Statement Presentation

DPL’s unaudited financial statements are prepared in conformity with accounting principles generally accepted in the United States of America (GAAP). Pursuant to the rules and regulations of the Securities and Exchange Commission, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been omitted. Therefore, these financial statements should be read along with the annual financial statements included in DPL’s Annual Report on Form 10-K for the year ended December 31, 2009. 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, 2010, 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, 2010 may not be indicative of results that will be realized for the full year ending December 31, 2010 since the sales of electric energy are seasonal.

Use of Estimates

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

Significant matters that involve the use of estimates include the assessment of contingencies, the calculation of future cash flows and fair value amounts for use in asset impairment evaluations, fair value calculations (based on estimated market pricing) associated with derivative instruments, pension and other postretirement benefits assumptions, unbilled revenue calculations, the assessment of the probability of recovery of regulatory assets, estimation of storm restoration accruals, and income tax provisions and reserves. Additionally, DPL is subject to legal, regulatory, and other proceedings and claims that arise in the ordinary course of its business. DPL records an estimated liability for these proceedings and claims when the loss is determined to be probable and is reasonably estimable.

During the first quarter of 2010, DPL incurred significant costs associated with the February 2010 severe winter storms that affected its service territories. The total costs of the restoration efforts have been estimated at $6 million with $4 million charged to Other Operation and Maintenance expense for repair work and $2 million recorded as capital expenditures. A large portion of the costs of the restoration work relate to services provided by outside contractors and other utilities, and billings for such services in most instances have not yet been received and have been estimated. Actual billings may vary significantly from the estimates of such billings.

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DPL Wind Transactions

DPL has entered into four wind power purchase agreements (PPAs) in amounts up to a total of 350 megawatts. Three of the PPAs are with land-based facilities and one of the PPAs is with an offshore facility. As the facilities are completed and become operational, DPL is obligated to purchase energy and renewable energy credits (RECs) from the four wind facilities and capacity from one of the wind facilities. The RECs help DPL fulfill 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 the four agreements, each of which sets forth the prices to be paid by DPL over the life of the contract, and has approved the recovery of DPL’s purchase costs through customer rates.

One of the land-based wind facilities became operational and went into service in December 2009. DPL is obligated to purchase energy and RECs from this facility over 15 years in amounts generated and delivered not to exceed 50.25 megawatts at rates that are fixed. Payments under the other agreements are currently expected to start in the fourth quarter of 2010 for the other two land-based contracts and 2014 for the offshore contract, if the projects are ultimately completed and operational.

The terms of the agreements with wind facilities that are not yet operational range between 20 and 25 years. When they become operational, DPL is obligated to purchase energy and RECs in amounts generated and delivered by the sellers at rates that are primarily fixed under these agreements. Under one of the agreements, DPL is also obligated to purchase the capacity associated with the facility at rates that are generally fixed. The inability of the offshore wind facility developer to obtain all necessary permits and financing commitments could result in setbacks in the construction schedules and the operational start dates of the offshore wind facility. If the wind facilities are not operational by specified dates, DPL has the right to terminate the PPAs.

DPL concluded that consolidation is not required for any of these PPAs under Financial Accounting Standards Board (FASB) guidance on the consolidation of variable interest entities (Accounting Standards Codification (ASC) 810).

Goodwill

Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired at the acquisition date. All of DPL’s goodwill was generated by DPL’s acquisition of Conowingo Power Company in 1995. DPL tests its goodwill for impairment annually and whenever an event occurs or circumstances change in the interim that would more likely than not reduce the fair value of DPL below its carrying amount. DPL performs its annual impairment test on November 1. Factors that may result in an interim impairment test include, but are not limited to: a change in the identified reporting units; an adverse change in business conditions; an adverse regulatory action; or an impairment of DPL’s long-lived assets. As described in Note (6), “Goodwill,” DPL concluded that an interim impairment test was not required during the three month period ending March 31, 2010.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in DPL’s gross revenues were $5 million for each of the three months ended March 31, 2010 and 2009.

Reclassifications and Adjustments

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

The following adjustment has been recorded which is not considered material:

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 was also recorded in the first quarter of 2009. Consequently there was no impact on net income as a result of this adjustment.

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(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Transfers and Servicing (ASC 860)

The FASB issued new guidance that removes the concept of a qualifying special-purpose entity (QSPE) from the current guidance on transfers and servicing and the QSPE scope exception in current guidance on consolidation. The new guidance also changed the requirements for derecognizing financial assets and requires additional disclosures about a transferor’s continuing involvement in transferred financial assets.

The guidance was effective for transfers of financial assets occurring in fiscal periods beginning on January 1, 2010 for DPL. As of January 1, 2010, DPL has adopted the provisions of this guidance and determined that the guidance did not have a material impact on DPL’s overall financial condition, results of operations, or cash flows, nor does it expect it to in the future.

Consolidation of Variable Interest Entities (ASC 810)

The FASB issued new consolidation guidance regarding variable interest entities effective January 1, 2010 that eliminated the existing quantitative analysis requirement and added new qualitative factors to determine whether consolidation is required. The new qualitative factors are applied on a quarterly basis to interests in variable interest entities. Under the new guidance, the holder of the interest with the power to direct the most significant activities of the entity and the right to receive benefits or absorb losses significant to the entity would consolidate. The new guidance retained the existing provision that allows entities created before December 31, 2003 to be scoped out from a consolidation assessment if exhaustive efforts are taken and there is insufficient information to determine the primary beneficiary.

DPL has adopted the provisions of the new FASB guidance on consolidation of variable interest entities, and it did not have a material impact on DPL’s overall financial condition, results of operations, or cash flows.

Fair Value Measurement and Disclosures (ASC 820)

The FASB issued new disclosure requirements for recurring and non-recurring fair value measurements. The guidance, effective for DPL’s March 31, 2010 financial statements, required the disaggregation of balance sheet items measured at fair value into classes (that is, subsets of balance sheet items) based on the nature and risks of the items. The standard requires description of pricing inputs and valuation methodologies for instruments with Level 2 or 3 valuation inputs. In addition, the standard requires information about any transfers of instruments between Level 1 and 2 valuation categories. These additional disclosures can be found in Note (11), “Fair Value Disclosures.”

Subsequent Events (ASC 855)

The FASB issued new guidance which eliminates the requirement for DPL to disclose the date through which it has evaluated subsequent events beginning with its March 31, 2010 financial statements. DPL has modified its disclosure in Note (2), “Significant Accounting Policies.”

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(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Fair Value Measurement and Disclosures (ASC 820)

The new FASB disclosure requirements that will be effective beginning with DPL’s March 31, 2011 financial statements require that the items within the reconciliation of the Level 3 valuation category be presented in separate categories for purchases, sales, issuances, and settlements, if significant. DPL is evaluating the impact of this part of the guidance on DPL’s overall financial statements.

(5) SEGMENT INFORMATION

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

(6) GOODWILL

DPL’s goodwill balance of $8 million was unchanged during the three month period ending March 31, 2010. All of DPL’s goodwill was generated by its acquisition of Conowingo Power Company in 1995.

DPL’s annual impairment tests as of July 1, 2009 and November 1, 2009 indicated that goodwill was not impaired. As of March 31, 2010, after review of its significant assumptions in the goodwill impairment analysis, DPL concluded that there were no events requiring it to perform an interim goodwill impairment test. DPL will continue to closely monitor for indicators of 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, 2010 before intercompany allocations from the PHI Service Company, of $29 million, included $4 million for DPL’s allocated share. 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, included $5 million for DPL’s allocated share.

(8) DEBT

Credit Facilities

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.

At March 31, 2010 and December 31, 2009, the amount of cash plus borrowing capacity under PHI’s $1.5 billion credit facility available to meet the liquidity needs of PHI’s utility subsidiaries was $546 million and $582 million, respectively.

Financing Activity Subsequent to March 31, 2010

In April 2010, DPL completed a tax-exempt bond financing in which The Delaware Economic Development Authority (DEDA) issued and sold $78.4 million of its Gas Facilities Refunding Revenue Bonds, Series 2010, due February 1, 2031. The proceeds from the issuance of the bonds were loaned by DEDA to DPL pursuant to a loan agreement, dated as of April 1, 2010, between DEDA and DPL. The payment obligations under the loan agreement correspond to the payments of principal, premium, if any, and interest when and as due on the bonds. The bonds bear interest at the fixed rate of 5.40% per annum, payable each February 1 and August 1, commencing August 1, 2010. Beginning on August 1, 2020, the bonds are subject to optional redemption at the direction of DPL, in whole or in part, at a redemption price equal to the principal amount thereof, plus accrued interest, if any, to the redemption date.

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DPL used the proceeds of the bonds to effect the redemption of all outstanding amounts of the following series of tax-exempt bonds previously issued by DEDA for the benefit of DPL (such bonds collectively are referred to as the Prior Bonds):

• $11.15 million of Exempt Facilities Refunding Revenue Bonds (Delmarva Power & Light Company Project) Series 2000A;

• $27.75 million of Exempt Facilities Refunding Revenue Bonds (Delmarva Power & Light Company Project) Series 2000B;

• $20 million of Exempt Facilities Refunding Revenue Bonds (Delmarva Power & Light Company Project) Series 2001A;

• $4.5 million of Exempt Facilities Refunding Revenue Bonds (Delmarva Power & Light Company Project) Series 2001B; and

• $15 million of Exempt Facilities Refunding Revenue Bonds (Delmarva Power & Light Company Project) Series 2002A.

The Prior Bonds were repurchased by DPL in 2008 in response to the 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 from the redemption of the Prior Bonds, which it intends to use for general corporate purposes.

(9) INCOME TAXES

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

	Three Months Ended March  31,
	2010		2009
Federal statutory rate	35.0	%	35.0	%
Increases (decreases) resulting from:
Depreciation	0.7		1.2
State income taxes, net of federal effect	5.2		5.5
Tax credits	(0.7	)	(0.6	)
Change in estimates and interest related to uncertain and effectively settled tax positions	7.4		(3.6	)
Other, net	0.6		(1.1	)
Effective Income Tax Rate	48.2	%	36.4	%

DPL’s effective tax rates for the three months ended March 31, 2010 and 2009 were 48.2 % and 36.4%, respectively. The increase in the rate primarily resulted from an increase in changes in estimates and interest related to uncertain and effectively settled tax positions, primarily related to a $2 million reversal of accrued interest income on state income tax positions that DPL no longer believes is more likely than not to be realized.

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

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 uses derivative instruments in the form of forward contracts, futures, swaps, and exchange-traded and over-the-counter options primarily to reduce gas commodity price volatility and limit its customers’ exposure to increases in the market price of gas. DPL also manages commodity risk with physical natural gas and capacity contracts that are not classified as derivatives. All premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all gains and losses related to hedging activities, are deferred under FASB guidance on regulated operations (ASC 980) until recovered based on the fuel adjustment clause approved by the DPSC.

The table below identifies the balance sheet location and fair values of derivative instruments as of March 31, 2010 and December 31, 2009:

	As of March 31, 2010
Balance Sheet Caption	Derivatives Designated as Hedging Instruments			Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting		Net Derivative Instruments
	(millions of dollars)
Derivative Assets (current assets)	$	—		$	—		$	—		$	—	$	—
Derivative Assets (non-current assets)		—			—			—			—		—
Total Derivative Assets		—			—			—			—		—
Derivative Liabilities (current liabilities)		(15	)		(23	)		(38	)		17		(21	)
Derivative Liabilities (non-current liabilities)		—			(14	)		(14	)		2		(12	)
Total Derivative Liabilities		(15	)		(37	)		(52	)		19		(33	)
Net Derivative (Liability) Asset	$	(15	)	$	(37	)	$	(52	)	$	19	$	(33	)

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	As of December 31, 2009
Balance Sheet Caption	Derivatives Designated as Hedging Instruments			Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting		Net Derivative Instruments
	(millions of dollars)
Derivative Assets (current assets)	$	—		$	—		$	—		$	—	$	—
Derivative Assets (non-current assets)		—			—			—			—		—
Total Derivative Assets		—			—			—			—		—
Derivative Liabilities (current liabilities)		(10	)		(15	)		(25	)		10		(15	)
Derivative Liabilities (non-current liabilities)		—			(14	)		(14	)		1		(13	)
Total Derivative Liabilities		(10	)		(29	)		(39	)		11		(28	)
Net Derivative (Liability) Asset	$	(10	)	$	(29	)	$	(39	)	$	11	$	(28	)

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

	March 31, 2010		December 31, 2009
	(millions of dollars)
Cash collateral pledged to counterparties with the right to reclaim	$	19	$	11

As of March 31, 2010 and December 31, 2009, DPL 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 of DPL’s gains and losses related to hedging activities, are deferred under FASB guidance on regulated operations until recovered based on the fuel adjustment clause approved by the DPSC. The following table indicates the amounts deferred as regulatory assets or liabilities and the location in the statements of income of amounts reclassified to income through the fuel adjustment clause for the three months ended March 31, 2010 and 2009:

	Three Months Ended March  31,
	2010			2009
	(millions of dollars)
Net Loss Deferred as a Regulatory Asset or Liability	$	(5	)	$	—
Net Loss Reclassified from Regulatory Asset or Liability to Purchased Energy or Gas Purchased		(2	)		(16	)

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As of March 31, 2010 and December 31, 2009, DPL had the following outstanding commodity forward contracts that were entered into to hedge forecasted transactions:

	Quantities
Commodity	March 31, 2010	December 31, 2009
Forecasted Purchases Hedges:
Natural Gas (One Million British Thermal Units (MMBtu))	4,957,500	5,695,000

Other Derivative Activity

DPL holds certain derivatives that do not qualify as hedges. Under FASB guidance on derivatives and hedging, these derivatives are recorded at fair value on the balance sheet with the gain or loss recorded in income. In accordance with FASB guidance on regulatory operations, offsetting regulatory assets or regulatory liabilities are recorded on the balance sheet and the recognition of the gain or recovery of the loss is deferred. For the three months ended March 31, 2010 and 2009 the amount of the derivative loss recognized by line item in the statements of income is provided in the table below:

	Three Months Ended March  31,
	2010			2009
	(millions of dollars)
Net Loss Deferred as a Regulatory Asset or Liability	$	(6	)	$	(14	)
Net Loss Reclassified from Regulatory Asset or Liability to Purchased Energy or Gas Purchased		(7	)		(3	)

As of March 31, 2010 and December 31, 2009, DPL had the following net outstanding natural gas commodity forward contracts that did not qualify for hedge accounting:

	March 31, 2010		December 31, 2009
Commodity	Quantity	Net Position	Quantity	Net Position
Natural Gas (MMBtu)	11,468,875	Long	10,442,546	Long

Contingent Credit Risk Features

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

The collateral requirements under the ISDA or similar agreements generally work as follows. The parties establish a dollar threshold of unsecured credit for each party in excess of which the party would be required to post collateral to secure its obligations to the other party. The amount of the unsecured credit threshold varies according to the senior, unsecured debt rating of the respective parties or that of a guarantor of the party’s obligations. The fair values of all transactions between the parties are netted under the master netting provisions. Transactions may include derivatives accounted for on-balance sheet as well as normal purchases and normal sales that are accounted for off-balance sheet. If the aggregate fair value of the transactions in a net loss position exceeds the unsecured credit threshold, then collateral is required

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to be posted in an amount equal to the amount by which the unsecured credit threshold is exceeded. The obligations of DPL are stand-alone obligations without the guaranty of PHI. If DPL’s credit rating were to fall below “investment grade,” the unsecured credit threshold would typically be zero and collateral would be required for the entire net loss position. Exchange-traded contracts are required to be fully collateralized without regard to the credit rating of the holder.

The gross fair value of DPL’s derivative liabilities, excluding the impact of offsetting transactions or collateral under master netting agreements, with credit-risk-related contingent features on March 31, 2010 and December 31, 2009, was $38 million and $28 million, respectively. As of those dates, DPL had posted cash collateral of $4 million and less than a million dollars, respectively, in the normal course of business against the gross derivative liability resulting in a net liability of $34 million and $28 million, respectively, before giving effect to offsetting transactions that are encompassed within master netting agreements that would reduce this amount. DPL’s net settlement amount in the event of a downgrade of DPL below “investment grade” as of March 31, 2010 and December 31, 2009, would have been approximately $26 million and $24 million respectively, after taking into account the master netting agreements.

DPL’s primary source for posting cash collateral or letters of credit are PHI’s credit facilities. At March 31, 2010 and December 31, 2009, the aggregate amount of cash plus borrowing capacity under PHI credit facilities available to meet the liquidity needs of PHI’s utility subsidiaries was $546 million and $582 million, respectively.

(11) FAIR VALUE DISCLOSURES

Fair Value of Assets and Liabilities Excluding Debt

DPL has adopted FASB guidance on fair value measurement and disclosures (ASC 820) which established a framework for measuring fair value and expanded disclosures about fair value measurements. As defined in the guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). DPL utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. Accordingly, DPL utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurement) and the lowest priority to unobservable inputs (level 3 measurement). DPL classifies its fair value balances in the fair value hierarchy based on the observability of the inputs used in the fair value calculation as follows:

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

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

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Executive deferred compensation plan assets and liabilities include life insurance policies that are categorized as level 2 assets because they are priced based on the underlying assets in the policy. The underlying assets of these life insurance contracts consist of short term cash equivalents and fixed income securities that are priced using observable market data. The level 2 liability of the life insurance contract represents deferred compensation obligation, the value of which are tracked via underlying insurance sub-accounts. The sub-accounts are designed to track and mirror existing mutual funds and money market funds that are observable and actively traded.

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

Derivative instruments categorized as level 3 that are derivative liabilities include natural gas options purchased by DPL as part of a natural gas hedging program approved by the DPSC. Some non-standard assumptions are used in their forward valuation to adjust for the pricing; otherwise, most of the options follow NYMEX valuation. A few of the options have no significant NYMEX components, and have to be priced using internal volatility assumptions.

