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 June 30, 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 June 30, 2010
Pepco Holdings	223,889,619 ($.01 par value)
Pepco	100 ($.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	106
Item 3.	- Quantitative and Qualitative Disclosures About Market Risk	165
Item 4.	- Controls and Procedures	167
PART II	OTHER INFORMATION	169
Item 1.	- Legal Proceedings	169
Item 1A	- Risk Factors	169
Item 2.	- Unregistered Sales of Equity Securities and Use of Proceeds	175
Item 3.	- Defaults Upon Senior Securities	175
Item 4.	- Reserved	175
Item 5.	- Other Information	175
Item 6.	- Exhibits	176
Signatures		177

GLOSSARY OF TERMS

Term	Definition
ACE	Atlantic City Electric Company
ACE Funding	Atlantic City Electric Transition Funding LLC
ADITC	Accumulated deferred investment tax credits
Ancillary services	Generally, electricity generation reserves and reliability services
AOCL	Accumulated other comprehensive loss
ASC	Accounting Standards Codification
BGS	Basic Generation Service (the supply of electricity by ACE to retail customers in New Jersey who have not elected to purchase electricity from a competitive supplier)
Bondable Transition Property	The principal and interest payments on the Transition Bonds and related taxes, expenses and fees
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 Morgan Stanley Bank, N.A. and Credit Suisse AG, Cayman Islands Branch, as the lenders, and Morgan Stanley Senior Funding, Inc., as administrative agent
BSA	Bill Stabilization Adjustment
Calpine	Calpine Corporation
CERCLA	Comprehensive Environmental Response, Compensation, and Liability Act of 1980
Conectiv	A wholly owned subsidiary of PHI and the parent of DPL and ACE
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
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
Energy Services	Energy savings performance contracting services principally to federal, state and local government customers, and designing, constructing and operating combined heat and power, and central energy plants by Pepco Energy Services
EPA	U.S. Environmental Protection Agency
EPS	Earnings per share
Exchange Act	Securities Exchange Act of 1934, as amended
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission

i

Term	Definition
FHACA	Flood Hazard Area Control Act
GAAP	Accounting principles generally accepted in the United States of America
GCR	Gas Cost Rate
GWh	Gigawatt hour
Heating Degree Days	Daily difference in degrees by which the mean (high and low divided by 2) dry bulb temperature is below a base of 65 degrees Fahrenheit
IRS	Internal Revenue Service
ISDA	International Swaps and Derivatives Association
ISRA	New Jersey’s Industrial Site Recovery Act
Lenders	Morgan Stanley Bank, N.A. and Credit Suisse AG, Cayman Islands Branch, the lenders for the Bridge Loan Facility
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.
MWh	Megawatt hours
New Jersey Societal Benefit Programs	Various NJBPU - mandated social programs for which ACE receives revenues to recover costs
NJBPU	New Jersey Board of Public Utilities
NJDEP	New Jersey Department of Environmental Protection
Normalization provisions	Sections of the Internal Revenue Code and related regulations that dictate how excess deferred income taxes resulting from the corporate income tax rate reduction enacted by the Tax Reform Act of 1986 and accumulated deferred investment tax credits should be treated for ratemaking purposes
NUGs	Non-utility generators
NYMEX	New York Mercantile Exchange
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
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
QSPE	Qualifying special purpose entity
RAR	IRS revenue agent’s report
RARC	Regulatory Asset Recovery Charge
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)
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
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 (Loss)	2	55	71	91
Consolidated Statements of Comprehensive Income	3	N/A	N/A	N/A
Consolidated Balance Sheets	4	56	72	92
Consolidated Statements of Cash Flows	6	58	74	94
Notes to Consolidated Financial Statements	7	59	75	95

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 (LOSS)

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
	(millions of dollars, except per share data)
Operating Revenue
Power Delivery	$	1,149		$	1,095		$	2,411		$	2,467
Pepco Energy Services		476			560			1,023			1,217
Other		11			11			21			19
Total Operating Revenue		1,636			1,666			3,455			3,703
Operating Expenses
Fuel and purchased energy		1,077			1,186			2,377			2,725
Other services cost of sales		35			18			47			35
Other operation and maintenance		196			201			410			405
Depreciation and amortization		93			85			182			172
Other taxes		105			89			197			179
Deferred electric service costs		(63	)		(57	)		(82	)		(84	)
Effect of settlement of Mirant bankruptcy claims		—			—			—			(14	)
Total Operating Expenses		1,443			1,522			3,131			3,418
Operating Income		193			144			324			285
Other Income (Expenses)
Interest and dividend income		—			1			—			2
Interest expense		(89	)		(87	)		(172	)		(169	)
Gain (loss) from equity investments		—			2			(1	)		1
Other income		5			4			11			8
Other expenses		—			(1	)		—			(1	)
Total Other Expenses		(84	)		(81	)		(162	)		(159	)
Income from Continuing Operations Before Income Tax Expense		109			63			162			126
Income Tax Expense related to Continuing Operations		33			24			58			46
Net Income from Continuing Operations		76			39			104			80
Loss from Discontinued Operations, net of Income Taxes		(130	)		(14	)		(122	)		(10	)
Net (Loss) Income		(54	)		25			(18	)		70
Retained Earnings at Beginning of Period		1,244			1,257			1,268			1,271
Dividends paid on common stock (Note 14)		(60	)		(60	)		(120	)		(119	)
Retained Earnings at End of Period	$	1,130		$	1,222		$	1,130		$	1,222
Basic and Diluted Share Information
Weighted average shares outstanding (millions)		223			220			223			220
Earnings per share of common stock from Continuing Operations	$	.34		$	.18		$	.47		$	.37
Loss per share of common stock from Discontinued Operations		(.58	)		(.07	)		(.55	)		(.05	)
Basic and diluted (loss) earnings per share	$	(.24	)	$	.11		$	(.08	)	$	.32

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

2

PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
	(millions of dollars)
Net (loss) income	$	(54	)	$	25		$	(18	)	$	70
Other comprehensive income (loss) from continuing operations
Gains (losses) on commodity derivatives designated as cash flow hedges:
Gains (losses) arising during period		12			(15	)		(78	)		(106	)
Amount of losses reclassified into income		38			39			87			90
Net gains (losses) on commodity derivatives		50			24			9			(16	)
Losses on treasury rate locks reclassified into income		2			2			3			3
Amortization of gains and losses for prior service costs		4			(10	)		4			(10	)
Other comprehensive income (loss) from continuing operations, before income taxes		56			16			16			(23	)
Income tax expense (benefit) from continuing operations		23			7			7			(9	)
Other comprehensive income (loss) from continuing operations, net of income taxes		33			9			9			(14	)
Other comprehensive income (loss) from discontinued operations, net of income taxes		113			34			71			(32	)
Comprehensive income	$	92		$	68		$	62		$	24

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

3

PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30, 2010			December 31, 2009
	(millions of dollars)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	34		$	44
Restricted cash equivalents		9			11
Accounts receivable, less allowance for uncollectible accounts of $49 million and $44 million, respectively		1,034			1,019
Inventories		129			124
Derivative assets		30			22
Prepayments of income taxes		154			167
Deferred income tax assets, net		109			126
Prepaid expenses and other		84			67
Conectiv Energy assets held for sale		281			346
Total Current Assets		1,864			1,926
INVESTMENTS AND OTHER ASSETS
Goodwill		1,407			1,407
Regulatory assets		1,804			1,801
Investment in finance leases held in trust		1,396			1,386
Income taxes receivable		134			141
Restricted cash equivalents		3			4
Assets and accrued interest related to uncertain tax positions		14			12
Derivative assets		10			16
Other		193			194
Conectiv Energy assets held for sale		19			29
Total Investments and Other Assets		4,980			4,990
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		11,745			11,431
Accumulated depreciation		(4,303	)		(4,190	)
Net Property, Plant and Equipment		7,442			7,241
Conectiv Energy assets held for sale		1,587			1,622
Total Property, Plant and Equipment		9,029			8,863
TOTAL ASSETS	$	15,873		$	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)

	June 30, 2010			December 31, 2009
	(millions of dollars, except shares)
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Short-term debt	$	988		$	530
Current portion of long-term debt and project funding		1,051			536
Accounts payable and accrued liabilities		649			574
Capital lease obligations due within one year		7			7
Taxes accrued		99			47
Interest accrued		68			68
Derivative liabilities		73			67
Other		302			282
Liabilities associated with Conectiv Energy assets held for sale		164			191
Total Current Liabilities		3,401			2,302
DEFERRED CREDITS
Regulatory liabilities		536			613
Deferred income taxes, net		2,604			2,600
Investment tax credits		33			35
Pension benefit obligation		283			290
Other postretirement benefit obligations		416			409
Income taxes payable		7			5
Liabilities and accrued interest related to uncertain tax positions		94			96
Derivative liabilities		41			54
Other		156			147
Liabilities associated with Conectiv Energy assets held for sale		23			19
Total Deferred Credits		4,193			4,268
LONG-TERM LIABILITIES
Long-term debt		3,595			4,470
Transition bonds issued by ACE Funding		351			368
Long-term project funding		16			17
Capital lease obligations		89			92
Total Long-Term Liabilities		4,051			4,947
COMMITMENTS AND CONTINGENCIES (NOTE 14)
EQUITY
Common stock, $.01 par value – authorized 400,000,000 shares, 223,889,619 and 222,269,895 shares outstanding, respectively		2			2
Premium on stock and other capital contributions		3,251			3,227
Accumulated other comprehensive loss		(161	)		(241	)
Retained earnings		1,130			1,268
Total Shareholders’ Equity		4,222			4,256
Non-controlling interest		6			6
Total Equity		4,228			4,262
TOTAL LIABILITIES AND EQUITY	$	15,873		$	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)