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

The following tables set forth, by level within the fair value hierarchy, DPL’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2010 and December 31, 2009. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. DPL’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Fair Value Measurements at March 31, 2010
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Cash equivalents
Treasury Fund	$	17	$	17	$	—	$	—
Executive deferred compensation plan assets
Money Market Funds		3		3		—		—
Life Insurance Contracts		1		—		—		1
	$	21	$	20	$	—	$	1
LIABILITIES
Derivative instruments
Natural Gas (a)	$	52	$	15	$	—	$	37
	$	52	$	15	$	—	$	37

(a) Represents natural gas options purchased by DPL as part of a natural gas hedging program approved by the DPSC.

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	Fair Value Measurements at December 31, 2009
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Cash equivalents
Treasury Fund	$	19	$	19	$	—	$	—
Executive deferred compensation plan assets
Money Market Funds		3		3		—		—
Life Insurance Contracts		1		—		—		1
	$	23	$	22	$	—	$	1
LIABILITIES
Derivative instruments
Natural Gas (a)	$	39	$	10	$	—	$	29
Executive deferred compensation plan liabilities
Life Insurance Contracts		1		—		1		—
	$	40	$	10	$	1	$	29

(a) Represents natural gas options purchased by DPL as part of a natural gas hedging program approved by the DPSC.

Reconciliations of the beginning and ending balances of DPL’s fair value measurements using significant unobservable inputs (Level 3) for the three months ended March 31, 2010 and 2009 are shown below:

	Three Months Ended March 31, 2010
	Natural Gas			Life Insurance Contracts
	(millions of dollars)
Beginning balance as of January 1, 2010	$	(29	)	$	1
Total gains or (losses) (realized and unrealized)
Included in income		—			—
Included in accumulated other comprehensive (loss) income		—			—
Included in regulatory liabilities		(12	)		—
Purchases and issuances		—			—
Settlements		4			—
Transfers in (out) of Level 3		—			—
Ending balance as of March 31, 2010	$	(37	)	$	1
				Other Operation and Maintenance Expense
				(millions of dollars)
Gains or (losses) (realized and unrealized) included in income for the period above are reported in Other Operation and Maintenance Expense as follows:
Total losses included in income for the period above				$	—
Change in unrealized gains relating to assets still held at reporting date				$	—

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	Three Months Ended March 31, 2009
	Natural Gas			Life Insurance Contracts
	(millions of dollars)
Beginning balance as of January 1, 2009	$	(24	)	$	1
Total gains or (losses) (realized and unrealized)
Included in income		—			—
Included in accumulated other comprehensive (loss) income		—			—
Included in regulatory liabilities		(17	)		—
Purchases and issuances		—			—
Settlements		3			—
Transfers in (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 income for the period above are reported in Other Operation and Maintenance Expense as follows:
Total gains (losses) included in income for the period above				$	—
Change in unrealized gains (losses) relating to assets still held at reporting date				$	—

Fair Value of Debt Instruments

The estimated fair values of DPL’s non-derivative financial instruments at March 31, 2010 and December 31, 2009 are shown below:

	March 31, 2010				December 31, 2009
	(millions of dollars)
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	686	$	739	$	686	$	733

The methods and assumptions described below were used to estimate, as of March 31, 2010 and December 31, 2009, the fair value of non-derivative financial instruments shown above for which it is practicable to estimate a value.

The fair value of long-term debt issued by DPL was based on actual trade prices as of March 31, 2010 and December 31, 2009, or bid prices obtained from brokers if actual trade prices were not available.

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

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(12) COMMITMENTS AND CONTINGENCIES

Regulatory and Other Matters

Rate Proceedings

In recent electric service distribution base rate cases, DPL has proposed the adoption of revenue decoupling methods for retail customers. To date:

• A bill stabilization adjustment mechanism (BSA) has been approved and implemented for electric service in Maryland.

• A modified fixed variable rate design (MFVRD) has been approved in concept for electric service in Delaware and a settlement among the parties to the ongoing base rate proceeding (as described below) has been submitted to the DPSC, which provides for the implementation of the MFVRD after the conclusion of DPL’s pending electric base rate case (under Delaware law, the MFVRD must be in place by December 31, 2010).

• An MFVRD has been approved in concept for natural gas service in Delaware and may be implemented either in the context of a pending decoupling case or DPL’s next Delaware natural gas distribution base rate case (under Delaware law, the MFVRD must be in place by December 31, 2010).

Under the BSA, customer delivery rates are subject to adjustment (through a credit or surcharge mechanism), depending on whether actual distribution revenue per customer exceeds or falls short of the revenue-per-customer amount approved by the applicable public service commission. The BSA increases rates if actual distribution revenues fall below the approved level and decreases rates if actual distribution revenues are above the approved level. The result is that, over time, DPL collects its authorized revenues for distribution deliveries. As a consequence, a BSA “decouples” distribution revenue from unit sales consumption and ties the growth in distribution revenues to the growth in the number of customers. Some advantages of the BSA are that it (i) eliminates revenue fluctuations due to weather and changes in customer usage patterns and, therefore, provides for more predictable distribution revenues that are better aligned with costs, (ii) provides for more reliable fixed-cost recovery, (iii) tends to stabilize customers’ delivery bills, and (iv) removes any disincentives for DPL to promote energy efficiency programs for its customers, because it breaks the link between overall sales volumes and distribution revenues. The MFVRD adopted in Delaware provides for a fixed customer charge (i.e., not tied to the customer’s volumetric consumption) to recover the utility’s fixed costs, plus a reasonable rate of return. Although different from the BSA, DPL views the MFVRD as an appropriate distribution revenue decoupling mechanism.

Delaware

In August 2009, DPL submitted its 2009 GCR filing, which permits DPL to recover gas procurement costs through customer rates, to the DPSC. The filing requested a 10.2% decrease in the level of GCR, to become effective on a temporary basis on November 1, 2009. This rate proposal was approved by the DPSC on September 9, 2009, subject to refund and pending final DPSC approval.

In September 2009, DPL submitted an application with the DPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $28 million (subsequently lowered to approximately $26.2 million), assuming approval of the implementation of the MFVRD, based on a requested return on equity (ROE) of 10.75%. DPL placed an increase of approximately $2.5 million annually into effect on a temporary basis in November 2009, subject to refund and pending final DPSC approval of the entirety of the requested increase. As permitted by Delaware law, DPL placed the remaining $23.7 million of the requested increase into effect on April 19, 2010, subject to refund and pending the final DPSC order. On April 16, 2010, all of the parties to the proceeding, including DPL, the DPSC staff, the Division of the Public Advocate, the Delaware Department of Natural Resources and Environmental Control, and the Delaware Energy Users Group, which represents large industrial

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consumers of electricity, signed a settlement agreement regarding implementation of the MFVRD. The settlement agreement, which has been submitted to the Hearing Examiner, provides for implementation of the MFVRD after the conclusion of this proceeding (under Delaware law, the MFVRD must be in place by December 31, 2010). Hearings on the unresolved issues in the case were begun in April 2010. Due to the unavailability of a key witness, the remainder of the hearings was postponed and it is expected that they will be concluded by the end of May 2010. A DPSC decision is expected in the third quarter of 2010.

In June 2009, DPL filed an application requesting approval for the implementation of the MFVRD for gas distribution rates. On August 4, 2009, the DPSC issued an order opening a docket for the matter. Under Delaware law, the MFVRD must be in place by December 31, 2010.

Maryland

In May 2009, DPL filed an electric distribution base rate case in Maryland. The filing sought approval of an annual rate increase of approximately $14 million, based on a requested ROE of 11.25%. The filing also proposed recovery of pension expenses, other postretirement benefits (OPEB) and uncollectible expenses through a surcharge mechanism, which would have reduced the increase request by approximately $4 million. In December 2009, the Maryland Public Service Commission approved an annual increase of approximately $7.5 million, based on an overall rate of return of 7.96%, including an ROE of 10% and denied the proposed surcharge mechanism for pension, OPEB and uncollectible expenses. The rate increase was implemented through rates that are effective for electric usage on and after December 2, 2009.

Environmental Litigation

DPL is subject to regulation by various federal, regional, state, and local authorities with respect to the environmental effects of its operations, including air and water quality control, solid and hazardous waste disposal, and limitations on land use. In addition, federal and state statutes authorize governmental agencies to compel responsible parties to clean up certain abandoned or unremediated hazardous waste sites. DPL may incur costs to clean up currently or formerly owned facilities or sites found to be contaminated, as well as other facilities or sites that may have been contaminated due to past disposal practices. Although penalties assessed for violations of environmental laws and regulations are not recoverable from DPL’s customers, environmental clean-up costs incurred by DPL would be included in its cost of service for ratemaking purposes.

Ward Transformer Site. In April 2009, a group of potentially responsible parties (PRPs) with respect to the Ward Transformer site in Raleigh, North Carolina, filed a complaint in the U.S. District Court for the Eastern District of North Carolina, alleging cost recovery and/or contribution claims against DPL with respect to past and future response costs incurred by the PRP group in performing a removal action at the site. With the court’s permission, the plaintiffs filed amended complaints on September 1, 2009. DPL, as part of a group of defendants, filed a motion to dismiss on October 13, 2009. In a March 24, 2010 order, the court denied the defendants’ motion to dismiss. Although it is too early in the process to characterize the magnitude of the potential liability at this site, it does not appear that DPL had extensive business transactions, if any, with the Ward Transformer site.

(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, 2010 and 2009 were $34 million and $32 million, respectively.

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In addition to the PHI Service Company charges described above, DPL’s financial statements include the following related party transactions in its statements of income:

	Three Months Ended March  31,
Income (Expense)	2010			2009
	(millions of dollars)
Purchased power under Default Electricity Supply contracts with Conectiv Energy Supply, Inc. (a)	$	(19	)	$	(37	)
Intercompany lease transactions (b)		2			2

(a) Included in purchased energy expense.

(b) Included in electric revenue.

As of March 31, 2010 and December 31, 2009, DPL had the following balances on its balance sheets due to related parties:

Asset (Liability)	March 31, 2010			December 31, 2009
	(millions of dollars)
Receivable from (Payable to) Related Party (current) (a)
PHI Service Company	$	(16	)	$	22
PHI Parent Company		(1	)		(27	)
Conectiv Energy Supply, Inc.		(5	)		(7	)
Pepco Energy Services, Inc. and its subsidiaries (Pepco Energy Services) (b)		(3	)		(3	)
Other		1			1
Total	$	(24	)	$	(14	)

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

(b) 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 INCOME

(Unaudited)

	Three Months Ended March  31,
	2010			2009
	(millions of dollars)
Operating Revenue	$	317		$	344
Operating Expenses
Purchased energy		235			277
Other operation and maintenance		50			48
Depreciation and amortization		24			25
Other taxes		6			5
Deferred electric service costs		(19	)		(27	)
Total Operating Expenses		296			328
Operating Income		21			16
Other Income (Expenses)
Interest expense		(16	)		(17	)
Other income		—			1
Total Other Expenses		(16	)		(16	)
Income Before Income Tax Expense (Benefit)		5			—
Income Tax Expense (Benefit)		7			(2	)
Net (Loss) Income		(2	)		2
Retained Earnings at Beginning of Period		143			166
Dividends Paid to Parent		—			(24	)
Retained Earnings at End of Period	$	141		$	144

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, 2010			December 31, 2009
	(millions of dollars)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	4		$	7
Restricted cash equivalents		10			10
Accounts receivable, less allowance for uncollectible accounts of $8 million and $7 million, respectively		161			176
Inventories		17			15
Prepayments of income taxes		38			38
Prepaid expenses and other		7			12
Total Current Assets		237			258
INVESTMENTS AND OTHER ASSETS
Regulatory assets		705			712
Prepaid pension expense		61			63
Income taxes receivable		71			76
Restricted cash equivalents		3			4
Assets and accrued interest related to uncertain tax positions		59			57
Other		12			9
Total Investments and Other Assets		911			921
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		2,358			2,328
Accumulated depreciation		(707	)		(699	)
Net Property, Plant and Equipment		1,651			1,629
TOTAL ASSETS	$	2,799		$	2,808

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

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ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31, 2010		December 31, 2009
	(millions of dollars, except shares)
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Short-term debt	$	114	$	83
Current portion of long-term debt		35		35
Accounts payable and accrued liabilities		104		120
Accounts payable due to associated companies		25		58
Taxes accrued		16		5
Interest accrued		17		13
Other		41		42
Total Current Liabilities		352		356
DEFERRED CREDITS
Regulatory liabilities		157		178
Deferred income taxes, net		608		604
Investment tax credits		9		9
Other postretirement benefit obligation		26		25
Other		10		11
Total Deferred Credits		810		827
LONG-TERM LIABILITIES
Long-term debt		632		609
Transition Bonds issued by ACE Funding		359		368
Total Long-Term Liabilities		991		977
COMMITMENTS AND CONTINGENCIES (NOTE 10)
REDEEMABLE SERIAL PREFERRED STOCK		6		6
EQUITY
Common stock, $3.00 par value, 25,000,000 shares authorized, 8,546,017 shares outstanding		26		26
Premium on stock and other capital contributions		473		473
Retained earnings		141		143
Total Equity		640		642
TOTAL LIABILITIES AND EQUITY	$	2,799	$	2,808

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

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ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
	2010			2009
	(millions of dollars)
OPERATING ACTIVITIES
Net (loss) income	$	(2	)	$	2
Adjustments to reconcile net (loss) income to net cash from operating activities:
Depreciation and amortization		24			25
Deferred income taxes		3			21
Changes in:
Accounts receivable		15			20
Inventories		(2	)		—
Regulatory assets and liabilities, net		(22	)		(41	)
Accounts payable and accrued liabilities		(49	)		(13	)
Taxes accrued		15			(2	)
Interest accrued		4			3
Other assets and liabilities		4			4
Net Cash (Used By) From Operating Activities		(10	)		19
INVESTING ACTIVITIES
Investment in property, plant and equipment		(38	)		(28	)
Changes in restricted cash equivalents		1			—
Net Cash Used By Investing Activities		(37	)		(28	)
FINANCING ACTIVITIES
Dividends paid to Parent		—			(24	)
Issuances of long-term debt		23			—
Reacquisition of long-term debt		(8	)		(8	)
Issuances of short-term debt, net		31			—
Net other financing activities		(2	)		(3	)
Net Cash From (Used by) Financing Activities		44			(35	)
Net Decrease in Cash and Cash Equivalents		(3	)		(44	)
Cash and Cash Equivalents at Beginning of Period		7			65
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	4		$	21
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash received for income taxes (includes payments to PHI for Federal income taxes)	$	—		$	13

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ATLANTIC CITY ELECTRIC COMPANY

(1) ORGANIZATION

Atlantic City Electric Company (ACE) is engaged in the transmission and distribution of electricity in southern New Jersey. ACE also provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its service territory who do not elect to purchase electricity from a competitive supplier. Default Electricity Supply is also known as Basic Generation Service in New Jersey. ACE is a wholly owned subsidiary of Conectiv, which is wholly owned by Pepco Holdings, Inc. (Pepco Holdings or PHI).

(2) SIGNIFICANT ACCOUNTING POLICIES

Financial Statement Presentation

ACE’s unaudited consolidated financial statements are prepared in conformity with accounting principles generally accepted in the United States of America (GAAP). Pursuant to the rules and regulations of the Securities and Exchange Commission, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been omitted. Therefore, these financial statements should be read along with the annual financial statements included in ACE’s Annual Report on Form 10-K for the year ended December 31, 2009. 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, 2010, 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, 2010 may not be indicative of results that will be realized for the full year ending December 31, 2010 since the sales of electric energy are seasonal.

Use of Estimates

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

Significant matters that involve the use of estimates include the assessment of contingencies, the calculation of future cash flows and fair value amounts for use in asset impairment evaluations, pension and other postretirement benefits assumptions, unbilled revenue calculations, the assessment of the probability of recovery of regulatory assets, estimation of storm restoration accruals, and income tax provisions and reserves. Additionally, ACE is subject to legal, regulatory, and other proceedings and claims that arise in the ordinary course of its business. ACE records an estimated liability for these proceedings and claims when the loss is determined to be probable and is reasonably estimable.

During the first quarter of 2010, ACE incurred significant costs associated with the February 2010 severe winter storms that affected its service territory. The total costs of the restoration efforts have been estimated at $16 million with $3 million charged to Other Operation and Maintenance expense for repair work and $13 million recorded as capital expenditures. A large portion of the costs of the restoration work relate to services provided by outside contractors and other utilities, and billings for such services in most instances have not yet been received and have been estimated. Actual billings may vary significantly from the estimates of such billings.

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Consolidation of Variable Interest Entities

ACE Power Purchase Agreements (PPAs)

ACE has PPAs with a number of entities, including three contracts between unaffiliated non-utility generators (NUGs). Due to a variable element in the pricing structure of the PPAs, ACE potentially assumes the variability in the operations of the generating facilities related to the NUGs and, therefore, has a variable interest in the entities. ACE continued, during the first quarter of 2010, to conduct exhaustive efforts to obtain information from these entities, but was unable to obtain sufficient information to conduct the analysis required under Financial Accounting Standards Board (FASB) guidance to determine whether these three entities were variable interest entities or if ACE was the primary beneficiary. As a result, ACE has applied the scope exemption from the guidance for enterprises that have conducted exhaustive efforts to obtain the necessary information, but have not been able to obtain such information.

Net purchase activities with the NUGs for the three months ended March 31, 2010 and 2009 were approximately $72 million and $83 million, respectively, of which approximately $67 million and $72 million, respectively, consisted of power purchases under the PPAs. ACE does not have loss exposure under the NUGs because the costs are recoverable from ACE’s customers through regulated rates.