	Six Months Ended June  30,
	2010			2009
	(millions of dollars)
OPERATING ACTIVITIES
Net (loss) income	$	(18	)	$	70
Loss from discontinued operations		122			10
Adjustments to reconcile net (loss) income to net cash from operating activities:
Depreciation and amortization		182			172
Non-cash rents from cross-border energy lease investments		(26	)		(27	)
Effect of settlement of Mirant bankruptcy claims		—			(14	)
Changes in restricted cash equivalents related to Mirant settlement		—			38
Deferred income taxes		53			82
Other		(7	)		(3	)
Changes in:
Accounts receivable		(20	)		157
Inventories		(6	)		14
Prepaid expenses		(28	)		(55	)
Regulatory assets and liabilities, net		(105	)		(82	)
Accounts payable and accrued liabilities		74			(195	)
Pension contributions		—			(220	)
Pension benefit obligation		34			48
Cash collateral related to derivative activities		4			(30	)
Taxes accrued		50			19
Interest accrued		—			(2	)
Other assets and liabilities		50			16
Net Conectiv Energy assets held for sale		140			9
Net Cash From Operating Activities		499			7
INVESTING ACTIVITIES
Investment in property, plant and equipment		(364	)		(297	)
Changes in restricted cash equivalents		3			1
Net other investing activities		(1	)		5
Investment in property, plant and equipment associated with Conectiv Energy assets held for sale		(111	)		(91	)
Net Cash Used By Investing Activities		(473	)		(382	)
FINANCING ACTIVITIES
Dividends paid on common stock		(120	)		(119	)
Common stock issued for the Dividend Reinvestment Plan		15			15
Issuances of common stock		10			11
Issuances of long-term debt		102			110
Reacquisition of long-term debt		(482	)		(67	)
Issuances of short-term debt, net		458			175
Cost of issuances		(7	)		(4	)
Net other financing activities		(18	)		(11	)
Net financing activities associated with Conectiv Energy assets held for sale		6			1
Net Cash (Used by) From Financing Activities		(36	)		111
Net Decrease in Cash and Cash Equivalents		(10	)		(264	)
Cash and Cash Equivalents at Beginning of Period		44			384
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	34		$	120
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash received for income taxes, net	$	1		$	66

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

6

PEPCO HOLDINGS

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

PEPCO HOLDINGS, INC.

(1) ORGANIZATION

Pepco Holdings, Inc. (PHI or Pepco Holdings), a Delaware corporation incorporated in 2001, is a holding company that, through the following regulated public utility subsidiaries, is engaged primarily in the distribution, transmission and default supply of electricity and the delivery and supply of natural gas (Power Delivery):

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

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

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

Each of Pepco, DPL and ACE is also a reporting company under the Securities Exchange Act of 1934, as amended. Together the three companies constitute a single segment for financial reporting purposes.

PHI has also been engaged in the competitive energy generation, marketing and supply business (Competitive Energy), which it has conducted through subsidiaries of Conectiv Energy Holding Company (collectively Conectiv Energy) and through Pepco Energy Services, Inc. and its subsidiaries (collectively, Pepco Energy Services), each of which has constituted a separate segment for financial reporting purposes. As more fully described below, PHI is in the process of disposing of Conectiv Energy and is winding down the retail energy supply portion of the business of 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.

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.

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

On April 20, 2010, the Board of Directors of PHI approved a plan for the disposition of Conectiv Energy. On July 1, 2010, PHI completed the sale of Conectiv Energy’s wholesale power generation business to Calpine Corporation (Calpine) for $1.63 billion. PHI is currently in the process of liquidating all of the Conectiv Energy segment’s remaining assets, consisting of its load service supply contracts, energy hedging portfolio, certain tolling agreements and other assets not included in the Calpine sale, which PHI expects to complete within a period of 12 months following the announcement of the disposition plan. In view of the adoption of a plan of disposition for the Conectiv Energy segment, beginning with the financial statements for the period ended June 30, 2010, the entire Conectiv Energy segment is being accounted for as a discontinued operation and is no longer being reflected as a separate segment for financial reporting purposes. In addition, substantially all of the information in these Notes to the Consolidated Financial Statements with respect to the operations of the former Conectiv Energy segment has been consolidated in Note (15), “Discontinued Operations.”

The business of the Pepco Energy Services segment has consisted primarily of (i) the retail supply of electricity and natural gas and (ii) providing energy savings performance contracting services principally to federal, state and local government customers, and designing, constructing and operating combined heat and power and central energy plants for customers (Energy Services). Pepco Energy Services also owns and operates two oil-fired generation facilities. In December 2009, PHI announced that it will wind down the retail energy supply component of the Pepco Energy Services business. Pepco Energy Services is implementing this wind down by not entering into any new supply contracts, while continuing to perform under its existing supply contracts through the expiration dates of those contracts.

The retail energy supply business has historically generated a substantial portion of the operating revenues and net income of the Pepco Energy Services segment. Operating revenues related to the retail energy supply business for the three months ended June 30, 2010 and 2009 were $401 million and $534 million, respectively, while operating income for the same periods was $10 million and $31 million, respectively. Operating revenues related to the retail energy supply business for the six months ended June 30, 2010 and 2009 were $898 million and $1.17 billion, respectively, while operating income for the same periods was $31 million and $53 million, respectively. In connection with the operation of the retail energy supply business, as of June 30, 2010, Pepco Energy Services provided letters of credit of $172 million and posted net cash collateral of $121 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 the collateral is expected to be fully released over time by June 1, 2014. The Energy Services business will not be affected by the wind down of the retail energy supply business.

Other Business Operations

Through its subsidiary Potomac Capital Investment Corporation (PCI), PHI maintains a portfolio of cross-border energy lease investments, with a book value at June 30, 2010 of approximately $1.4 billion. This activity constitutes a third 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 June 30, 2010, in accordance with GAAP. The year-end December 31, 2009 balance sheet was derived from audited financial statements, but does not include all disclosures required by

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GAAP. Interim results for the three and six months ended June 30, 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 business and the retail energy supply business of Pepco Energy Services are seasonal.

Use of Estimates

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

Significant matters that involve the use of estimates include the assessment of goodwill and long-lived assets for impairment, fair value calculations for certain derivative instruments, the costs of providing pension and other postretirement benefits, evaluation of the probability of recovery of regulatory assets, 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 were originally estimated at March 31, 2010 to be $37 million with $19 million charged to Other Operation and Maintenance expense for repair work and $18 million recorded as capital expenditures. A portion of the costs of the restoration work relates to services provided by outside contractors and other utilities, and since billings for such services in certain instances had not been received at March 31, 2010, the costs were estimated at that date. The actual billings received during the second quarter of 2010 resulted in final costs of $32 million, with $15 million charged to Other Operation and Maintenance expense and $17 million recorded as capital expenditures, which reflects a reduction in Other Operation and Maintenance expense of $4 million in the second quarter of 2010 and a reduction of $1 million originally recorded as capital expenditures.

In May 2010, each of PHI’s utility subsidiaries provided its updated network service transmission rate to the FERC effective June 1, 2010 through May 31, 2011 that included a true-up of costs incurred in the prior service year that had not yet been reflected in rates charged to customers. The recording of the difference between the true-ups provided to the FERC and the estimated true-up calculation as of March 31, 2010 resulted in an increase in transmission service revenue of $8 million in the second quarter of 2010.

In the second quarter of 2010, PHI recorded after-tax net losses from dispositions of assets and businesses of the discontinued Conectiv Energy segment of $132 million, including a $67 million write-down in connection with the sale of the wholesale power generation business to Calpine. The write-down has been calculated using estimates and assumptions which PHI believes provide a reasonable basis for presenting the significant effects of the sale. The actual loss on disposal of these assets may vary from the write-down recorded.

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.

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ACE Power Purchase 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 June 30, 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 June 30, 2010 and 2009, were approximately $67 million and $61 million, respectively, of which approximately $62 million and $59 million, respectively, consisted of power purchases under the PPAs. Net purchase activities with the NUGs for the six months ended June 30, 2010 and 2009, were approximately $140 million and $144 million, respectively, of which approximately $129 million and $131 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 Renewable Energy Transactions

PHI, through its DPL subsidiary, has entered into four wind PPAs in amounts up to a total of 350 megawatts and one solar renewable energy credit (REC) purchase agreement with a nine megawatt facility. Of the wind PPAs, three of them are with land-based facilities and one is with an offshore facility. The Delaware Public Service Commission (DPSC) has approved the four wind 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. The solar agreement is being reviewed by the DPSC. The RECs purchased under all the agreements, as described below, will help DPL fulfill a portion of its requirements under the State of Delaware’s Renewable Energy Portfolio Standards Act.

One of the land-based wind facilities became operational and went into service in December 2009. DPL is obligated to purchase energy and RECs from this facility through 2024 in amounts generated and delivered not to exceed 50.25 megawatts at rates that are primarily fixed. Payments under the other wind agreements are currently expected to start in the fourth quarter of 2010 for the other two land-based contracts and 2016 for the offshore contract, if the projects are ultimately completed and operational. The terms of the agreements with the 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. The term of the agreement with the solar facility is 20 years and DPL is obligated to purchase RECs in an amount up to seventy percent of the energy output from the solar facility at a fixed price once the PPA is approved by the DPSC and the facility is operational.

DPL concluded that consolidation is not required for any of these agreements 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

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for the transfer by ACE to ACE Funding of the right to collect non-bypassable Transition Bond Charges (the Transition Bond Charges) from ACE customers pursuant to bondable stranded costs rate orders issued by the New Jersey Board of Public Utilities (NJBPU) in an amount sufficient to fund the principal and interest payments on the Transition Bonds and related taxes, expenses and fees (Bondable Transition Property). ACE collects the Transition Bond Charges from its customers on behalf of ACE Funding and the holders of the Transition Bonds. The assets of ACE Funding, including the Bondable Transition Property, and the Transition Bond Charges collected from ACE’s customers, are not available to creditors of ACE. The holders of the Transition Bonds have recourse only to the assets of ACE Funding. ACE owns 100 percent of the equity of ACE Funding and PHI 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 entirely to Pepco Holdings’ Power Delivery reporting unit based on the aggregation of its regulated public utility company components for purposes of testing for impairment. 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 six months ended June 30, 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 June 30, 2010, it was determined that the fair value of the assets less costs to sell was less than the carrying value of the long-lived assets of the Conectiv Energy segment. Accordingly, as of June 30, 2010, PHI recorded an after-tax write-down of the long-lived assets of $67 million. The write-down is included as a component of the discontinued operations loss for the three and six months ended June 30, 2010.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in Pepco Holdings’ gross revenues were $95 million and $77 million for the three months ended June 30, 2010 and 2009, respectively, and $177 million and $156 million for the six months ended June 30, 2010 and 2009, respectively.

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Reclassifications and Adjustments

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

Income Tax Adjustments

During the second quarter of 2010, PHI recorded an adjustment to correct certain income tax errors associated with casualty loss claims, which resulted in a decrease to income tax expense of $1 million for the three and six months ended June 30, 2010.

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 and second quarters of 2009, ACE recorded adjustments to correct certain income tax errors related to prior periods. These adjustments resulted in an increase in income tax expense of $1 million for the three months ended June 30, 2009, and a decrease in income tax expense of $1 million for the six months ended June 30, 2009.

During the second quarter of 2009, DPL recorded an adjustment to correct certain income tax errors related to prior periods. The adjustment resulted in a decrease in income tax expense of $1 million for the three and six months ended June 30, 2009.