ACE Transition Funding, LLC

ACE Transition Funding, LLC (ACE Funding) was established in 2001 by ACE solely for the purpose of securitizing authorized portions of ACE’s recoverable stranded costs through the issuance and sale of Transition Bonds. The proceeds of the sale of each series of Transition Bonds have been transferred to ACE in exchange for the transfer by ACE to ACE Funding of the right to collect a non-bypassable transition bond charge from ACE customers pursuant to bondable stranded costs rate orders issued by the New Jersey Board of Public Utilities (NJBPU) in an amount sufficient to fund the principal and interest payments on the Transition Bonds and related taxes, expenses and fees (Bondable Transition Property). ACE collects the transition bond charges from its customers on behalf of ACE Funding and the holders of the Transition Bonds. The assets of ACE Funding, including the Bondable Transition Property, and the Transition Bond charges collected from ACE’s customers, are not available to creditors of ACE. The holders of the Transition Bonds have recourse only to the assets of ACE Funding. ACE owns 100 percent of the equity of ACE Funding and has consolidated ACE Funding in its financial statements. The amendment to the variable interest entity consolidation guidance effective January 1, 2010 resulted in ACE Funding meeting the definition of a variable interest entity. ACE continues to consolidate ACE Funding in its financial statements as ACE is the primary beneficiary of ACE Funding under the amended variable interest entity consolidation guidance.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in ACE’s gross revenues were $6 million for each of the three months ended March 31, 2010 and 2009.

Reclassifications and Adjustments

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

Income Tax Adjustments

During the first quarter of 2010, ACE recorded an adjustment to correct certain income tax errors related to prior periods. The adjustment resulted in an increase in income tax expense of $6 million for the quarter ended March 31, 2010. The adjustment represents the reversal of erroneously recorded interest income for state income tax purposes related to uncertain and effectively settled tax positions, including $2 million, $3 million, and $1 million recorded in 2009, 2008 and 2007, respectively. During the first quarter of 2009, ACE recorded a decrease in income tax expense of $1 million to correct certain income tax errors related to prior periods.

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(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Transfers and Servicing (Accounting Standards Codification (ASC) 860)

The FASB issued new guidance that removes the concept of a qualifying special-purpose entity (QSPE) from the current guidance on transfers and servicing and the QSPE scope exception in current guidance on consolidation. The new guidance also changed the requirements for derecognizing financial assets and requires additional disclosures about a transferor’s continuing involvement in transferred financial assets.

The guidance was effective for transfers of financial assets occurring in fiscal periods beginning on January 1, 2010 for ACE. As of January 1, 2010, ACE has adopted the provisions of this guidance and determined that the guidance did not have a material impact on ACE’s overall financial condition, results of operations, or cash flows, nor does it expect it to in the future.

Consolidation of Variable Interest Entities (ASC 810)

The FASB issued new consolidation guidance regarding variable interest entities effective January 1, 2010 that eliminated the existing quantitative analysis requirement and added new qualitative factors to determine whether consolidation is required. The new qualitative factors are applied on a quarterly basis to interests in variable interest entities. Under the new guidance, the holder of the interest with the power to direct the most significant activities of the entity and the right to receive benefits or absorb losses significant to the entity would consolidate. The new guidance retained the existing provision that allows entities created before December 31, 2003 to be scoped out from a consolidation assessment if exhaustive efforts are taken and there is insufficient information to determine the primary beneficiary.

ACE has adopted the provisions of the new FASB guidance on consolidation of variable interest entities, and it did not have a material impact on ACE’s overall financial condition, results of operations, or cash flows.

Fair Value Measurement and Disclosures (ASC 820)

The FASB issued new disclosure requirements for recurring and non-recurring fair value measurements. The guidance, effective for ACE’s March 31, 2010 financial statements, required the disaggregation of balance sheet items measured at fair value into classes (that is, subsets of balance sheet items) based on the nature and risks of the items. The standard requires description of pricing inputs and valuation methodologies for instruments with Level 2 or 3 valuation inputs. In addition, the standard requires information about any transfers of instruments between Level 1 and 2 valuation categories. These additional disclosures can be found in Note (9), “Fair Value Disclosures.”

Subsequent Events (ASC 855)

The FASB issued new guidance which eliminates the requirement for ACE to disclose the date through which it has evaluated subsequent events beginning with its March 31, 2010 financial statements. ACE has modified its disclosure in Note (2), “Significant Accounting Policies.”

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(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Fair Value Measurement and Disclosures (ASC 820)

The new FASB disclosure requirements that will be effective beginning with ACE’s March 31, 2011 financial statements require that the items within the reconciliation of the Level 3 valuation category be presented in separate categories for purchases, sales, issuances, and settlements, if significant. ACE is evaluating the impact of this part of the guidance on ACE’s overall financial statements.

(5) SEGMENT INFORMATION

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

(6) 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, 2010 before intercompany allocations from the PHI Service Company, of $29 million, included $4 million for ACE’s allocated share. 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, included $4 million for ACE’s allocated share.

(7) DEBT

Credit Facilities

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.

At March 31, 2010 and December 31, 2009, the amount of cash plus borrowing capacity under PHI’s $1.5 billion credit facility available to meet the liquidity needs of PHI’s utility subsidiaries was $546 million and $582 million, respectively.

Other Financing Activities

During the three months ended March 31, 2010, the following financing activities occurred:

In January 2010, ACE Funding made principal payments of $5.9 million on Series 2002-1 Bonds, Class A-2, and $2.3 million on Series 2003-1 Bonds, Class A-2.

In March 2010, ACE resold $23.2 million in aggregate principal amount of Pollution Control Revenue Refunding Bonds Series 2004A due June 1, 2029 issued by The Pollution Control Financing Authority of Salem County. The bonds were repurchased by ACE in April 2008 in response to the 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, ACE received the proceeds of the sale, which it intends to use for general corporate purposes. The bonds bear interest at the fixed rate of 4.875% per annum, payable each March 1 and September 1, commencing September 1, 2010.

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Financing Activity Subsequent to March 31, 2010

In April 2010, 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-2.

(8) INCOME TAXES

ACE’s consolidated effective tax rate for the three months ended March 31, 2010 was 140%. ACE’s income before income tax for the three months ended March 31, 2009 was less than $1 million; therefore the consolidated effective tax rate is not meaningful. The primary item impacting the 2010 effective tax rate was the reversal of $6 million of accrued interest income on uncertain and effectively settled state income tax positions, as discussed in Note 2, “Significant Accounting Policies.”

In March 2009, the Internal Revenue Service (IRS) issued a Revenue Agent’s Report (RAR) for the audit of PHI’s consolidated federal income tax returns for the calendar years 2003 to 2005. The IRS has proposed adjustments to PHI’s tax returns, including adjustments to ACE’s capitalization of overhead costs for tax purposes and the deductibility of certain ACE casualty losses. In conjunction with PHI, ACE has appealed certain of the proposed adjustments and believes it has adequately reserved for the adjustments 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 agreements with taxing authorities and $8 million as adjustments to prior year tax positions).

(9) FAIR VALUE DISCLOSURES

Fair Value of Assets and Liabilities Excluding Debt

ACE has adopted FASB guidance on fair value measurement and disclosures (ASC 820) which established a framework for measuring fair value and expanded disclosures about fair value measurements. As defined in the guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). ACE utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. Accordingly, ACE utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurement) and the lowest priority to unobservable inputs (level 3 measurement). ACE classifies its fair value balances in the fair value hierarchy based on the observability of the inputs used in the fair value calculation as follows:

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

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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 data. Level 2 also includes those financial instruments that are valued using internally developed methodologies that have been corroborated by observable market data through correlation or by other means. Significant assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

Executive deferred compensation plan assets and liabilities include life insurance policies that are categorized as level 2 assets because they are priced based on the underlying assets in the policy. The underlying assets of these life insurance contracts consist of short term cash equivalents and fixed income securities that are priced using observable market data. The level 2 liability of the life insurance contract represents deferred compensation obligation, the value of which are tracked via underlying insurance sub-accounts. The sub-accounts are designed to track and mirror existing mutual funds and money market funds that are observable and actively traded.

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

The following tables set forth, by level within the fair value hierarchy, ACE’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2010 and December 31, 2009. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. ACE’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Fair Value Measurements at March 31, 2010
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Cash equivalents
Treasury Fund	$	13	$	13	$	—	$	—
	$	13	$	13	$	—	$	—
LIABILITIES
Executive deferred compensation plan liabilities
Life Insurance Contracts	$	1	$	—	$	1	$	—
	$	1	$	—	$	1	$	—

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	Fair Value Measurements at December 31, 2009
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Cash equivalents
Treasury Fund	$	17	$	17	$	—	$	—
	$	17	$	17	$	—	$	—
LIABILITIES
Executive deferred compensation plan liabilities
Life Insurance Contracts	$	1	$	—	$	1	$	—
	$	1	$	—	$	1	$	—

Fair Value of Debt Instruments

The estimated fair values of ACE’s non-derivative financial instruments at March 31, 2010 and December 31, 2009 are shown below:

	March 31, 2010				December 31, 2009
	(millions of dollars)
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	633	$	692	$	610	$	674
Transition Bonds issued by ACE Funding		393		424		402		427
Redeemable Serial Preferred Stock		6		5		6		4

The methods and assumptions described below were used to estimate, as of March 31, 2010 and December 31, 2009, the fair value of each class of non-derivative financial instruments shown above for which it is practicable to estimate a value.

The fair value of long-term debt issued by ACE was based on actual trade prices as of March 31, 2010 and December 31, 2009, or bid prices obtained from brokers if actual trade prices were not available. The fair values of Transition Bonds issued by ACE Funding, including amounts due within one year, were derived based on bid prices obtained from brokers if actual trade prices were not available or were based on discounted cash flows using current rates for similar issues with similar credit ratings, terms, and remaining maturities for issues with no market price available.

The fair value of the Redeemable Serial Preferred Stock, excluding amounts due within one year, was derived based on quoted market prices or discounted cash flows using current rates for preferred stock with similar terms.

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

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(10) COMMITMENTS AND CONTINGENCIES

Regulatory and Other Matters

Rate Proceeding

In August 2009, ACE submitted a petition to the NJBPU to increase its electric distribution base rates, including a request for the implementation of a BSA. Based on a test year ending December 31, 2009, adjusted for known and measurable changes, ACE requested an annual net increase in its current retail distribution rates for electric service in the amount of approximately $54 million (which includes a reduction to its Regulatory Asset Recovery Charge (RARC)) based on a requested ROE of 11.50% (or an increase of approximately $52 million, based on an ROE of 11.25%, if the BSA were approved). Excluding any adjustment to the RARC, as well as sales and use taxes, the amounts in the original application would be approximately $51.6 million without the BSA and $49.8 million with the BSA. On February 19, 2010, ACE made a filing based on an updated test period, adjusting the requested increase to approximately $45.8 million without the BSA and $44.1 million with the BSA (excluding any adjustment to the RARC, as well as sales and use taxes). On April 28, 2010, all of the parties to the proceeding, including ACE, the NJBPU Staff, the New Jersey Department of the Public Advocate, Division of Rate Counsel, the Natural Resources Defense Council, and Wal-Mart Stores East, LP and Sam’s East, signed a settlement agreement and submitted it to the Administrative Law Judge (ALJ) in the proceeding for review. The settlement agreement provides for an increase in electric distribution rates, effective for service rendered on and after June 1, 2010, of approximately $20 million (excluding any adjustment to the RARC, as well as sales and use taxes), based on a stated ROE of 10.30%. The agreement also provides that the BSA and certain other issues will be considered in a Phase II proceeding. On April 30, 2010, the ALJ issued an initial decision ordering the parties to comply with the settlement terms. The settlement agreement is subject to final review and approval by the NJBPU. The parties have requested that the NJBPU consider the matter at the public meeting currently scheduled for May 12, 2010. If the settlement is not approved, the matter will be scheduled for hearings.

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

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. The claim for indemnification seeks payment from ACE in the event the TSA is held not to be enforceable against Citgo.

RC Cape May commenced an arbitration proceeding against Citgo seeking a determination that the TSA remains in effect and notified ACE of the proceedings. On July 1, 2009, the arbitrator issued its interim award, ruling that the TSA remains in effect and is enforceable by RC Cape May against Citgo. PHI believes this ruling invalidates RC Cape May’s indemnification claim against ACE, but cannot predict whether RC Cape May will continue to pursue indemnification.

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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.

Frontier Chemical Site. In June 2007, ACE received a letter from the New York Department of Environmental Conservation (NYDEC) identifying ACE as a potentially responsible party (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. In February 2010, ACE accepted the PRP group’s offer of a de minimis cash-out settlement under which ACE paid a total of $16,000 to receive a release from liability from the PRP group and be relieved from any further involvement at the site.

Franklin Slag Pile Site. On November 26, 2008, ACE received a general notice letter from the U.S. Environmental Protection Agency (EPA) concerning the Franklin Slag Pile site in Philadelphia, Pennsylvania, asserting that ACE is a 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 as of the date of the letter, EPA’s 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, the sale was not an arrangement for the disposal or treatment of any hazardous substances as would be necessary to constitute a basis for liability under CERCLA. ACE intends to contest any claims to the contrary made by the EPA. In a May 2009 decision arising under CERCLA, which did not involve ACE, the U.S. Supreme Court rejected an EPA argument that the sale of a useful product constituted an arrangement for disposal or treatment of hazardous substances. While this decision supports ACE’s position, at this time ACE cannot predict how EPA will proceed with respect to the Franklin Slag Pile site, or what portion, if any, of the Franklin Slag Pile site response costs EPA would seek to recover from ACE.

Ward Transformer Site. In April 2009, a group of PRPs with respect to the Ward Transformer site in Raleigh, North Carolina, filed a complaint in the U.S. District Court for the Eastern District of North Carolina, alleging cost recovery and/or contribution claims against ACE with respect to past and future response costs incurred by the PRP group in performing a removal action at the site. With the court’s permission, the plaintiffs filed amended complaints on September 1, 2009. ACE, as part of a group of defendants, filed a motion to dismiss on October 13, 2009. In a March 24, 2010 order, the court denied the defendants’ motion to dismiss.

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Although it is too early in the process to characterize the magnitude of the potential liability at this site, it does not appear that ACE had extensive business transactions, if any, with the Ward Transformer site.

Appeal of New Jersey Flood Hazard Regulations. In November 2007, the New Jersey Department of Environmental Protection (NJDEP) adopted amendments to the agency’s regulations under the Flood Hazard Area Control Act (FHACA) to minimize damage to life and property from flooding caused by development in flood plains. The amended regulations impose a new regulatory program to mitigate flooding and related environmental impacts from a broad range of construction and development activities, including electric utility transmission and distribution construction that was previously unregulated under the FHACA. These regulations impose restrictions on construction of new electric transmission and distribution facilities and increase the time and personnel resources required to obtain permits and conduct maintenance activities. In November 2008, ACE filed an appeal of these regulations with the Appellate Division of the Superior Court of New Jersey. The grounds for ACE’s appeal include the lack of administrative record justification for the FHACA regulations and conflict between the FHACA regulations and other state and federal regulations and standards for maintenance of electric power transmission and distribution facilities. The case is currently in the briefing process before the appellate court.

(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, 2010 and 2009 were $26 million and $25 million, respectively.

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

	Three Months Ended March 31,
Income (Expense)	2010			2009
	(millions of dollars)
Purchased power under Default Electricity Supply contracts with Conectiv Energy Supply, Inc. (a)	$	(39	)	$	(46	)
Meter reading services provided by Millennium Account Services LLC (b)		(1	)		(1	)
Intercompany use revenue (c)		—			2

(a) Included in purchased energy expense.

(b) Included in other operating and maintenance expense.

(c) Included in operating revenue.

As of March 31, 2010 and December 31, 2009, ACE had the following balances on its balance sheets due to related parties:

Asset (Liability)	March 31 2010			December 31, 2009
	(millions of dollars)
Payable to Related Party (current) (a)
PHI Service Company	$	(11	)	$	(38	)
PHI Parent Company		—			(3	)
Conectiv Energy Supply, Inc.		(12	)		(15	)
Other		(2	)		(2	)
Total	$	(25	)	$	(58	)

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

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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	97
Pepco	125
DPL	132
ACE	140

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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).

The following table sets forth the percentage contributions to consolidated operating revenue and operating income, including intercompany transactions, attributable to the Power Delivery and Competitive Energy business.

	Three Months Ended March 31,
	2010		2009
Percentage of Consolidated Operating Revenue
Power Delivery	53	%	54	%
Competitive Energy	49	%	49	%
Intercompany transactions and Other	(2	)%	(3	)%
Percentage of Consolidated Operating Income
Power Delivery	62	%	74	%
Competitive Energy	30	%	19	%
Intercompany transactions and Other	8	%	7	%
Percentage of Power Delivery Operating Revenue
Power Delivery Electric	92	%	90	%
Power Delivery Gas	8	%	10	%

Power Delivery

Power Delivery Electric consists primarily of the transmission, distribution and default supply of electricity, and Power Delivery Gas consists of the distribution and supply of natural gas. 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 & 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 is Standard Offer Service in Delaware, the District of Columbia and Maryland, and Basic Generation Service in New Jersey. In this Form 10-Q, these supply service obligations are referred to generally as Default Electricity Supply.

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

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

Effective June 2007, the Maryland Public Service Commission approved a bill stabilization adjustment mechanism (BSA) for retail customers of Pepco and DPL. The District of Columbia Public Service Commission also approved a BSA for Pepco’s retail customers, effective in November 2009. For customers to whom 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 and the District of Columbia to fluctuate from period to period are changes in the number of customers and changes in the approved distribution charge per customer. For customers to whom the BSA applies, changes in customer usage (such as due to weather conditions, energy prices, energy efficiency programs or other reasons) from period to period have no impact on reported distribution revenue.

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

Competitive Energy

The Competitive Energy business provides competitive generation, marketing and supply of electricity and gas, and 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 provide 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, 2010 and 2009, 5% and 7% of the operating revenues of the Competitive Energy business were attributable to electric energy and capacity, and natural gas sold to the Power Delivery segment.