(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Transfers and Servicing (ASC 860)

The FASB issued new guidance that removed the concept of a qualifying special-purpose entity (QSPE) from the guidance on transfers and servicing and the QSPE scope exception in the guidance on consolidation. The new guidance also 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 its overall financial condition, results of operations, or cash flows.

Consolidation of Variable Interest Entities (ASC 810)

The FASB issued new consolidation guidance regarding variable interest entities effective January 1, 2010 that eliminated the 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 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.

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 its overall financial condition, results of operations, or cash flows.

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Fair Value Measurements and Disclosures (ASC 820)

The FASB issued new disclosure requirements for recurring and non-recurring fair value measurements. The guidance, effective beginning with PHI’s March 31, 2010 financial statements, requires the disaggregation of balance sheet items measured at fair value into subsets of balance sheet items based on the nature and risks of the items. The standard requires descriptions of pricing inputs and valuation methodologies for instruments with Level 2 or 3 valuation inputs. In addition, the standard requires information about any 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 eliminated 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 Measurements 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 its financial statements.

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(5) SEGMENT INFORMATION

Pepco Holdings’ management has identified its operating segments at June 30, 2010 as Power Delivery, Pepco Energy Services, and Other Non-Regulated. Corporate and Other includes unallocated Pepco Holdings’ (parent company) capital costs, such as acquisition financing costs. Segment financial information for continuing operations, for the three and six months ended June 30, 2010 and 2009, is as follows:

	Three Months Ended June 30, 2010
	(millions of dollars)
	Power Delivery		Pepco Energy Services		Other Non- Regulated		Corporate and Other  (a)			PHI Consolidated
Operating Revenue	$	1,149	$	476	$	13	$	(2	)	$	1,636
Operating Expenses (b)		996		453		2		(8	)		1,443
Operating Income		153		23		11		6			193
Interest Income		1		—		1		(2	)		—
Interest Expense		53		5		3		28			89
Other Income		5		—		—		—			5
Income Tax Expense (Benefit)		41		8		3		(19	)(c)		33
Net Income (Loss) from Continuing Operations		65		10		6		(5	)		76
Total Assets (excluding Assets Held for Sale)		10,429		653		1,462		1,442			13,986
Construction Expenditures	$	194	$	—	$	—	$	12		$	206

(a) Total Assets line item in this column includes Pepco Holdings’ goodwill balance of $1.4 billion, substantially all of which is allocated to the Power Delivery segment for purposes of assessing impairment. Additionally, Corporate and Other includes intercompany amounts of $(2) million for Operating Revenue, $(1) million for Operating Expense, $(13) million for Interest Income and $(13) million for Interest Expense.

(b) Includes depreciation and amortization of $93 million, consisting of $85 million for Power Delivery, $5 million for Pepco Energy Services, $1 million for Other Non-Regulated and $2 million for Corporate and Other.

(c) Includes $8 million state tax benefit from changed apportionment arising from the restructuring of certain PHI subsidiaries.

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	Three Months Ended June 30, 2009
	(millions of dollars)
	Power Delivery		Pepco Energy Services		Other Non- Regulated		Corporate and Other (a)			PHI Consolidated
Operating Revenue	$	1,095	$	560	$	14	$	(3	)	$	1,666
Operating Expenses (b)		995		531		1		(5	)		1,522
Operating Income		100		29		13		2			144
Interest Income		1		1		1		(2	)		1
Interest Expense		53		12		3		19			87
Other Income		3		—		1		1			5
Income Tax Expense (Benefit)		20		8		4		(8	)		24
Net Income (Loss) from Continuing Operations		31		10		8		(10	)		39
Total Assets (excluding Assets Held for Sale)		10,254		743		1,526		1,593			14,116
Construction Expenditures	$	149	$	3	$	—	$	6		$	158

(a) Total Assets line item in this column includes Pepco Holdings’ goodwill balance of $1.4 billion, substantially all of which is allocated to the Power Delivery segment for purposes of assessing impairment. Additionally, Corporate and Other includes intercompany amounts of $(3) million for Operating Revenue, $(1) million for Operating Expense, $(22) million for Interest Income, and $(21) million for Interest Expense.

(b) Includes depreciation and amortization of $85 million, consisting of $79 million for Power Delivery, $5 million for Pepco Energy Services, and $1 million for Corporate and Other.

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	Six Months Ended June 30, 2010
	(millions of dollars)
	Power Delivery			Pepco Energy Services		Other Non- Regulated			Corporate and Other  (a)			PHI Consolidated
Operating Revenue	$	2,411		$	1,023	$	26		$	(5	)	$	3,455
Operating Expenses (b)		2,165			975		3			(12	)		3,131
Operating Income		246			48		23			7			324
Interest Income		1			—		2			(3	)		—
Interest Expense		104			10		7			51			172
Other Income (Expense)		9			1		(1	)		1			10
Preferred Stock Dividends		—			—		1			(1	)		—
Income Tax Expense (Benefit)		67	(c)		16		6			(31	)(d)		58
Net Income (Loss) from Continuing Operations		85			23		10			(14	)		104
Total Assets (excluding Assets Held for Sale)		10,429			653		1,462			1,442			13,986
Construction Expenditures	$	345		$	1	$	—		$	18		$	364

(a) Total Assets line item in this column includes Pepco Holdings’ goodwill balance of $1.4 billion, substantially all of which is allocated to the Power Delivery segment for purposes of assessing impairment. Additionally, Corporate and Other includes intercompany amounts of $(5) million for Operating Revenue, $(5) million for Operating Expense, $(25) million for Interest Income, $(25) million for Interest Expense, and $(1) million for Preferred Stock Dividends.