Conectiv Energy’s primary business objective is to maximize the value of its generating facilities by leveraging its operational and fuel flexibilities. Pepco Energy Services’ primary objective is to provide energy savings performance contracting services principally to federal, state and local government customers, as well as, designing, constructing and operating combined heat and power, and central energy plants, for customers. 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 generating facilities, the cost of purchased energy necessary to meet its power and gas supply obligations, and the cost of construction services provided by Pepco Energy Services.

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

Conectiv Energy

On April 20, 2010, the Board of Directors of PHI approved a plan for the disposition of Conectiv Energy. The plan consists of the sale of Conectiv Energy’s wholesale power generation business (the Generation Business) and the liquidation of all of Conectiv Energy’s load service supply contracts, energy hedging portfolio, certain tolling agreements and other non-core assets. In accordance with the plan, PHI on the same day entered into an agreement (the Purchase Agreement) to sell the Generation Business to a subsidiary of Calpine Corporation (Calpine). Under the terms of the Purchase Agreement, Calpine will purchase a subsidiary of PHI, which after a reorganization will hold the assets and liabilities of the Generation Business, for a purchase price of $1.65 billion, plus the market value of the fuel oil inventory at closing, and subject to various adjustments, including adjustments for (i) the level of working capital and non-fuel oil inventory at closing and (ii) actual capital expenditures relative to budgeted capital expenditures through the closing date. The targeted closing date for the sale is June 30, 2010.

All of Conectiv Energy’s generating facilities, which have an aggregate generating capacity of 3,860 megawatts, are included in the sale. Calpine is also acquiring Conectiv Energy’s Delta Project, a 565 megawatt combined cycle generating facility that is under construction, along with a 6-year tolling agreement associated with the Delta Project. The sale does not include the balance of PHI’s Conectiv Energy segment, which includes Conectiv Energy’s load service supply contracts, energy hedging portfolio, certain tolling agreements, and other non-core assets. Under the plan adopted by the board of directors, these contracts and other assets will be liquidated over a period not exceeding 12 months from the date of adoption of the plan.

PHI currently estimates that the sale of the Generation Assets on the terms set forth in the Purchase Agreement and the liquidation of the remaining Conectiv Energy assets will result in a loss through the completion of the liquidation for financial reporting purposes ranging from $60 million to $90 million, after tax. The loss to be recognized in the second quarter of 2010 could exceed this range due to unrealized losses required to be recorded in earnings related to derivative instruments no longer qualifying for cash flow hedge accounting. PHI currently estimates that these unrealized losses will be offset by gains from the liquidation of load service supply contracts over the liquidation period.

The estimated after-tax proceeds from the sale of the Generation Assets and the liquidation of the remaining Conectiv Energy assets and contracts, combined with the return of collateral posted under the contracts, are expected to total approximately $1.75 billion. Taxes on the sale and liquidation of the assets are currently estimated to be approximately $300 million.

Beginning with its financial statements for the quarter ended June 30, 2010, the entire Conectiv Energy segment will be reported in discontinued operations.

For further details related to the sale agreement, see Note (15), “Subsequent Event,” in the consolidated financial statements of PHI, set forth in Item 1 of this Form 10-Q.

Pepco Energy Services

On December 7, 2009, PHI announced that it will wind down the retail electric and natural gas supply business, which it conducts through its subsidiary Pepco Energy Services. The retail energy supply business historically has generated a substantial portion of the operating revenues and net income of PHI’s Pepco Energy Services operating segment. Operating revenues related to the retail energy supply business for the three months ended March 31, 2010 and 2009 were $497 million and $630 million, respectively,

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PEPCO HOLDINGS

while operating income for the same periods was $21 million and $22 million, respectively. In connection with the operation of the retail energy supply business, as of March 31, 2010, Pepco Energy Services provided letters of credit of $181 million and posted net cash collateral of $192 million. These collateral requirements, which are based on existing wholesale energy purchase and sale contracts and current market prices, will decrease as the contracts expire and are expected to be fully released over time by June 1, 2014. The remaining Energy Services business will not be affected by the wind down of the retail energy supply business.

Other Non-regulated

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, 2010 of approximately $1.4 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 (14), “Commitments and Contingencies—Regulatory and Other Matters – PHI’s Cross-Border Energy Lease Investments,” to the consolidated financial statements of PHI set forth in Part I, Item 1 of this Form 10-Q.

Earnings Overview

Three Months Ended March 31, 2010 Compared to Three Months Ended March 31, 2009

PHI’s net income for the three months ended March 31, 2010 was $36 million, or $0.16 per share, compared to $45 million, or $0.21 per share, for the three months ended March 31, 2009.

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

Mirant Corporation (Mirant) bankruptcy claims settlement $ 8

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

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

	2010			2009			Change
Power Delivery	$	20		$	42		$	(22	)
Conectiv Energy		8			4			4
Pepco Energy Services		13			8			5
Other Non-Regulated		4			6			(2	)
Corporate and Other		(9	)		(15	)		6
Total PHI Net Income	$	36		$	45		$	(9	)

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PEPCO HOLDINGS

Discussion of Operating Segment Net Income Variances:

Power Delivery’s $22 million decrease in earnings is primarily due to the following:

• $11 million decrease due to income tax adjustments related to uncertain and effectively settled tax positions.

• $8 million increase in 2009 earnings attributable to the District of Columbia Public Service Commission approval of Pepco’s proposal for sharing the District of Columbia’s portion of the proceeds of the Mirant bankruptcy settlement remaining after the transfer of the power purchase agreement between Pepco and Panda-Brandywine L.P.

• $8 million decrease due to higher operating and maintenance costs primarily resulting from February 2010 storm restoration activity.

• $4 million increase due to the impact of distribution rate orders (Pepco District of Columbia effective November 2009 and March 2010; and DPL Maryland effective December 2009).

Conectiv Energy’s $4 million increase in earnings is primarily due to the following:

Merchant Generation earnings increased $3 million primarily due to:

• $14 million increase due to higher capacity prices.

• $11 million decrease related to fuel (primarily natural gas) derivatives, used for economic hedging, that were adversely impacted by falling commodity prices.

Load Service earnings increased $3 million primarily due to:

• $10 million increase from PJM default electricity supply contracts and associated hedges due to lower power cost, lower power price volatility and higher sales volumes.

• $7 million decrease due to New England default electricity supply contracts and associated hedges due to higher net cost and lower volume served.

Energy Marketing earnings decreased $2 million primarily due to oil marketing activities.

Pepco Energy Services’ $5 million increase in earnings is primarily due to lower Reliability Pricing Model charges and higher capacity prices associated with generating facilities.

Corporate and Other’s $6 million increase in earnings is primarily due to favorable income tax adjustments from the release of certain deferred tax asset valuation allowances related to state net operating losses; partially offset by the unfavorable impact of new health care tax legislation, specifically, the Medicare Part D subsidized costs that are no longer tax deductible after 2012.

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Consolidated Results Of Operations

The following results of operations discussion is for the three months ended March 31, 2010, compared to the three months ended March 31, 2009. 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:

	2010			2009			Change
Power Delivery	$	1,262		$	1,372		$	(110	)
Conectiv Energy		603			575			28
Pepco Energy Services		547			657			(110	)
Other Non-Regulated		13			13			—
Corporate and Other		(66	)		(97	)		31
Total Operating Revenue	$	2,359		$	2,520		$	(161	)

Power Delivery Business

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

	2010		2009		Change
Regulated T&D Electric Revenue	$	397	$	387	$	10
Default Electricity Supply Revenue		755		836		(81	)
Other Electric Revenue		15		18		(3	)
Total Electric Operating Revenue		1,167		1,241		(74	)
Regulated Gas Revenue		87		119		(32	)
Other Gas Revenue		8		12		(4	)
Total Gas Operating Revenue		95		131		(36	)
Total Power Delivery Operating Revenue	$	1,262	$	1,372	$	(110	)

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 at rates regulated by FERC.

Default Electricity Supply Revenue is the revenue received from 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 energy supplier, and which, depending on the jurisdiction, is also known as Standard Offer Service or Basic Generation Service. The costs related to Default Electricity Supply are included in Fuel and Purchased Energy. Default Electricity Supply Revenue also includes revenue from Transition Bond Charges 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 territory at regulated rates.

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

Regulated T&D Electric

Regulated T&D Electric Revenue	2010		2009		Change
Residential	$	149	$	144	$	5
Commercial and industrial		183		180		3
Other		65		63		2
Total Regulated T&D Electric Revenue	$	397	$	387	$	10

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

Regulated T&D Electric Sales (Gigawatt hours (GWh))	2010	2009	Change
Residential	4,877	4,774	103
Commercial and industrial	7,201	7,493	(292	)
Other	68	70	(2	)
Total Regulated T&D Electric Sales	12,146	12,337	(191	)
Regulated T&D Electric Customers (in thousands)	2010	2009	Change
Residential	1,630	1,615	15
Commercial and industrial	198	197	1
Other	2	2	—
Total Regulated T&D Electric Customers	1,830	1,814	16

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

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

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

Regulated T&D Electric Revenue increased by $10 million primarily due to:

• An increase of $3 million as a result of the implementation of the BSA in the District of Columbia that became effective in November 2009 (consisting of a positive $3 million Revenue Decoupling Adjustment after netting a $1 million reduction in distribution rates effective with the BSA implementation).

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• An increase of $3 million due to a distribution rate increase for DPL in Maryland that became effective in December 2009.

• An increase of $2 million due to customer growth of 1% in 2010 primarily in the residential class.

Default Electricity Supply

Default Electricity Supply Revenue	2010		2009		Change
Residential	$	521	$	517	$	4
Commercial and industrial		179		260		(81	)
Other		55		59		(4	)
Total Default Electricity Supply Revenue	$	755	$	836	$	(81	)

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

Default Electricity Supply Sales (GWh)	2010	2009	Change
Residential	4,680	4,638	42
Commercial and industrial	1,755	2,472	(717	)
Other	25	27	(2	)
Total Default Electricity Supply Sales	6,460	7,137	(677	)

Default Electricity Supply Customers (in thousands)	2010	2009	Change
Residential	1,573	1,574	(1	)
Commercial and industrial	158	166	(8	)
Other	2	2	—
Total Default Electricity Supply Customers	1,733	1,742	(9	)

Default Electricity Supply Revenue decreased by $81 million primarily due to:

• A decrease of $71 million due to lower sales, primarily as a result of commercial customer migration to competitive suppliers.

• A decrease of $15 million due to lower sales as a result of milder weather during the 2010 winter months as compared to 2009.

• A decrease of $9 million in wholesale energy and capacity revenues primarily due to the sale of lower volumes of electricity purchased from NUGs.

The aggregate amount of these decreases was partially offset by:

• An increase of $17 million due to higher non-weather related average customer usage.

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Regulated Gas

Regulated Gas Revenue	2010		2009		Change
Residential	$	55	$	75	$	(20	)
Commercial and industrial		30		42		(12	)
Transportation and other		2		2		—
Total Regulated Gas Revenue	$	87	$	119	$	(32	)
Regulated Gas Sales (billion cubic feet)	2010		2009		Change
Residential		4		4		—
Commercial and industrial		2		3		(1	)
Transportation and other		2		2		—
Total Regulated Gas Sales		8		9		(1	)
Regulated Gas Customers (in thousands)	2010		2009		Change
Residential		114		114		—
Commercial and industrial		9		9		—
Transportation and other		—		—		—
Total Regulated Gas Customers		123		123		—

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

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

• Industrial activity in the region includes chemical and pharmaceutical.

Regulated Gas Revenue decreased by $32 million primarily due to:

• A decrease of $23 million due to lower sales as a result of milder weather during the 2010 winter months as compared to 2009.

• A decrease of $16 million due to the Gas Cost Rate decreases effective March 2009 and November 2009.

• A decrease of $8 million (which is offset by a corresponding decrease in Fuel and Purchased Energy) associated with an adjustment in 2009 to recognize the unbilled portion of Gas Cost Rate revenue, which prior to 2009 had not previously been recognized.

The aggregate amount of these decreases was partially offset by:

• An increase of $15 million due to higher non-weather related average customer usage.

Other Gas Revenue

Other Gas Revenue decreased by $4 million primarily due to lower revenue from off-system sales as a result of lower demand from electric generators and gas marketers.

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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 business 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 Energy and Other Services Cost of Sales. 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, Fuel and Purchased Energy and Other Services Cost 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 Operating Revenue, Fuel and Purchased Energy and Other Services 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 consists primarily of electric power, capacity and ancillary services sales from Conectiv Energy’s generating facilities; tolling agreements entered into to sell energy and other products from Conectiv Energy’s generating facilities and to purchase energy and other products from generating facilities 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; and fuel switching activities made possible by the multi-fuel capabilities of some of Conectiv Energy’s generating facilities.

Load Service consists primarily of 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 in PJM and ISONE.

Energy Marketing activities consist primarily of wholesale 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, power origination activities, which primarily represent the fixed margin component of structured power transactions such as default supply service in PJM and Default Electricity Supply service in ISONE.

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Conectiv Energy Gross Margin and Operating Statistics	Three Months Ended March 31,
	2010			2009		Change
Operating Revenue ($ millions):
Merchant Generation (a)	$	266		$	243	$	23
Load Service (a)		196			202		(6	)
Energy Marketing(a)		141			130		11
Total Operating Revenue(b)	$	603		$	575	$	28
Cost of Sales ($ millions):
Merchant Generation	$	219		$	201	$	18
Load Service		190			201		(11	)
Energy Marketing		131			116		15
Total Cost of Sales(c)	$	540		$	518	$	22
Gross Margin ($ millions):
Merchant Generation	$	47		$	42	$	5
Load Service		6			1		5
Energy Marketing		10			14		(4	)
Total Gross Margin	$	63		$	57	$	6
Generation Fuel and Purchased Power Expenses ($ millions) (d):
Generation Fuel Expenses (e),(f)
Natural Gas	$	37		$	18	$	19
Coal		7			9		(2	)
Oil		8			18		(10	)
Other(g)		2			1		1
Total Generation Fuel Expenses	$	54		$	46	$	8
Purchased Power Expenses (f)	$	251		$	242	$	9
Statistics:
Generation Output (Megawatt hours(MWh)):
Base-Load (h)		177,948			303,541		(125,593	)
Mid-Merit (Combined Cycle) (i)		495,614			309,146		186,468
Other (j)		(2,175	)		34,140		(36,315	)
Peaking		2,174			2,112		62
Tolled Generation		77,793			223,143		(145,350	)
Total		751,354			872,082		(120,728	)
Load Service Volume (MWh) (k)		1,974,344			2,009,958		(35,614	)
Average Power Sales Price (l) ($/MWh):
Generation Sales (e)	$	57.48		$	65.65	$	(8.17	)
Non-Generation Sales (m)	$	85.46		$	92.65	$	(7.19	)
Total	$	77.87		$	84.38	$	(6.51	)
Average on-peak spot power price at PJM East Hub ($/MWh) (n)	$	52.41		$	60.81	$	(8.40	)
Average around-the-clock spot power price at PJM East Hub ($/MWh) (n)	$	48.93		$	54.89	$	(5.96	)
Average spot natural gas price at market area M3 ($/MMBtu)(o)	$	6.09		$	6.28	$	(0.19	)
Weather (degree days at Philadelphia Airport): (p)
Heating degree days		2,411			2,534		(123	)
Cooling degree days		—			—		—

(a) 2009 data has been adjusted to reflect new reporting structure as of 01/01/2010. Load and related hedges are now reported in Load Service (previously included in Merchant Generation and Load Service); Wholesale natural gas marketing activities are now reported in Merchant Generation (previously included in Energy Marketing).

(b) Includes $61 million and $91 million of affiliate transactions for 2010 and 2009, respectively.

(c) Includes less than $1 million of affiliate transactions for both 2010 and 2009. Also, excludes depreciation and amortization expense of $11 million and $9 million, respectively.

(d) Consists solely of Merchant Generation and Load Service expenses; does not include the cost of fuel not consumed by the generating facilities and intercompany tolling expenses.

(e) Includes tolled generation.

(f) Includes associated hedging gains and losses.

(g) Includes emissions expenses, fuel additives, and other fuel-related costs.

(h) Edge Moor Units 3 and 4 and Deepwater Unit 6.

(i) Hay Road and Bethlehem, all units.

(j) Edge Moor Unit 5, Deepwater Unit 1 and Vineland Solar.

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

(l) Calculated from data reported in Conectiv Energy’s Electric Quarterly Report (EQR) filed with the FERC; does not include capacity or ancillary services revenue. Prices may differ from those originally reported in prior periods due to normal load true-ups requiring EQR filing amendments.

(m) 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.

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(n) Source: PJM website (www.pjm.com).

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

(p) Source: National Oceanic and Atmospheric Administration National Weather Service data.

Merchant Generation gross margin increased approximately $5 million primarily due to:

• An increase of approximately $24 million due to higher PJM capacity prices.

• A decrease of approximately $19 million primarily related to fuel (mostly natural gas) derivatives, used for economic hedging, that were adversely impacted by falling commodity prices.

Load Service gross margin increased approximately $5 million primarily due to:

• An increase of approximately $17 million from PJM default electricity supply contracts and associated hedges due to lower power cost, lower power price volatility, and 11% higher sales volumes.

• A decrease of approximately $12 million on New England default electricity supply contracts and associated hedges due to higher net cost and a 22% decrease in volume served.

Energy Marketing gross margin decreased approximately $4 million primarily due to oil marketing activities.

Pepco Energy Services

Pepco Energy Services’ operating revenue decreased $110 million primarily due to:

• $145 million decrease due to lower volumes of retail electric load served as a result of the continuing expiration of existing retail contracts.

• $19 million increase due to higher customer load from customer acquisitions in 2009 prior to the commencement of the wind down of the business, partially offset by lower retail natural gas prices.

• $10 million increase due to lower Reliability Pricing Model charges and higher PJM capacity prices associated with the generating facilities.