(b) Includes depreciation and amortization of $182 million, consisting of $167 million for Power Delivery, $9 million for Pepco Energy Services, $1 million for Other Non-Regulated and $5 million for Corporate and Other.

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

(d) Includes $8 million state tax benefit from changed apportionment arising from the restructuring of certain PHI subsidiaries and the release of $8 million 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.

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	Six Months Ended June 30, 2009
	(millions of dollars)
	Power Delivery			Pepco Energy Services		Other Non- Regulated		Corporate and Other (a)			PHI Consolidated
Operating Revenue	$	2,467		$	1,217	$	27	$	(8	)	$	3,703
Operating Expenses (b)		2,253	(c)		1,173		2		(10	)		3,418
Operating Income		214			44		25		2			285
Interest Income		2			1		2		(3	)		2
Interest Expense		106			16		7		40			169
Other Income		6			1		1		—			8
Preferred Stock Dividends		—			—		1		(1	)		—
Income Tax Expense (Benefit)		43			12		5		(14	)		46
Net Income (Loss) from Continuing Operations		73			18		15		(26	)		80
Total Assets (excluding Assets Held for Sale)		10,254			743		1,526		1,593			14,116
Construction Expenditures	$	281		$	6	$	—	$	10		$	297

(a) Total Assets line item in this column includes Pepco Holdings’ goodwill balance of $1.4 billion, substantially all of which is allocated to the Power Delivery segment for purposes of assessing impairment. Additionally, Corporate and Other includes intercompany amounts of $(8) million for Operating Revenue, $(3) million for Operating Expense, $(44) million for Interest Income, $(44) million for Interest Expense, and $(1) million for Preferred Stock Dividends.

(b) Includes depreciation and amortization of $172 million, consisting of $158 million for Power Delivery, $9 million for Pepco Energy Services, $1 million for Other Non-Regulated and $4 million for Corporate and Other.

(c) 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 and six months ended June 30, 2010. Substantially all of PHI’s $1.4 billion goodwill balance was generated by Pepco’s acquisition of Conectiv in 2002 and is allocated entirely to the Power Delivery reporting unit based on the aggregation of its regulated public utility company components for purposes of assessing impairment under FASB guidance on goodwill and other intangibles (ASC 350).

PHI’s annual impairment tests as of July 1, 2009 and November 1, 2009 indicated that goodwill was not impaired. As of June 30, 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 June 30, 2010, PHI’s market capitalization has improved compared to earlier periods when it performed interim impairment tests. PHI performed its previous annual goodwill impairment tests as of November 1, 2009 and July 1, 2009, and an interim impairment test as of March 31, 2009 when its market capitalization was further below book value than at June 30, 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.

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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 the wind-down of Pepco Energy Services retail energy business		(4	)
Balance, December 31, 2009		1,407
Less: Adjustments		—
Balance, June 30, 2010	$	1,407

(7) LEASING ACTIVITIES

Investment in Finance Leases Held in Trust

As of June 30, 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 June 30, 2010 and at December 31, 2009 are summarized below:

	June 30, 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		(869	)		(895	)
Investment in finance leases held in trust		1,396			1,386
Less: Deferred income tax liabilities		(770	)		(748	)
Net investment in finance leases held in trust	$	626		$	638

Income recognized from cross-border energy lease investments was comprised of the following for the three and six months ended June 30, 2010 and 2009:

	Three Months Ended June  30,				Six Months Ended June  30,
	2010		2009		2010		2009
	(millions of dollars)
Pre-tax income from PHI’s cross-border energy lease investments (included in “Other Revenue”)	$	13	$	13	$	26	$	27
Income tax expense		3		3		7		7
Net income from PHI’s cross-border energy lease investments	$	10	$	10	$	19	$	20

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(8) PENSION AND OTHER POSTRETIREMENT BENEFITS

The following Pepco Holdings information is for the three months ended June 30, 2010 and 2009:

	Pension Benefits						Other Postretirement Benefits
	2010			2009			2010			2009
	(millions of dollars)
Service cost	$	7		$	9		$	1		$	1
Interest cost		25			28			9			10
Expected return on plan assets		(25	)		(23	)		(4	)		(3	)
Amortization of prior service cost		—			—			(1	)		(1	)
Amortization of net actuarial loss		10			17			3			6
Plan amendment		1			—			—			—
Termination benefits		—			—			5			—
Net periodic benefit cost	$	18		$	31		$	13		$	13

The following Pepco Holdings information is for the six months ended June 30, 2010 and 2009:

	Pension Benefits						Other Postretirement Benefits
	2010			2009			2010			2009
	(millions of dollars)
Service cost	$	18		$	18		$	3		$	3
Interest cost		55			56			19			20
Expected return on plan assets		(58	)		(51	)		(8	)		(7	)
Amortization of prior service cost		—			—			(2	)		(2	)
Amortization of net actuarial loss		21			29			6			9
Plan amendment		1			—			—			—
Termination benefits		—			—			5			—
Net periodic benefit cost	$	37		$	52		$	23		$	23

Pension and Other Postretirement Benefits

Net periodic benefit cost is included in other operation and maintenance expense, net of the portion of the net periodic benefit cost that is capitalized as part of the cost of labor for internal construction projects. PHI’s pension and other postretirement net periodic benefits cost for the three and six months ended June 30, 2010 includes one time charges of $6 million related to the pending sale of Conectiv Energy. After intercompany allocations, the three utility subsidiaries are responsible for substantially all of the total PHI net periodic pension and other postretirement benefit costs.

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Pension Contributions

PHI’s funding policy with regard to PHI’s noncontributory retirement plan (the PHI Retirement Plan) is to maintain a funding level that is at least equal to the funding target level under the Pension Protection Act of 2006. Although PHI currently projects there will be no minimum funding requirement under the Pension Protection Act guidelines in 2010, PHI intends to make discretionary tax-deductible contributions in 2010 in the aggregate amount of approximately $100 million to bring its plan assets to at least the funding target level for 2010 under the Pension Protection Act. As of June 30, 2010, no 2010 contributions had been made. Subsequent to June 30, 2010, PHI Service Company contributed $35 million to the PHI Retirement Plan on each of July 1, 2010 and August 2, 2010.

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.

(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.

PHI also has a $400 million unsecured credit facility with a syndicate of nine lenders, which has a termination date of 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. This facility and the $1.5 billion facility are referred to collectively as PHI’s “primary credit facilities.”

In addition, PHI has a $50 million bilateral credit agreement with The Bank of Nova Scotia in effect though October 2010, which only can be used for the purpose of obtaining letters of credit. As of June 30, 2010, $25 million in letters of credit were outstanding under the agreement.

Under the terms of each of these facilities, the sale of the Conectiv Energy wholesale power generation business required the consent of the lenders. In each case, the sale was approved without any requirement that the terms of the facility be modified by reason of the sale.

At June 30, 2010 and December 31, 2009, the amount of cash plus borrowing capacity under the three above-referenced credit facilities available to meet the future liquidity needs of PHI and its utility subsidiaries on a consolidated basis each totaled $1.4 billion. PHI’s utility subsidiaries had combined cash and borrowing capacity under the $1.5 billion credit facility of $450 million and $582 million, respectively.

On April 20, 2010, PHI entered into a $450 million unsecured bridge loan facility with Morgan Stanley Bank, N.A. and Credit Suisse AG. PHI used the proceeds of the loans drawn under the facility 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. On July 1, 2010, PHI repaid all amounts outstanding under this facility with the proceeds from the sale of the Conectiv Energy wholesale power generation business to Calpine, thereby terminating the facility.

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Other Financing Activities

In April 2010, ACE Funding made principal payments of $5.6 million on Series 2002-1 Bonds, Class A-2, and $2.2 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. The bonds bear interest at the fixed rate of 5.40% per annum, payable each February 1 and August 1, commencing August 1, 2010. DPL used the proceeds of the loan 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, which 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:

• $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.

As the owner of these bonds, DPL received the proceeds from the redemption of the bonds, which it used for general corporate purposes.

On June 1, 2010 ACE replaced the letters of credit associated with (i) $18.2 million of The Pollution Control Financing Authority of Salem County Pollution Control Revenue Refunding Bonds, 1997 Series A (Atlantic City Electric Company Project) due April 15, 2014 (the 1997 Series A Bonds) and (ii) $4.4 million of The Pollution Control Financing Authority of Salem County Pollution Control Revenue Refunding Bonds, 1997 Series B (Atlantic City Electric Company Project) due July 15, 2017 (the 1997 Series B Bonds), both of which expired on June 23, 2010, with new irrevocable direct pay letters of credit. The new letters of credit supporting the 1997 Series A Bonds and the 1997 Series B Bonds expire on April 15, 2014 and June 1, 2013, respectively.

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Financing Activity Subsequent to June 30, 2010

Repurchase of Tax-Exempt Bonds

On July 1, 2010, DPL repurchased $31 million of tax-exempt bonds pursuant to a put provision of the bonds. DPL intends to remarket these bonds in the second half of 2010.

Debt Tender Offers

On July 2, 2010, PHI purchased, pursuant to a cash tender offer, $640.1 million in principal amount of its 6.45% senior notes due 2012 (6.45% Notes) for an aggregate purchase price of $713 million, plus accrued and unpaid interest. The tender offer for the 6.45% Notes also constituted a solicitation of the consent of the holders of the 6.45% Notes to an amendment of the terms of the 6.45% Notes to reduce the notice period for the redemption from not less than 30 days and not more than 60 days to three business days. This amendment, which required the consent of the holders of a majority of the outstanding 6.45% Notes, was approved upon the repurchase of the 6.45% Notes pursuant to the tender offer. On July 2, 2010, PHI terminated the tender offer and issued a notice of redemption for the balance of the 6.45% Notes. On July 8, 2010, PHI redeemed the remaining $109.9 million of outstanding 6.45% Notes at an aggregate redemption price of $122 million, plus accrued and unpaid interest.

On July 20, 2010, PHI purchased pursuant to a cash tender offer (i) $128.9 million of its 6.125% senior notes due 2017 (6.125% Notes), at an aggregate purchase price of $145 million, plus accrued and unpaid interest, and (ii) $65.1 million of 7.45% senior notes due 2032 (7.45% Notes), at an aggregate purchase price of $78 million, plus accrued and unpaid interest.