Operating Expenses

Fuel and Purchased Energy and Other Services Cost of Sales

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

	2010			2009			Change
Power Delivery	$	817		$	946		$	(129	)
Conectiv Energy		540			518			22
Pepco Energy Services		496			614			(118	)
Corporate and Other		(62	)		(95	)		33
Total	$	1,791		$	1,983		$	(192	)

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Power Delivery Business

Power Delivery’s Fuel and Purchased Energy (other than expense associated with Regulated Gas Revenue and Other Gas Revenue) consists of the cost of electricity purchased by its utility subsidiaries to fulfill their respective Default Electricity Supply obligations and, as such, is recoverable from customers in accordance with the terms of public service commission orders. Fuel and Purchased Energy expense decreased by $129 million primarily due to:

• A decrease of $66 million primarily due to commercial customer migration to competitive suppliers.

• A decrease of $22 million in deferred electricity expense due to a lower rate of recovery of electricity supply costs.

• A decrease of $16 million due to lower electricity sales as a result of milder weather during the 2010 winter months as compared to 2009.

• A decrease of $14 million in deferred gas expense as a result of a higher rate of recovery of natural gas supply costs in 2009 due to the recognition of the unbilled portion of Gas Cost Rate revenue, as discussed under Regulated Gas Revenue.

• A decrease of $10 million from the settlement of financial hedges entered into as part of DPL’s hedge program for regulated natural gas.

• A decrease of $7 million in the cost of gas purchased for regulated sales as a result of a lower average cost of gas withdrawn from storage.

The aggregate amount of these decreases was partially offset by:

• An increase of $16 million due to higher average electricity costs under Default Electricity Supply contracts.

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 business 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 decreased $118 million primarily due to:

• $130 million decrease due to lower volumes of electricity purchased to serve decreased retail customer load as a result of the continuing expiration of existing retail contracts.

• $4 million decrease due to fewer purchases of installed capacity and lower fuel usage associated with the generating facilities.

• $10 million increase due to higher retail customer load from 2009 customer acquisitions partially offset by lower wholesale natural gas prices.

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Other Operation and Maintenance

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

	2010			2009			Change
Power Delivery	$	198		$	186		$	12
Conectiv Energy		31			33			(2	)
Pepco Energy Services		21			23			(2	)
Other Non-Regulated		1			—			1
Corporate and Other		(7	)		(6	)		(1	)
Total	$	244		$	236		$	8

Other Operation and Maintenance expense for Power Delivery increased by $12 million primarily due to:

• An increase of $17 million in emergency restoration costs largely driven by the February 2010 severe winter storms. A large portion of the costs of the restoration work relates to services provided by outside contractors and other utilities and billings for such services in most instances have not yet been received and have been estimated. Actual billings may vary significantly from the estimates of such billings.

The increase was partially offset by:

• A decrease of $3 million in regulatory expenses due to an adjustment for recoverable District of Columbia distribution rate case costs.

Deferred Electric Service Costs

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

Deferred Electric Service Costs increased by $8 million, to an expense reduction of $19 million in 2010 as compared to an expense reduction of $27 million in 2009, primarily due to an increase in deferred electricity expense due to a higher rate of recovery of electricity supply costs.

Effect of Settlement of Mirant Bankruptcy Claims

In the first quarter of 2009, Pepco recorded a pre-tax gain of $14 million reflecting the portion of the Mirant bankruptcy settlement proceeds attributed to the District of Columbia that were retained by Pepco after the allocation of such proceeds between Pepco and its District of Columbia customers.

Income Tax Expense

PHI’s effective tax rates for the three months ended March 31, 2010 and 2009 were 46.3% and 34.8%, respectively. A portion of the increase in the rate resulted from changes in estimates and interest related to uncertain and effectively settled tax positions, primarily related to a $2 million reversal of accrued interest income on state income tax positions that PHI no longer believes is more likely than not to be realized and the reversal of $6 million of erroneously accrued interest income on uncertain and effectively settled state income tax positions, as discussed in Note 2, “Significant Accounting Policies.”

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

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

In March 2009, the Internal Revenue Service (IRS) issued a Revenue Agent’s Report (RAR) for the audit of PHI’s consolidated federal income tax returns for the calendar years 2003 to 2005. The IRS has proposed adjustments to PHI’s tax returns, including adjustments to PHI’s deductions related to cross-border energy lease investments, the capitalization of overhead costs for tax purposes and the deductibility of certain casualty losses. PHI has appealed certain of the proposed adjustments and believes it has adequately reserved for the adjustments proposed in the RAR. See Note (14), “Commitments and Contingencies – PHI’s Cross-Border Energy Lease Investments” to the consolidated financial statements of PHI, set forth in Item 1 of this Form 10-Q, for additional discussion. 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).

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, 2010, Pepco Holdings’ current assets on a consolidated basis totaled $1.9 billion and its current liabilities totaled $2.5 billion. At December 31, 2009, Pepco Holdings’ current assets on a consolidated basis totaled $1.9 billion and its current liabilities totaled $2.3 billion. The decrease in working capital from December 31, 2009 to March 31, 2010 is primarily due to a $200 million increase in short-term debt.

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At March 31, 2010, Pepco Holdings’ cash and current cash equivalents totaled $38 million, of which $18 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 equivalents (cash that is available to be used only for designated purposes) totaled $10 million. At December 31, 2009, Pepco Holdings’ cash and current cash equivalents totaled $46 million and its current restricted cash equivalents totaled $11 million.

PHI expects the working capital deficit will be funded during 2010 through cash flow from operations, reduced collateral requirements of the Competitive Energy business, delayed capital expenditures related to the Mid-Atlantic Power Pathway project, and the refinancing of long-term debt currently due within a year through the use of the unsecured credit facility entered into on April 20, 2010.

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, 2010 (millions of dollars)
Type	PHI Parent		Pepco		DPL		ACE		ACE Funding		Conectiv Energy		Pepco Energy Services		PCI		Conectiv		PHI Consolidated
Variable Rate Demand Bonds	$	—	$	—	$	105	$	23	$	—	$	—	$	18	$	—	$	—	$	146
Commercial Paper		490		—		—		91		—		—		—		—		—		581
Total Short-Term Debt	$	490	$	—	$	105	$	114	$	—	$	—	$	18	$	—	$	—	$	727
Current Maturities of Long-Term Debt and Project Funding	$	450	$	—	$	31	$	1	$	34	$	—	$	5	$	—	$	—	$	521
	As of December 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	$	—	$	—	$	105	$	23	$	—	$	—	$	18	$	—	$	—	$	146
Commercial Paper		324		—		—		60		—		—		—		—		—		384
Total Short-Term Debt	$	324	$	—	$	105	$	83	$	—	$	—	$	18	$	—	$	—	$	530
Current Maturities of Long-Term Debt and Project Funding	$	450	$	16	$	31	$	1	$	34	$	—	$	4	$	—	$	—	$	536

Financing Activity During the Three Months Ended March 31, 2010

In January 2010, Atlantic City Electric Transition Funding LLC (ACE Funding) made principal payments of $5.9 million on Series 2002-1 Bonds, Class A-2, and $2.3 million on Series 2003-1 Bonds, Class A-2.

In March 2010, Pepco redeemed at maturity, $16 million of Prince George’s County 5.75% Pollution Control Revenue Refunding Bonds Series 1995.

In March 2010, ACE resold $23.2 million in aggregate principal amount of Pollution Control Revenue Refunding Bonds Series 2004A due June 1, 2029 issued by The Pollution Control Financing Authority of Salem County. The bonds were repurchased by ACE in April 2008 in response to the 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, ACE received the proceeds of the sale, which it intends to use for general corporate purposes. The bonds bear interest at the fixed rate of 4.875% per annum, payable each March 1 and September 1, commencing September 1, 2010.

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Financing Activity Subsequent to March 31, 2010

In April 2010, 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-2.

In April 2010, DPL completed a tax-exempt bond financing in which The Delaware Economic Development Authority (DEDA) issued and sold $78.4 million of its Gas Facilities Refunding Revenue Bonds, Series 2010, due February 1, 2031. The proceeds from the issuance of the bonds were loaned by DEDA to DPL pursuant to a loan agreement, dated as of April 1, 2010, between DEDA and DPL. The payment obligations under the loan agreement correspond to the payments of principal, premium, if any, and interest when and as due on the bonds. The bonds bear interest at the fixed rate of 5.40% per annum, payable each February 1 and August 1, commencing August 1, 2010. Beginning on August 1, 2020, the bonds are subject to optional redemption at the direction of DPL, in whole or in part, at a redemption price equal to the principal amount thereof, plus accrued interest, if any, to the redemption date.

DPL used the proceeds of the bonds to effect the redemption of all outstanding amounts of the following series of tax-exempt bonds previously issued by DEDA for the benefit of DPL (such bonds collectively are referred to as the Prior Bonds):

• $11.15 million of Exempt Facilities Refunding Revenue Bonds (Delmarva Power & Light Company Project) Series 2000A;

• $27.75 million of Exempt Facilities Refunding Revenue Bonds (Delmarva Power & Light Company Project) Series 2000B;

• $20 million of Exempt Facilities Refunding Revenue Bonds (Delmarva Power & Light Company Project) Series 2001A;

• $4.5 million of Exempt Facilities Refunding Revenue Bonds (Delmarva Power & Light Company Project) Series 2001B; and

• $15 million of Exempt Facilities Refunding Revenue Bonds (Delmarva Power & Light Company Project) Series 2002A.

The Prior Bonds were repurchased by DPL in 2008 in response to the 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 from the redemption of the Prior Bonds, which it intends to use for general corporate purposes.

Credit Facilities

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

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election, (i) the greater of the prevailing prime rate and the federal funds effective rate plus 0.5% or (ii) the prevailing Eurodollar rate, plus a margin that varies according to the credit rating of the borrower. The facility also includes a “swingline loan sub-facility” pursuant to which each company may make same day borrowings in an aggregate amount not to exceed $150 million. Any swingline loan must be repaid by the borrower within seven days of receipt thereof.

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

The facility is intended to serve primarily as a source of liquidity to support the commercial paper programs of the respective companies. The companies also are permitted to use the facility to borrow funds for general corporate purposes and issue letters of credit. In order for a borrower to use the facility, certain representations and warranties must be true and correct, and the borrower must be in compliance with specified covenants, including (i) the requirement that each borrowing company maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the credit agreement, which calculation excludes from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) a restriction on sales or other dispositions of assets, other than certain sales and dispositions, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than permitted liens.

The absence of a material adverse change in the borrower’s business, property, and results of operations or financial condition is not a condition to the availability of credit under the facility. The facility does not include any rating triggers.

In November 2008, PHI entered into a second unsecured credit facility in the amount of $400 million with a syndicate of nine lenders, which was amended and restated in October 2009, to extend the facility termination date to October 15, 2010. Under this facility, PHI may obtain revolving loans and swingline loans over the term of the facility. 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 $1.5 billion credit facility. The absence of a material adverse change in PHI’s business, property, and results of operations or financial condition is not a condition to the availability of credit under the facility. The facility does not include any rating triggers. These two facilities are referred to herein collectively as PHI’s “primary credit facilities.” As of March 31, 2010, each borrower was in compliance with the covenants of each of the primary credit facilities.

In May 2009, PHI entered into a $50 million, 18-month bilateral credit agreement, which can only be used for the purpose of obtaining letters of credit. As of March 31, 2010, $25 million in letters of credit were outstanding under the agreement.

On April 20, 2010, PHI entered into an additional unsecured credit facility in the amount of $450 million with two lenders. PHI is entitled to make up to two draws under the facility at any time on or before June 1, 2010, and may use the proceeds from the facility solely to repay (i) $200 million in aggregate principal amount of its 4.00% Notes due May 15, 2010 and (ii) $250 million in aggregate principal amount of its Floating Rate Notes due June 1, 2010. The facility matures on April 19, 2011. Subject to certain exceptions, the facility requires PHI to make mandatory prepayments upon the receipt by PHI of cash proceeds from (i) certain issuance of equity interests by PHI, (ii) the issuance of debt securities in a public or private debt or capital markets transaction with a maturity of greater than one year, (iii) the borrowing

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by PHI under a credit facility not currently in effect and (iv) certain asset sales, including the sale of the Conectiv Energy wholesale power generation assets. The interest rate payable on funds borrowed under the facility is, at PHI’s election, based on either (a) the corresponding 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. In addition to a commitment fee that varies according to the credit rating of PHI, PHI will be required to pay a duration fee equal to 1.0% on the principal amount of any loans outstanding on October 15, 2010, January 20, 2011 and March 21, 2011. 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 loans under the facility. The facility does not include any rating triggers.

Cash and Credit Facilities Available as of March 31, 2010

	Consolidated PHI		PHI Parent		Utility Subsidiaries
	(millions of dollars)
Credit Facilities (Total Capacity) (a)	$	1,950	$	1,325	$	625
Less: Letters of Credit issued		210		204		6
Commercial Paper outstanding		581		490		91
Remaining Credit Facilities Available		1,159		631		528
Cash Invested in Money Market Funds (b)		18		—		18
Total Cash and Credit Facilities Available	$	1,177	$	631	$	546

(a) Of this amount, $50 million is available under a bi-lateral agreement expiring in November 2010 that can be used only for the purpose of obtaining letters of credit.

(b) Cash and cash equivalents reported on the Balance Sheet total $38 million, which includes the $18 million invested in money market funds and $20 million held in cash and uncollected funds.

At March 31, 2010, the amount of cash, plus borrowing capacity under PHI credit facilities available to meet the future liquidity needs of PHI and its utility subsidiaries on a consolidated basis totaled $1.2 billion, of which $546 million consisted of the combined cash and borrowing capacity of PHI’s utility subsidiaries. At December 31, 2009, the amount of cash, plus borrowing capacity under PHI credit facilities available to meet the liquidity needs of PHI on a consolidated basis totaled $1.4 billion, of which $582 million consisted of the combined cash and borrowing capacity of PHI’s utility subsidiaries.

Collateral Requirements of the Competitive Energy Business

In conducting its retail energy supply business, Pepco Energy Services, during periods of declining energy prices, has been exposed to the asymmetrical risk of having to post collateral under its wholesale purchase contracts without receiving a corresponding amount of collateral from its retail customers. To partially address these asymmetrical collateral obligations, Pepco Energy Services, in the first quarter of 2009, entered into a credit intermediation arrangement with Morgan Stanley Capital Group, Inc. (MSCG). Under this arrangement, MSCG, in consideration for the payment to MSCG of certain fees, (i) 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 obligation to post collateral based on changes in electricity prices. As of March 31, 2010, approximately 12% of Pepco Energy Services’ wholesale electricity purchase obligations (measured in megawatt hours) was covered by this credit intermediation arrangement with MSCG. The fees incurred by Pepco Energy Services in the amount of $25 million are being amortized into expense in declining amounts over the life of the arrangement based on the fair value of the underlying contracts at the time of the novation. For the three months ended March 31, 2010 and 2009, approximately $2 million and $1 million, respectively, of the fees have been amortized and reflected in interest expense.

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In addition to Pepco Energy Services’ retail energy supply 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, 2010, Pepco Energy Services and Conectiv Energy had posted net cash collateral of $192 million and $325 million, respectively, and letters of credit of $181 million and $19 million, respectively. At December 31, 2009, Pepco Energy Services and Conectiv Energy had posted net cash collateral of $123 million and $240 million, respectively, and letters of credit of $157 million and $22 million, respectively.

At March 31, 2010, the amount of cash, plus borrowing capacity under PHI credit facilities available to meet the future liquidity needs of the Competitive Energy business totaled $631 million.

Pension and Postretirement Benefit Plans

PHI and its subsidiaries sponsor pension and postretirement benefit plans for their employees. The pension and postretirement benefit plans experienced significant declines in the fair value of plan assets in 2008, which has resulted in increased pension and postretirement benefit costs in 2009 and 2010 and increased plan funding requirements.

Based on the results of the 2009 actuarial valuation, PHI’s net periodic pension and other postretirement benefit costs were approximately $149 million. The current estimate of benefit cost for 2010 is $116 million. The utility subsidiaries are generally responsible for approximately 80% to 85% of the total PHI net periodic pension and other postretirement benefit costs. Approximately 30% of net periodic pension and other postretirement benefit costs are capitalized. PHI estimates that its net periodic pension and other postretirement benefit expense will be approximately $80 million in 2010, as compared to $103 million in 2009 and $44 million in 2008.

Pension benefits are provided under PHI’s defined benefit pension plan (the PHI Retirement Plan), a non contributory retirement plan that covers substantially all employees of Pepco, DPL and ACE and certain employees of other PHI subsidiaries. PHI’s funding policy with regard to the PHI Retirement Plan is to maintain a funding level that is at least equal to the funding target as defined under the Pension Protection Act of 2006. The funding target under the Pension Protection Act is an amount that is being phased in over time, and will reach 100% of accrued pension liability by 2011. The funding target was 94% of the accrued liability for 2009 and is 96% of the accrued liability for 2010.

No contributions have been made in 2010. In 2009, PHI made discretionary tax-deductible contributions totaling $300 million to the PHI Retirement Plan, which brought plan assets to at least the funding target level for 2009 under the Pension Protection Act. Of this amount, $240 million was contributed through tax-deductible contributions from Pepco, ACE and DPL in the amounts of $170 million, $60 million and $10 million, respectively. The remaining $60 million contribution was made through tax-deductible contributions from the PHI Service Company.

Under the Pension Protection Act, if a plan incurs a funding shortfall in the preceding plan year, there can be required minimum quarterly contributions in the current and following plan years. PHI satisfied the minimum required contribution rules in 2008 and 2009 and does not expect to have any required contributions in 2010. Although PHI projects there will be no minimum funding requirement under the Pension Protection Act guidelines in 2010, PHI currently estimates it may make discretionary tax-deductible contributions in 2010 of approximately $100 million to bring its plan assets to at least the funding target level for 2010 under the Pension Protection Act.

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Cash Flow Activity

PHI’s cash flows for the three months ended March 31, 2010 and 2009 are summarized below:

	Cash (Use) Source
	2010			2009			Change
	(millions of dollars)
Operating Activities	$	67		$	126		$	(59	)
Investing Activities		(207	)		(180	)		(27	)
Financing Activities		132			250			(118	)
Net (decrease) increase in cash and cash equivalents	$	(8	)	$	196		$	(204	)

Operating Activities

Cash flows from operating activities during the three months ended March 31, 2010 and 2009 are summarized below:

	Cash (Use) Source
	2010			2009			Change
	(millions of dollars)
Net Income	$	36		$	45		$	(9	)
Non-cash adjustments to net income		86			107			(21	)
Changes in cash collateral related to derivative activities		(162	)		(258	)		96
Changes in other assets and liabilities		107			232			(125	)
Net cash from operating activities	$	67		$	126		$	(59	)

Net cash from operating activities was $59 million lower for the three months ended March 31, 2010, compared to the same period in 2009. A portion of this decrease is attributable to the 2009 release from restricted cash of $38 million related to the Mirant settlement and a 2009 Federal income tax refund received associated with the 2009 pension plan contributions which were deductible on the 2008 return. Partially offsetting these decreases is a year over year increase in cash from operating activities as a result of decreased collateral requirements of the Competitive Energy business in 2010 as compared to 2009.

Investing Activities

Cash flows from investing activities during the three months ended March 31, 2010 and 2009 are summarized below:

	Cash (Use) Source
	2010			2009			Change
	(millions of dollars)
Investment in property, plant and equipment	$	(208	)	$	(180	)	$	(28	)
Changes in restricted cash equivalents		2			—			2
Net other investing activities		(1	)		—			(1	)
Net cash used by investing activities	$	(207	)	$	(180	)	$	(27	)

Net cash used by investing activities increased $27 million for the three months ended March 31, 2010 compared to the same period in 2009. The increase was due primarily to a $28 million increase in capital expenditures, of which $19 million was attributable to Power Delivery and $9 million was attributable to Conectiv Energy. The increase in Power Delivery capital expenditures consisted primarily of costs associated with emergency restoration and Blueprint for the Future projects. The increase in Conectiv Energy capital expenditures was primarily due to the construction of new generating facilities.

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Financing Activities

Cash flows from financing activities during the three months ended March 31, 2010 and 2009 are summarized below:

	Cash (Use) Source
	2010			2009			Change
	(millions of dollars)
Dividends paid on common stock	$	(60	)	$	(59	)	$	(1	)
Common stock issued for the Dividend Reinvestment Plan		8			7			1
Issuance of common stock		7			8			(1	)
Issuances of long-term debt		23			110			(87	)
Reacquisition of long-term debt		(24	)		(58	)		34
Issuances of short-term debt, net		197			240			(43	)
Net other financing activities		(19	)		2			(21	)
Net cash from financing activities	$	132		$	250		$	(118	)

Net cash from financing activities decreased $118 million for the three months ended March 31, 2010, compared to the same period in 2009 primarily due to changes in outstanding long-term and short-term debt.

Changes in Outstanding Long-Term Debt

Cash flows from the issuance and reacquisitions of long-term debt for the three months ended March 31, 2010 and for the three months ended March 31, 2009 are summarized in the charts below:

	2010		2009
Issuances	(millions of dollars)
Pepco
6.2% Tax-exempt bonds due 2022 (a)	$	—	$	110
ACE
4.875% Tax-exempt bonds due 2029 (b)		23		—
Total issuances of long-term debt	$	23	$	110

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

(b) Consists of Pollution Control Revenue Refunding Bonds (ACE Bonds) issued by The Pollution Control Financing Authority of Salem County for the benefit of ACE that were purchased by ACE in 2008. In connection with the resale by ACE, the interest rate on the ACE Bonds was changed from an auction rate to a fixed rate. The ACE Bonds are secured by an outstanding series of senior notes issued by ACE, and the senior notes are in turn secured by a series of collateral first mortgage bonds issued by ACE. Both the senior notes and the collateral first mortgage bonds have maturity dates, optional and mandatory redemption provisions, interest rates and interest payment dates that are identical to the terms of the ACE Bonds. The payment by ACE of its obligations in respect of the ACE Bonds satisfies the corresponding payment obligations on the senior notes and collateral first mortgage bonds.

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	2010		2009
Reacquisitions	(millions of dollars)
Pepco
5.75% Tax-exempt bonds due 2010 (a)	$	16	$	—
6.25% Medium-term notes		—		50
		16		50
ACE
Securitization bonds due 2009-2010		8		8
Total reacquisition of long-term debt	$	24	$	58

(a) Consists of Pollution Control Revenue Refunding Bonds (Pepco 2010 Bonds) issued by Prince George’s County for the benefit of Pepco. The Pepco 2010 Bonds were secured by an outstanding series of collateral first mortgage bonds issued by Pepco. The collateral first mortgage bonds had maturity dates, optional and mandatory redemption provisions, interest rates and interest payment dates that were identical to the terms of the Pepco 2010 Bonds. Accordingly, the redemption of the Pepco 2010 Bonds at maturity was deemed to be a redemption of the collateral first mortgage bonds.

Changes in Short-Term Debt

Cash flows from the issuance of short-term debt decreased during the three months ended March 31, 2010 as compared to the same period in 2009, primarily due to borrowings under PHI’s credit facilities. At March 31, 2009, PHI had an outstanding loan of $150 million, and Pepco had an outstanding loan of $100 million. As of March 31, 2010, PHI and its utility subsidiaries were able to meet their short-term capital needs in the commercial paper market.

Proceeds from Settlement of Mirant Bankruptcy Claims

In the first quarter of 2009, Pepco recorded a pre-tax gain of $14 million reflecting the portion of the Mirant bankruptcy settlement proceeds attributed to the District of Columbia that were retained by Pepco after the allocation of such proceeds between Pepco and its District of Columbia customers.

Capital Requirements

Capital Expenditures

Pepco Holdings’ total capital expenditures for the three months ended March 31, 2010 totaled $208 million, of which $65 million was incurred by Pepco, $48 million was incurred by DPL, $38 million was incurred by ACE, $50 million was incurred by Conectiv Energy and $1 million was incurred by Pepco Energy Services. The remainder was incurred primarily by the PHI Service Company. The Power Delivery expenditures were primarily related to capital costs associated with new customer services, distribution reliability, and transmission.

Stimulus Funds Related to Blueprint for the Future

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

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

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

In April 2010, PHI and the DOE signed agreements formalizing the $168 million in awards. The money will help offset the cost to customers for installing meters and modernizing the electric grid.

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Of the $168 million, $130 million will offset Blueprint for the Future and other capital expenditures that the PHI subsidiaries are projected to incur. The remaining $38 million will be used to help offset ongoing expenses associated with direct load control and other Power Delivery programs.

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

Smart Grid Workforce Training Grant

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

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 (14) “Commitments and Contingencies,” to the consolidated financial statements of PHI included as Part I, Item 1, in this Form 10-Q.

Dividends

On April 22, 2010, Pepco Holdings’ Board of Directors declared a dividend on common stock of 27 cents per share payable June 30, 2010, to shareholders of record on June 10, 2010.

Energy Contract Net Asset Activity

The following table provides detail on changes in the net asset or liability position of the Competitive Energy business (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, 2010. The balances reflected in the table are stated gross, pre-tax and before the netting of collateral as required by Financial Accounting Standards Board (FASB) guidance on the offsetting of balance sheet accounts (Accounting Standards Codification (ASC) 210-20).

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	Energy Commodity Activities (a)
	(millions of dollars)
Total Fair Value of Energy Contract Net Liabilities at December 31, 2009	$	(328	)
Current period unrealized gains		2
Effective portion of changes in fair value – recorded in Accumulated Other Comprehensive Loss		(203	)
Cash flow hedge ineffectiveness – recorded in income		(6	)
Recognition of realized gains (losses) on settlement of contracts		90
Total Fair Value of Energy Contract Net Liabilities at March 31, 2010	$	(445	)
	Total
Detail of Fair Value of Energy Contract Net Liabilities at March 31, 2010 (see above)
Derivative assets (current assets)	$	52
Derivative assets (non-current assets)		70
Total Fair Value of Energy Contract Assets		122
Derivative liabilities (current liabilities)		(458	)
Derivative liabilities (non-current liabilities)		(109	)
Total Fair Value of Energy Contract Liabilities		(567	)
Total Fair Value of Energy Contract Net Liabilities	$	(445	)

Notes:

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

The $445 million net liability on energy contracts at March 31, 2010 was primarily attributable to losses on power swaps and natural gas futures and swaps designated as hedges of future energy purchases or production under FASB guidance on derivatives and hedging (ASC 815). Prices of electricity and natural gas declined during the first quarter of 2010, which resulted in unrealized losses on the energy contracts of the Competitive Energy business. Competitive Energy recorded unrealized losses of $203 million on energy contracts in Accumulated Other Comprehensive Loss as these energy contracts were effective hedges under the guidance. 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 business with their customers.

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

	Fair Value of Contracts at March 31, 2010 Maturities
Source of Fair Value	2010			2011			2012			2013 and Beyond			Total Fair Value
	(millions of dollars)
Energy Commodity Activities, net (a)
Actively Quoted (i.e., exchange-traded) prices	$	(125	)	$	(31	)	$	(19	)	$	(4	)	$	(179	)
Prices provided by other external sources (b)		(196	)		(43	)		(94	)		(7	)		(340	)
Modeled (c)		28			13			25			8			74
Total	$	(293	)	$	(61	)	$	(88	)	$	(3	)	$	(445	)

Notes:

(a) Includes all hedge activity and trading activities recorded at fair value through AOCL or on the Statements of Income, as required.

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

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

Contractual Arrangements with Credit Rating Triggers or Margining Rights

Under certain contractual arrangements entered into by PHI’s subsidiaries in connection with the Competitive Energy business and other transactions, the subsidiary may be required to 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, 2010, 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 $498 million, $313 million of which is the net settlement amount attributable to derivatives, normal purchase and normal sale contracts, collateral, and other contracts under master netting agreements as described in Note (12), “Derivative Instruments and Hedging Activities,” to the consolidated financial statements of PHI set forth in Part I, Item 1 of this Form 10-Q. The remaining $185 million of the collateral obligation that would be incurred in the event PHI was downgraded to below investment grade is attributable primarily to energy services contracts and accounts payable to independent system operators and distribution companies on full requirements contracts entered into by Pepco Energy Services. PHI believes that it and its utility subsidiaries currently have sufficient liquidity to fund their operations and meet their financial obligations.

Many of the contractual arrangements entered into by PHI’s subsidiaries in connection with Competitive Energy and Default Electricity Supply activities include margining rights pursuant to which the PHI subsidiary or a counterparty may request collateral if the market value of the contractual obligations reaches levels in excess of the credit thresholds established in the applicable arrangements. Pursuant to these margining rights, the affected PHI subsidiary may receive, or be required to post, collateral due to energy price movements. As of March 31, 2010, Pepco Holdings’ subsidiaries engaged in Competitive Energy activities and Default Electricity Supply activities provided net cash collateral in the amount of $517 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 (14) “Commitments and Contingencies,” to the consolidated financial statements of PHI set forth in Part I, Item 1 of this Form 10-Q.

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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, 2009. There have been no material changes to PHI’s critical accounting policies as disclosed in the Form 10-K.

New Accounting Standards and Pronouncements

For information concerning new accounting standards and pronouncements that have recently been adopted by PHI and its subsidiaries or that one or more of the companies will be required to adopt on or before a specified date in the future, see Note (3), “Newly Adopted Accounting Standards,” and Note (4), “Recently Issued Accounting Standards, Not Yet Adopted,” to the consolidated financial statements of PHI set forth in Part I, Item 1 of this Form 10-Q.

Forward-Looking Statements

Some of the statements contained in this Quarterly Report on Form 10-Q are forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and are subject to the safe harbor created by the Private Securities Litigation Reform Act of 1995. These statements include declarations regarding Pepco Holdings’ intents, beliefs and current expectations. In some cases, you can identify forward-looking statements by terminology such as “may,” “will,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “predicts,” “potential” or “continue” or the negative of such terms or 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 generating 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;

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• 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

Pepco meets the conditions set forth in General Instruction H to the Form 10-Q, and accordingly information otherwise required under this Item has been omitted.

General Overview

Potomac Electric Power Company (Pepco) is engaged in the transmission and distribution of electricity in the District of Columbia and major portions of Montgomery County and Prince George’s County in suburban Maryland. Pepco also provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its service territories who do not elect to purchase electricity from a competitive 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, 2010, approximately 59% of delivered electricity sales were to Maryland customers and approximately 41% were to the District of Columbia customers.

Effective June 2007, the Maryland Public Service Commission approved a bill stabilization adjustment mechanism (BSA) for retail customers. The District of Columbia Public Service Commission also approved a BSA for retail customers, effective in November 2009. For customers to whom the BSA applies, Pepco recognizes distribution revenue based on the approved distribution charge per customer. From a revenue recognition standpoint, this has the effect of decoupling distribution revenue recognized in a reporting period from the amount of power delivered during the period. As a consequence, the only factors that will cause distribution revenue in Maryland and the District of Columbia to fluctuate from period to period are changes in the number of customers and changes in the approved distribution charge per customer. For customers to whom the BSA applies, changes in customer usage (such as due to weather conditions, energy prices, energy efficiency programs or other reasons) from period to period have no impact on reported distribution revenue.

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

Pepco is a wholly owned subsidiary of Pepco Holdings, Inc. (PHI or Pepco Holdings). Because PHI is a public utility holding company subject to the Public Utility Holding Company Act of 2005 (PUHCA 2005), the relationship between PHI and Pepco and certain activities of Pepco are subject to the regulatory oversight of the Federal Energy Regulatory Commission under PUHCA 2005.

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Results Of Operations

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

Operating Revenue

	2010		2009		Change
Regulated T&D Electric Revenue	$	219	$	212	$	7
Default Electricity Supply Revenue		324		356		(32	)
Other Electric Revenue		9		9		—
Total Operating Revenue	$	552	$	577	$	(25	)

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

Regulated T&D Electric Revenue includes revenue from the 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) at rates regulated by the Federal Energy Regulatory Commission (FERC). Transmission rates are updated annually based on a FERC-approved formula methodology.

Default Electricity Supply Revenue is the revenue received from the supply of electricity by Pepco at regulated rates to retail customers who do not elect to purchase electricity from a competitive supplier, and which is also known as Standard Offer Service (SOS). 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	2010		2009		Change
Residential	$	62	$	60	$	2
Commercial and industrial		130		126		4
Other		27		26		1
Total Regulated T&D Electric Revenue	$	219	$	212	$	7

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

Regulated T&D Electric Sales (Gigawatt hours (GWh))	2010	2009	Change
Residential	2,252	2,193	59
Commercial and industrial	4,344	4,453	(109	)
Other	44	45	(1	)
Total Regulated T&D Electric Sales	6,640	6,691	(51	)
Regulated T&D Electric Customers (in thousands)	2010	2009	Change
Residential	709	695	14
Commercial and industrial	74	73	1
Other	—	—	—
Total Regulated T&D Electric Customers	783	768	15

Regulated T&D Electric Revenue increased by $7 million primarily due to:

• An increase of $3 million as a result of the implementation of the BSA in the District of Columbia that became effective in November 2009 (consisting of a positive $3 million Revenue Decoupling Adjustment after netting a $1 million reduction in distribution rates effective with the BSA implementation).

• An increase of $2 million due to customer growth of 2% in 2010, primarily in the residential class.

• An increase of $2 million in transmission service revenue in 2010 due to an accrual of the estimated true-up of the FERC formula-based rate, which will be reflected in future billings.

Default Electricity Supply

Default Electricity Supply Revenue	2010		2009		Change
Residential	$	240	$	239	$	1
Commercial and industrial		80		115		(35	)
Other		4		2		2
Total Default Electricity Supply Revenue	$	324	$	356	$	(32	)
Default Electricity Supply Sales (GWh)	2010		2009		Change
Residential		2,087		2,083		4
Commercial and industrial		777		1,073		(296	)
Other		3		3		—
Total Default Electricity Supply Sales		2,867		3,159		(292	)

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PEPCO

Default Electricity Supply Customers (in thousands)	2010	2009	Change
Residential	660	662	(2	)
Commercial and industrial	50	53	(3	)
Other Commercial and industrial	—	—	—
Total Default Electricity Supply Customers	710	715	(5	)

Default Electricity Supply Revenue decreased by $32 million primarily due to:

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

• A decrease of $6 million due to lower sales as a result of milder weather during the 2010 winter months as compared to 2009.

The aggregate amount of these decreases was partially offset by:

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

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

	2010		2009
Sales to District of Columbia customers	31	%	36	%
Sales to Maryland customers	52	%	55	%

Operating Expenses

Purchased Energy

Purchased Energy consists of the cost of electricity purchased by Pepco to fulfill its Default Electricity Supply obligation and, as such, is recoverable from customers in accordance with the terms of public service commission orders. Purchased Energy decreased by $34 million to $315 million in 2010 from $349 million in 2009 primarily due to:

• A decrease of $24 million primarily due to commercial customer migration to competitive suppliers.

• A decrease of $15 million in deferred electricity expense due to a lower rate of recovery of electricity supply costs.

• A decrease of $6 million due to lower sales as a result of milder weather during the 2010 winter months as compared to 2009.

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The aggregate amount of these decreases was partially offset by:

• An increase of $13 million due to higher average electricity costs under Default Electricity Supply contracts.

Other Operation and Maintenance

Other Operation and Maintenance increased by $9 million to $88 million in 2010 from $79 million in 2009 primarily due to:

• An increase of $11 million in emergency restoration costs largely driven by the February 2010 severe winter storms. A large portion of the costs of the restoration work relates to services provided by outside contractors and other utilities and billings for such services in most instances have not yet been received and have been estimated. Actual billings may vary significantly from the estimates of such billings.

The increase was partially offset by:

• A decrease of $3 million in regulatory expenses due to an adjustment for recoverable District of Columbia distribution rate case costs.

Effect of Settlement of Mirant Bankruptcy Claims

In the first quarter of 2009, Pepco recorded a pre-tax gain of $14 million reflecting the portion of the Mirant Corporation (Mirant) bankruptcy settlement proceeds attributed to the District of Columbia that were retained by Pepco after the allocation of such proceeds between Pepco and its District of Columbia customers.

Income Tax Expense

Pepco’s effective tax rates for the three months ended March 31, 2010 and 2009 were 42.9% and 42.4%, respectively. The increase in the rate primarily resulted from changes in estimates and interest relating to uncertain and effectively settled positions, partially offset by the effect of certain permanent and flow through tax differences as a percentage of pre-tax income.

Capital Requirements

Capital Expenditures

Pepco’s capital expenditures for the three months ended March 31, 2010, totaled $65 million. These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission.

Stimulus Funds Related to Blueprint for the Future

In 2009, the U.S. Department of Energy (DOE) announced a $168 million award to PHI under the American Recovery and Reinvestment Act of 2009 for the implementation of an advanced metering infrastructure system, direct load control, distribution automation, and communications infrastructure. The Pepco service territory in Maryland and the District of Columbia were awarded $105 million and $44 million, respectively, for a total of $149 million.

In April 2010, PHI and the DOE signed agreements formalizing Pepco’s share of the $168 million award. The money will help offset the cost to customers for installing meters and modernizing the electric grid.

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Of the $149 million, $118 million will offset Blueprint for the Future and other capital expenditures that Pepco is projected to incur. The remaining $31 million will be used to help offset ongoing expenses associated with direct load control and other programs.

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

Forward-Looking Statements

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

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 generating 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;

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• 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 unanticipated events. New factors emerge from time to time, and it is not possible for Pepco to predict all such factors, nor can Pepco assess the impact of any such factor on Pepco’s business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.

The foregoing review of factors should not be construed as exhaustive.

131

DPL

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

Delmarva Power & Light Company

DPL meets the conditions set forth in General Instruction H to the Form 10-Q, and accordingly information otherwise required under this Item has been omitted.

General Overview

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 service territories who do not elect to purchase electricity from a competitive supplier. Default Electricity Supply is known as Standard Offer Service in both Delaware and Maryland. DPL’s electricity distribution service territory covers approximately 5,000 square miles and has a population of approximately 1.3 million. As of March 31, 2010, approximately 64% of delivered electricity sales were to Delaware customers and approximately 36% were to Maryland customers. In northern Delaware, DPL also supplies and distributes natural gas to retail customers and provides transportation-only services to retail customers that purchase natural gas from other suppliers. DPL’s natural gas distribution service territory covers approximately 275 square miles and has a population of approximately 500,000.

Effective June 2007, the Maryland Public Service Commission approved a bill stabilization adjustment mechanism (BSA) for retail customers. For customers to whom 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 whom the BSA applies, changes in customer usage (such as due to weather conditions, energy prices, energy efficiency programs or other reasons) from period to period have no impact on reported distribution revenue.

DPL is a wholly owned subsidiary of Conectiv, which is wholly owned by Pepco Holdings, Inc. (PHI or Pepco Holdings). Because PHI is a public utility holding company subject to the Public Utility Holding Company Act of 2005 (PUHCA 2005), the relationship between PHI and DPL and certain activities of DPL are subject to the regulatory oversight of the Federal Energy Regulatory Commission under PUHCA 2005.

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Results Of Operations

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

Electric Operating Revenue

	2010		2009		Change
Regulated T&D Electric Revenue	$	87	$	91	$	(4	)
Default Electricity Supply Revenue		208		225		(17	)
Other Electric Revenue		4		5		(1	)
Total Electric Operating Revenue	$	299	$	321	$	(22	)

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

Regulated T&D Electric Revenue includes revenue from the 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) at rates regulated by the Federal Energy Regulatory Commission (FERC). Transmission rates are updated annually based on a FERC-approved formula methodology.

Default Electricity Supply Revenue is the revenue received from the supply of electricity by DPL at regulated rates to retail customers who do not elect to purchase electricity from a competitive supplier, which is also known as SOS service. 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	2010		2009		Change
Residential	$	48	$	45	$	3
Commercial and industrial		24		25		(1	)
Other		15		21		(6	)
Total Regulated T&D Electric Revenue	$	87	$	91	$	(4	)

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

Regulated T&D Electric Sales (Gigawatt hours (GWh))	2010	2009	Change
Residential	1,528	1,496	32
Commercial and industrial	1,683	1,807	(124	)
Other	12	12	—
Total Regulated T&D Electric Sales	3,223	3,315	(92	)

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Regulated T&D Electric Customers (in thousands)	2010	2009	Change
Residential	439	439	—
Commercial and industrial	59	59	—
Other	1	1	—
Total Regulated T&D Electric Customers	499	499	—

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

• A decrease of $3 million in transmission service revenue in 2010 due to an accrual of the estimated true-up of the FERC formula-based rate, which will be reflected in future billings.

• A decrease of $3 million in transmission service revenue primarily due to a transmission rate decrease in June 2009.

The aggregate amount of these decreases was partially offset by:

• An increase of $3 million due to a distribution rate increase in Maryland that became effective in December 2009.

Default Electricity Supply

Default Electricity Supply Revenue	2010		2009		Change
Residential	$	161	$	162	$	(1	)
Commercial and industrial		44		60		(16	)
Other		3		3		—
Total Default Electricity Supply Revenue	$	208	$	225	$	(17	)
Default Electricity Supply Sales (GWh)	2010		2009		Change
Residential		1,496		1,470		26
Commercial and industrial		465		578		(113	)
Other		10		11		(1	)
Total Default Electricity Supply Sales		1,971		2,059		(88	)
Default Electricity Supply Customers (in thousands)	2010		2009		Change
Residential		431		431		—
Commercial and industrial		47		48		(1	)
Other		1		1		—
Total Default Electricity Supply Customers		479		480		(1	)

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Default Electricity Supply Revenue decreased by $17 million primarily due to:

• A decrease of $15 million due to lower sales, primarily as a result of Delaware commercial and Maryland residential customer migration to competitive suppliers.

• A decrease of $7 million as a result of lower Default Electricity Supply rates.

• A decrease of $6 million due to lower sales as a result of milder weather during the 2010 winter months as compared to 2009.

The aggregate amount of these decreases was partially offset by:

• An increase of $12 million due to higher non-weather related average customer usage.

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

	2010		2009
Sales to Delaware customers	56	%	58	%
Sales to Maryland customers	70	%	71	%

Natural Gas Operating Revenue

	2010		2009		Change
Regulated Gas Revenue	$	87	$	119	$	(32	)
Other Gas Revenue		8		12		(4	)
Total Natural Gas Operating Revenue	$	95	$	131	$	(36	)

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

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Regulated Gas

Regulated Gas Revenue	2010		2009		Change
Residential	$	55	$	75	$	(20	)
Commercial and industrial		30		42		(12	)
Transportation and other		2		2		—
Total Regulated Gas Revenue	$	87	$	119	$	(32	)
Regulated Gas Sales (billion cubic feet)	2010		2009		Change
Residential		4		4		—
Commercial and industrial		2		3		(1	)
Transportation and other		2		2		—
Total Regulated Gas Sales		8		9		(1	)
Regulated Gas Customers (in thousands)	2010		2009		Change
Residential		114		114		—
Commercial and industrial		9		9		—
Transportation and other		—		—		—
Total Regulated Gas Customers		123		123		—

Regulated Gas Revenue decreased by $32 million primarily due to:

• A decrease of $23 million due to lower sales as a result of milder weather during the 2010 winter months as compared to 2009.

• A decrease of $16 million due to the Gas Cost Rate decreases effective March 2009 and November 2009.

• A decrease of $8 million (which is offset by a corresponding decrease in Gas Purchased) associated with an adjustment in 2009 to recognize the unbilled portion of Gas Cost Rate revenue, which prior to 2009 had not previously been recognized.

The aggregate amount of these decreases was partially offset by:

• An increase of $15 million due to higher non-weather related average customer usage.

Other Gas Revenue

Other Gas Revenue decreased by $4 million primarily due to lower revenue from off-system sales as a result of lower demand from electric generators and gas marketers.

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DPL

Operating Expenses

Purchased Energy

Purchased Energy consists of the cost of electricity purchased by DPL to fulfill its Default Electricity Supply obligation and, as such, is recoverable from customers in accordance with the terms of public service commission orders. Purchased Energy decreased by $18 million to $201 million in 2010 from $219 million in 2009 primarily due to:

• A decrease of $7 million in deferred electricity expense due to a lower rate of recovery of electricity supply costs.

• A decrease of $6 million due to lower sales as a result of milder weather during the 2010 winter months as compared to 2009.

• A decrease of $3 million due to lower average electricity costs under Default Electricity Supply contracts.

Gas Purchased

Gas Purchased consists of the cost of gas purchased by DPL to fulfill its obligation to regulated gas customers and, as such, is recoverable from customers in accordance with the terms of public service commission orders. It also includes the cost of gas purchased for off-system sales. Total Gas Purchased decreased by $35 million to $66 million in 2010 from $101 million in 2009 primarily due to:

• A decrease of $14 million in deferred gas expense as a result of a higher rate of recovery of natural gas supply costs in 2009 due to the recognition of the unbilled portion of Gas Cost Rate revenue, as discussed under Regulated Gas Revenue.

• A decrease of $10 million from the settlement of financial hedges entered into as part of DPL’s hedge program for regulated natural gas.

• A decrease of $7 million in the cost of gas purchased for regulated sales as a result of a lower average cost of gas withdrawn from storage.

• A decrease of $4 million in the cost of gas purchased for off-system sales, primarily as a result of lower volumes purchased.

Other Operation and Maintenance

Other Operation and Maintenance increased by $2 million to $61 million in 2010 from $59 million in 2009 primarily due to an increase of $3 million in emergency restoration costs largely driven by the February 2010 severe winter storms. A large portion of the costs of the restoration work relates to services provided by outside contractors and other utilities and billings for such services in most instances have not yet been received and have been estimated. Actual billings may vary significantly from the estimates of such billings.

Income Tax Expense

DPL’s effective tax rates for the three months ended March 31, 2010 and 2009 were 48.2 % and 36.4%, respectively. The increase in the rate primarily resulted from an increase in changes in estimates and interest related to uncertain and effectively settled tax positions, primarily related to a $2 million reversal of accrued interest income on state income tax positions that DPL no longer believes is more likely than not to be realized.

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Capital Requirements

Capital Expenditures

DPL’s capital expenditures for the three months ended March 31, 2010, totaled $48 million. These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission.

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 generating 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 DPL’s business and profitability;

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

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• 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.

139

ACE

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

Atlantic City Electric Company

ACE meets the conditions set forth in General Instruction H to the Form 10-Q, and accordingly information otherwise required under this Item has been omitted.

General Overview

Atlantic City Electric Company (ACE) is engaged in the transmission and distribution of electricity in southern New Jersey. ACE also provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its service territory who do not elect to purchase electricity from a competitive supplier. Default Electricity Supply is also known as Basic Generation Service 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, 2010 to the three months ended March 31, 2009. All amounts in the tables (except sales and customers) are in millions of dollars.

Operating Revenue

	2010		2009		Change
Regulated T&D Electric Revenue	$	91	$	84	$	7
Default Electricity Supply Revenue		223		255		(32	)
Other Electric Revenue		3		5		(2	)
Total Operating Revenue	$	317	$	344	$	(27	)

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

Regulated T&D Electric Revenue includes revenue from the 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) at rates regulated by the Federal Energy Regulatory Commission (FERC). Transmission rates are updated annually based on a FERC-approved formula methodology.

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ACE

Default Electricity Supply Revenue is the revenue received from the supply of electricity by ACE at regulated rates to retail customers who do not elect to purchase electricity from a competitive supplier, and which is also known as Basic Generation Service. The costs related to Default Electricity Supply are included in Purchased Energy. Default Electricity 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.

Regulated T&D Electric

Regulated T&D Electric Revenue	2010		2009		Change
Residential	$	39	$	39	$	—
Commercial and industrial		29		29		—
Other		23		16		7
Total Regulated T&D Electric Revenue	$	91	$	84	$	7

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

Regulated T&D Electric Sales (Gigawatt hours (GWh))	2010	2009	Change
Residential	1,097	1,085	12
Commercial and industrial	1,174	1,233	(59	)
Other	12	13	(1	)
Total Regulated T&D Electric Sales	2,283	2,331	(48	)
Regulated T&D Electric Customers (in thousands)	2010	2009	Change
Residential	482	481	1
Commercial and industrial	65	65	—
Other	1	1	—
Total Regulated T&D Electric Customers	548	547	1

Regulated T&D Electric Revenue increased by $7 million primarily due to:

• An increase of $3 million in transmission service revenue primarily due to a transmission rate increase in June 2009.

• An increase of $3 million in transmission service revenue in 2010 due to an accrual of the estimated true-up of the FERC formula-based rate, which will be reflected in future billings.

Default Electricity Supply

Default Electricity Supply Revenue	2010		2009		Change
Residential	$	120	$	116	$	4
Commercial and industrial		55		85		(30	)
Other		48		54		(6	)
Total Default Electricity Supply Revenue	$	223	$	255	$	(32	)

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ACE

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

Default Electricity Supply Sales (GWh)	2010	2009	Change
Residential	1,097	1,085	12
Commercial and industrial	513	821	(308	)
Other	12	13	(1	)
Total Default Electricity Supply Sales	1,622	1,919	(297	)
Default Electricity Supply Customers (in thousands)	2010	2009	Change
Residential	482	481	1
Commercial and industrial	61	65	(4	)
Other	1	1	—
Total Default Electricity Supply Customers	544	547	(3	)

Default Electricity Supply Revenue decreased by $32 million primarily due to:

• A decrease of $25 million due to lower sales, primarily as a result of commercial customer migration to competitive suppliers.

• A decrease of $9 million in wholesale energy and capacity revenues primarily due to the sale of lower volumes of electricity purchased from NUGs.

For the three months ended March 31, 2010 and 2009, the percentage of ACE’s total distribution sales that are derived from customers receiving Default Electricity Supply are 71% and 82%, respectively.

Operating Expenses

Purchased Energy

Purchased Energy consists of the cost of electricity purchased by ACE to fulfill its Default Electricity Supply obligation and, as such, is recoverable from customers in accordance with the terms of public service commission orders. Purchased Energy decreased by $42 million to $235 million in 2010 from $277 million in 2009 primarily due to commercial customer migration to competitive suppliers.

Other Operation and Maintenance

Other Operation and Maintenance increased by $2 million to $50 million in 2010 from $48 million in 2009 primarily due to an increase of $3 million in emergency restoration costs largely driven by the February 2010 severe winter storms. A large portion of the costs of the restoration work relates to services provided by outside contractors and other utilities and billings for such services in most instances have not yet been received and have been estimated. Actual billings may vary significantly from the estimates of such billings.

Deferred Electric Service Costs

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

142

ACE

Deferred Electric Service Costs increased by $8 million, to an expense reduction of $19 million in 2010 as compared to an expense reduction of $27 million in 2009, primarily due to an increase in deferred electricity expense due to a higher rate of recovery of electricity supply costs.

Income Tax Expense

ACE’s consolidated effective tax rate for the three months ended March 31, 2010 was 140%. ACE’s income before income tax for the three months ended March 31, 2009 was less than $1 million; therefore the consolidated effective tax rate is not meaningful. The primary item impacting the 2010 effective tax rate was the reversal of $6 million of accrued interest income on uncertain and effectively settled state income tax positions, as discussed in Note 2, “Significant Accounting Policies.”

Capital Requirements

Capital Expenditures

ACE’s capital expenditures for the three months ended March 31, 2010, totaled $38 million. These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission.

Stimulus Funds Related to Blueprint for the Future

In 2009, the U.S. Department of Energy (DOE) announced a $168 million award to PHI under the American Recovery and Reinvestment Act of 2009 for the implementation of direct load control, distribution automation, and communications infrastructure in ACE’s service territory. Under the award, ACE is to receive $19 million.

In April 2010, PHI and the DOE signed agreements formalizing ACE’s share of the $168 million award. The money will help offset the cost to customers for installing meters and modernizing the electric grid.

Of the $19 million, $12 million will offset Blueprint for the Future and other capital expenditures that ACE is projected to incur. The remaining $7 million will be used to help offset ongoing expenses associated with direct load control and other programs.

143

ACE

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

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 generating 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 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.

144

ACE

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.

145

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,” Note (15), “Derivative Instruments and 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, 2009.

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 based on Financial Accounting Standards Board (FASB) guidance on derivatives and hedging (ASC 815). 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 generating facilities and the revenue received from the sale of the power produced by those facilities by selling forward a portion of their projected generating facility output and buying forward a portion of their projected fuel supply requirements 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 business’ 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. In January 2009, PHI changed its VaR estimation model from a delta-normal variance / covariance model to a delta-gamma model. The other parameters, a 95 percent, one-tailed confidence level and a one-day holding period, remained the same. Since VaR is an estimate, it is not necessarily indicative of actual results that may occur. The table below provides the VaR associated with energy contracts for the three months ended March 31, 2010 in millions of dollars:

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

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

146

Conectiv Energy economically hedges both the estimated generating facility output and fuel requirements as the estimated levels of output and fuel needs change. Economic hedges include the estimated electricity output of Conectiv Energy’s generating facilities and any associated financial or physical commodity contracts (including derivative contracts that are classified as cash flow hedges, other derivative instruments, wholesale normal purchase and normal sales contracts, and default electricity supply contracts).

Conectiv Energy maintains a forward 36 month program for economically hedging its projected generating facility output combined with its energy purchase commitments. During the fourth quarter of 2009, Conectiv Energy transitioned to the use of dynamic spread option models to capture the value of its generation portfolio. The model computes the probability of run-time derived from forward market prices for power and fuel, and then computes the desired hedge positions, over the next 36 months. Conectiv executes power and fuel hedges according to the model’s projections based on forward market prices and volatilities. The primary purpose of the risk management program is to improve the predictability and stability of margins by selling forward a portion of projected generating facility output, and buying forward a matched portion of projected fuel supply requirements. As discussed in Note (15), “Subsequent Event,” to the consolidated financial statements of PHI, set forth in Item 1 of this Form 10-Q, the plan for disposition of Conectiv Energy requires modification of the economic hedging program by reducing the term of the hedges to cover only the expected generating facility output until the target closing date of the sale transaction.

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 due to market liquidity.

Since the inception of the Reliability Pricing Model (RPM) in PJM, Conectiv Energy has taken steps to ensure a reasonable return on its generating capacity. Prior to the commencement of the first RPM auction for the 2007-2008 PJM planning year, Conectiv Energy sold a portion of its capacity forward into the over-the-counter market. Conectiv Energy continues to sell some of its capacity into the forward market when it believes prices are favorable. Conectiv Energy also reserves some of its capacity to serve full requirements load within PJM. Conectiv Energy recovers the value of this capacity by including it in the price offered for the bundled load service in individual load auctions.

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 normal sale accounting under FASB guidance on derivatives and hedging.

147

Credit and Nonperformance Risk

The following table provides information on the Competitive Energy business’ credit exposure on competitive wholesale energy contracts, net of collateral, to wholesale counterparties as of March 31, 2010, in 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	$	317	$	2	$	315	4	$	230
Non-Investment Grade		5		—		5	—		—
No External Ratings		21		7		14	—		—
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.

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, 2009.

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, 2010, and, based upon this evaluation, the chief executive officer and the chief financial officer of Pepco Holdings have concluded that these controls and procedures are effective to provide reasonable assurance that material information relating to Pepco Holdings and its subsidiaries that is required to be disclosed in reports filed with, or submitted to, the Securities and Exchange Commission (SEC) under the Securities Exchange Act of 1934, as amended (the Exchange Act) (i) is recorded, processed, summarized and reported within the time periods specified by the SEC rules and forms and (ii) is accumulated and communicated to management, including its chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

148

Changes in Internal Control Over Financial Reporting

During the three months ended March 31, 2010, there was no change in Pepco Holdings’ internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, Pepco Holdings’ internal controls over financial reporting.

In February 2010, PHI’s regulated subsidiary, Pepco, completed the transition that allows its customers to view and pay their bills on-line. Previously, Pepco’s processing of electronic payments was outsourced. This transition completes the implementation of an application that allows for in-house processing of electronic payments for customers of Pepco as well as for PHI’s other regulated subsidiaries, ACE and DPL.

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, 2010, and, based upon this evaluation, the chief executive officer and the chief financial officer of Pepco have concluded that these controls and procedures are effective to provide reasonable assurance that material information relating to Pepco that is required to be disclosed in reports filed with, or submitted to, the SEC under the Exchange Act (i) is recorded, processed, summarized and reported within the time periods specified by the SEC rules and forms and (ii) is accumulated and communicated to management, including its chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

During the three months ended March 31, 2010, there was no change in Pepco’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, Pepco’s internal controls over financial reporting.

In February 2010, Pepco completed the transition to an in-house process that allows its customers to view and pay their bills on-line. Previously, processing of electronic payments was outsourced.

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, 2010, and, based upon this evaluation, the chief executive officer and the chief financial officer of DPL have concluded that these controls and procedures are effective to provide reasonable assurance that material information relating to DPL that is required to be disclosed in reports filed with, or submitted to, the SEC under the Exchange Act (i) is recorded, processed, summarized and reported within the time periods specified by the SEC rules and forms and (ii) is accumulated and communicated to management, including its chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

During the three months ended March 31, 2010, there was no change in DPL’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, DPL’s internal controls over financial reporting.

149

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, 2010, and, based upon this evaluation, the chief executive officer and the chief financial officer of ACE have concluded that these controls and procedures are effective to provide reasonable assurance that material information relating to ACE and its subsidiaries that is required to be disclosed in reports filed with, or submitted to, the SEC under the Exchange Act (i) is recorded, processed, summarized and reported within the time periods specified by the SEC rules and forms and (ii) is accumulated and communicated to management, including its chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

During the three months ended March 31, 2010, there was no change in ACE’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, ACE’s internal controls over financial reporting.

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 (14), “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 consolidated 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, 2009.

150

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

Pepco Holdings

None.

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

Item 3. DEFAULTS UPON SENIOR SECURITIES

Pepco Holdings

None.

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

Item 4. RESERVED

Item 5. OTHER INFORMATION

Pepco Holdings

None.

Pepco

None.

DPL

None.

ACE

None.

151

Item 6. EXHIBITS

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

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
12.1	PHI	Statements Re: Computation of Ratios	Filed herewith.
12.2	Pepco	Statements Re: Computation of Ratios	Filed herewith.
12.3	DPL	Statements Re: Computation of Ratios	Filed herewith.
12.4	ACE	Statements Re: Computation of Ratios	Filed herewith.
31.1	PHI	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	Filed herewith.
31.2	PHI	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	Filed herewith.
31.3	Pepco	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	Filed herewith.
31.4	Pepco	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	Filed herewith.
31.5	DPL	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	Filed herewith.
31.6	DPL	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	Filed herewith.
31.7	ACE	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	Filed herewith.
31.8	ACE	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	Filed herewith.
32.1	PHI	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	Furnished herewith.
32.2	Pepco	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	Furnished herewith.
32.3	DPL	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	Furnished herewith.
32.4	ACE	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	Furnished herewith.
101. INS	PHI, Pepco, DPL, ACE	XBRL Instance Document	Exhibit 101.INS to PHI’s Form 10-Q, 5/7/10.
101. SCH	PHI, Pepco, DPL, ACE	XBRL Taxonomy Extension Schema Document	Exhibit 101.SCH to PHI’s Form 10-Q, 5/7/10.
101. CAL	PHI, Pepco, DPL, ACE	XBRL Taxonomy Extension Calculation Linkbase Document	Exhibit 101.CAL to PHI’s Form 10-Q, 5/7/10.
101. DEF	PHI, Pepco, DPL, ACE	XBRL Taxonomy Extension Definition Linkbase Document	Exhibit 101.DEF to PHI’s Form 10-Q, 5/7/10.
101. LAB	PHI, Pepco, DPL, ACE	XBRL Taxonomy Extension Label Linkbase Document	Exhibit 101.LAB to PHI’s Form 10-Q, 5/7/10.
101. PRE	PHI, Pepco, DPL, ACE	XBRL Taxonomy Extension Presentation Linkbase Document	Exhibit 101.PRE to PHI’s Form 10-Q, 5/7/10.

152

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, 2010	By	/s/    A.J. KAMERICK
		Anthony J. Kamerick
		Senior Vice President and Chief Financial Officer, PHI, Pepco and DPL Chief Financial Officer, ACE

153

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

154

EX-12.1

Exhibit 12.1

Pepco Holdings, Inc.

	Three  Months Ended March 31, 2010			For the Year Ended December 31,
				2009			2008			2007			2006			2005
	(millions of dollars)
Income before extraordinary item (a)	$	37		$	233		$	305		$	324		$	245		$	369
Income tax expense (b)		31			110			168			188			161			255
Fixed charges:
Interest on long-term debt, amortization of discount, premium and expense		90			382			341			348			343			341
Other interest		6			23			24			25			19			20
Preferred dividend requirements of subsidiaries		—			—			—			—			1			3
Total fixed charges		96			405			365			373			363			364
Non-utility capitalized interest		(1	)		(4	)		(6	)		(2	)		(1	)		(1	)
Income before extraordinary item, income tax expense, fixed charges and non-utility capitalized interest	$	163		$	744		$	832		$	883		$	768		$	987
Total fixed charges, shown above		96			405			365			373			363			364
Increase preferred stock dividend requirements of subsidiaries to a pre-tax amount		—			—			—			—			1			2
Fixed charges for ratio computation	$	96		$	405		$	365		$	373		$	364		$	366
Ratio of earnings to fixed charges and preferred dividends		1.70			1.84			2.28			2.36			2.11			2.70

(a) Excludes income/losses from equity investments.

(b) Concurrent with the adoption of FASB guidance on taxes (ASC 740) in 2007, amount includes interest on uncertain tax positions.

EX-12.2

Exhibit 12.2

Potomac Electric Power Company

	Three  Months Ended March 31, 2010		For the Year Ended December 31,
			2009		2008		2007		2006		2005
	(millions of dollars)
Net income	$	8	$	106	$	116	$	125	$	85	$	165
Income tax expense (a)		6		76		64		62		58		128
Fixed charges:
Interest on long-term debt, amortization of discount, premium and expense		25		103		95		86		77		83
Other interest		3		11		11		12		13		14
Total fixed charges		28		114		106		98		90		97
Income before income tax expense, and fixed charges	$	42	$	296	$	286	$	285	$	233	$	390
Ratio of earnings to fixed charges		1.50		2.60		2.70		2.91		2.59		4.04
Total fixed charges, shown above		28		114		106		98		90		97
Preferred dividend requirements, adjusted to a pre-tax amount		—		—		—		—		2		2
Total fixed charges and preferred dividends	$	28	$	114	$	106	$	98	$	92	$	99
Ratio of earnings to fixed charges and preferred dividends		1.50		2.60		2.70		2.91		2.54		3.94

(a) Concurrent with the adoption of FASB guidance on taxes (ASC 740) in 2007, amount includes interest on uncertain tax positions.

EX-12.3

Exhibit 12.3

Delmarva Power & Light Company

	Three  Months Ended March 31, 2010		For the Year Ended December 31,
			2009		2008		2007		2006		2005
	(millions of dollars)
Net income	$	14	$	52	$	68	$	45	$	43	$	75
Income tax expense (a)		13		16		45		37		32		58
Fixed charges:
Interest on long-term debt, amortization of discount, premium and expense		11		45		41		44		41		35
Other interest		1		2		2		2		3		3
Total fixed charges		12		47		43		46		44		38
Income before income tax expense, and fixed charges	$	39	$	115	$	156	$	128	$	119	$	171
Ratio of earnings to fixed charges		3.25		2.45		3.63		2.78		2.70		4.48
Total fixed charges, shown above		12		47		43		46		44		38
Preferred dividend requirements, adjusted to a pre-tax amount		—		—		—		—		1		2
Total fixed charges and preferred dividends	$	12	$	47	$	43	$	46	$	45	$	40
Ratio of earnings to fixed charges and preferred dividends		3.25		2.45		3.63		2.78		2.62		4.28

(a) Concurrent with the adoption of FASB guidance on taxes (ASC 740) in 2007, amount includes interest on uncertain tax positions.

EX-12.4

Exhibit 12.4

Atlantic City Electric Company

	Three  Months Ended March 31, 2010			For the Year Ended December 31,
				2009		2008		2007		2006		2005
	(millions of dollars)
(Loss) income from continuing operations	$	(2	)	$	41	$	64	$	60	$	60	$	51
Income tax expense (a)		7			17		30		41		33		41
Fixed charges:
Interest on long-term debt, amortization of discount, premium and expense		16			69		64		66		65		60
Other interest		1			3		3		3		3		4
Total fixed charges		17			72		67		69		68		64
Income before extraordinary item, income tax expense, and fixed charges	$	22		$	130	$	161	$	170	$	161	$	156
Ratio of earnings to fixed charges		1.29			1.81		2.40		2.46		2.37		2.45
Total fixed charges, shown above		17			72		67		69		68		64
Preferred dividend requirements adjusted to a pre-tax amount		—			—		—		1		1		1
Total fixed charges and preferred dividends	$	17		$	72	$	67	$	70	$	69	$	65
Ratio of earnings to fixed charges and preferred dividends		1.29			1.81		2.40		2.44		2.35		2.43

(a) Concurrent with the adoption of FASB guidance on taxes (ASC 740) in 2007, amount includes interest on uncertain tax positions.

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Joseph M. Rigby, certify that:

1. I have reviewed this report on Form 10-Q of Pepco Holdings, Inc.

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal controls over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 7, 2010	/s/    JOSEPH M. RIGBY
	Joseph M. Rigby
	Chairman of the Board, President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Anthony J. Kamerick, certify that:

1. I have reviewed this report on Form 10-Q of Pepco Holdings, Inc.

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal controls over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 7, 2010	/s/    A.J. KAMERICK
	Anthony J. Kamerick
	Senior Vice President and Chief Financial Officer

EX-31.3

Exhibit 31.3

CERTIFICATION

I, David M. Velazquez, certify that:

1. I have reviewed this report on Form 10-Q of Potomac Electric Power Company.

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 7, 2010	/s/    DAVID M. VELAZQUEZ
	David M. Velazquez
	President and Chief Executive Officer

EX-31.4

Exhibit 31.4

CERTIFICATION

I, Anthony J. Kamerick, certify that:

1. I have reviewed this report on Form 10-Q of Potomac Electric Power Company.

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 7, 2010	/s/    A.J. KAMERICK
	Anthony J. Kamerick
	Senior Vice President and Chief Financial Officer

EX-31.5

Exhibit 31.5

CERTIFICATION

I, David M. Velazquez, certify that:

1. I have reviewed this report on Form 10-Q of Delmarva Power & Light Company.

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 7, 2010	/s/    DAVID M. VELAZQUEZ
	David M. Velazquez
	President and Chief Executive Officer

EX-31.6

Exhibit 31.6

CERTIFICATION

I, Anthony J. Kamerick, certify that:

1. I have reviewed this report on Form 10-Q of Delmarva Power & Light Company.

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 7, 2010	/s/    A.J. KAMERICK
	Anthony J. Kamerick
	Senior Vice President and Chief Financial Officer

EX-31.7

Exhibit 31.7

CERTIFICATION

I, David M. Velazquez, certify that:

1. I have reviewed this report on Form 10-Q of Atlantic City Electric Company.

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 7, 2010	/s/    DAVID M. VELAZQUEZ
	David M. Velazquez
	President and Chief Executive Officer

EX-31.8

Exhibit 31.8

CERTIFICATION

I, Anthony J. Kamerick, certify that:

1. I have reviewed this report on Form 10-Q of Atlantic City Electric Company.

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 7, 2010	/s/    A.J. KAMERICK
	Anthony J. Kamerick
	Chief Financial Officer

EX-32.1

Exhibit 32.1

Certificate of Chief Executive Officer and Chief Financial Officer

of

Pepco Holdings, Inc.

(pursuant to 18 U.S.C. Section 1350)

I, Joseph M. Rigby, and I, Anthony J. Kamerick, certify that, to the best of my knowledge, (i) the Quarterly Report on Form 10-Q of Pepco Holdings, Inc. for the quarter ended March 31, 2010, filed with the Securities and Exchange Commission on the date hereof fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Pepco Holdings, Inc.

May 7, 2010	/s/    JOSEPH M. RIGBY
	Joseph M. Rigby
	Chairman of the Board, President and Chief Executive Officer
May 7, 2010	/s/    A.J. KAMERICK
	Anthony J. Kamerick
	Senior Vice President and Chief Financial Officer

A signed original of this written statement required by Section 906 has been provided to Pepco Holdings, Inc. and will be retained by Pepco Holdings, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

Certificate of Chief Executive Officer and Chief Financial Officer

of

Potomac Electric Power Company

(pursuant to 18 U.S.C. Section 1350)

I, David M. Velazquez, and I, Anthony J. Kamerick, certify that, to the best of my knowledge, (i) the Quarterly Report on Form 10-Q of Potomac Electric Power Company for the quarter ended March 31, 2010, filed with the Securities and Exchange Commission on the date hereof fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Potomac Electric Power Company.

May 7, 2010	/s/    DAVID M. VELAZQUEZ
	David M. Velazquez
	President and Chief Executive Officer
May 7, 2010	/s/    A.J. KAMERICK
	Anthony J. Kamerick
	Senior Vice President and Chief Financial Officer

A signed original of this written statement required by Section 906 has been provided to Potomac Electric Power Company and will be retained by Potomac Electric Power Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.3

Exhibit 32.3

Certificate of Chief Executive Officer and Chief Financial Officer

of

Delmarva Power & Light Company

(pursuant to 18 U.S.C. Section 1350)

I, David M. Velazquez, and I, Anthony J. Kamerick, certify that, to the best of my knowledge, (i) the Quarterly Report on Form 10-Q of Delmarva Power & Light Company for the quarter ended March 31, 2010, filed with the Securities and Exchange Commission on the date hereof fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Delmarva Power & Light Company.

May 7, 2010	/s/    DAVID M. VELAZQUEZ
	David M. Velazquez
	President and Chief Executive Officer
May 7, 2010	/s/    A.J. KAMERICK
	Anthony J. Kamerick
	Senior Vice President and Chief Financial Officer

A signed original of this written statement required by Section 906 has been provided to Delmarva Power & Light Company and will be retained by Delmarva Power & Light Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.4

Exhibit 32.4

Certificate of Chief Executive Officer and Chief Financial Officer

of

Atlantic City Electric Company

(pursuant to 18 U.S.C. Section 1350)

I, David M. Velazquez, and I, Anthony J. Kamerick, certify that, to the best of my knowledge, (i) the Quarterly Report on Form 10-Q of Atlantic City Electric Company for the quarter ended March 31, 2010, filed with the Securities and Exchange Commission on the date hereof fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Atlantic City Electric Company.

May 7, 2010	/s/    DAVID M. VELAZQUEZ
	David M. Velazquez
	President and Chief Executive Officer
May 7, 2010	/s/    A.J. KAMERICK
	Anthony J. Kamerick
	Chief Financial Officer

A signed original of this written statement required by Section 906 has been provided to Atlantic City Electric Company and will be retained by Atlantic City Electric Company and furnished to the Securities and Exchange Commission or its staff upon request.