At June 30, 2010, PHI reclassified $944 million of its senior notes to current liabilities pursuant to the debt tender offers noted above.

The repurchases of the 6.45% Notes, 6.125% Notes and the 7.45% Notes were funded using the proceeds realized by PHI from the sale of Conectiv Energy’s wholesale power generation business to Calpine.

As a result of the aforementioned repurchases of debt, an after-tax loss on extinguishment of debt of $70 million will be recorded in the third quarter of 2010.

In June 2002, PHI entered into several treasury rate lock transactions to hedge changes in interest rates related to the anticipated issuance in August 2002 of several series of senior notes, including the 6.45% Notes and the 7.45% Notes. Upon issuance of the fixed rate debt, the rate locks were terminated at a loss that has been deferred in Accumulated Other Comprehensive Loss and is being recognized in income over the life of the debt issued as interest payments are made. In connection with the repurchases of the 6.45% Notes and the 7.45% Notes, PHI expects to accelerate the recognition of $9 million of these after-tax losses by reclassifying these losses from Accumulated Other Comprehensive Loss to income in the third quarter of 2010.

Collateral Requirements

At June 30, 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 Pepco Energy Services and Conectiv Energy totaled $918 million and $820 million, respectively.

Collateral Requirements of Pepco Energy Services

In conducting its retail energy supply business, Pepco Energy Services, during periods of declining energy prices, has been exposed to the asymmetrical risk of having to post collateral under its wholesale purchase contracts without receiving a corresponding amount of collateral from its retail customers. To partially address these asymmetrical collateral obligations, Pepco Energy Services, in the first quarter of 2009, entered into a credit intermediation arrangement with Morgan Stanley Capital Group, Inc. (MSCG). Under this arrangement, MSCG, in consideration for the payment to MSCG of certain fees: (i) 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

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novated transactions, but without imposing on Pepco Energy Services any obligation to post collateral based on changes in electricity prices. As of June 30, 2010, approximately 7% 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 June 30, 2010 and 2009, approximately $3 million and $7 million, respectively, of the fees have been amortized and reflected in interest expense. For the six months ended June 30, 2010 and 2009, approximately $5 million and $8 million, respectively, of the fees have been amortized and reflected in interest expense.

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

Depending on the contract terms, the collateral required to be posted by Pepco Energy Services can be of varying forms, including cash and letters of credit. As of June 30, 2010, Pepco Energy Services had posted net cash collateral of $121 million and letters of credit of $172 million.

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

Remaining Collateral Requirements of Conectiv Energy

Depending on the contract terms, the collateral required to be posted by Conectiv Energy was of varying forms, including cash and letters of credit. As of June 30, 2010, Conectiv Energy had posted net cash collateral of $195 million and letters of credit of $12 million. After giving effect to the sale of the wholesale power generation business, effective July 1, 2010, the net cash collateral posted by Conectiv Energy was reduced to cash of $184 million and letters of credit of $8 million.

At December 31, 2009, Conectiv Energy had posted net cash collateral of $240 million and letters of credit of $22 million.

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(10) INCOME TAXES

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

	Three Months Ended June  30,				Six Months Ended June  30,
	2010		2009		2010		2009
Federal statutory rate	35.0	%	35.0	%	35.0	%	35.0	%
Increases (decreases) resulting from:
State income taxes, net of federal effect	5.0		8.9		5.6		4.3
Change in estimates and interest related to uncertain and effectively settled tax positions	1.0		(3.8	)	6.2		(1.9	)
Depreciation	1.4		2.4		1.7		1.2
Tax credits	(0.9	)	(1.6	)	(1.2	)	(0.7	)
Cross-border energy lease investments	(1.2	)	(2.1	)	(1.5	)	(1.0	)
Release of valuation allowance	—		—		(4.8	)	—
Change in state deferred tax balances as a result of corporate restructuring	(7.8	)	—		(5.2	)	—
Medicare Part D subsidy	—		—		2.2		—
Other, net	(2.2	)	(0.7	)	(2.2	)	(0.4	)
Consolidated Effective Income Tax Rate	30.3	%	38.1	%	35.8	%	36.5	%

PHI’s effective tax rates for the three months ended June 30, 2010 and 2009 were 30.3% and 38.1%, respectively. The reduction in the rate is primarily due to an $8 million state tax benefit from a change in state tax apportionment factors arising from a 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 from corporations to single member limited liability companies. In addition to increased organization flexibility and reduced administrative costs, a consequence of converting these entities was to allow PHI to include income or losses in the former corporations in a single state income tax return, thus increasing the utilization of state income tax attributes.

PHI’s effective tax rates for the six months ended June 30, 2010 and 2009 were 35.8% and 36.5%, respectively. The decrease in the rate resulted primarily from approximately $8 million of state apportionment factor benefits recognized in the second quarter of 2010, and the release of $8 million of valuation allowances on deferred tax assets related to state net operating losses recognized in the first quarter of 2010, both of which related to the April 1, 2010 restructuring. This was partially offset by 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 for the six months ended June 30, 2010 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. Under this legislation, 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 legislation, the costs incurred for those prescription drugs were tax deductible. The legislation includes a provision, effective beginning in 2013, which eliminates the tax deductibility of the prescription drug costs. As a result, in the first quarter of 2010, PHI wrote off $5 million of deferred tax assets. Of this amount, $3 million was established as a regulatory asset, which PHI

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anticipates will be recoverable from its utility customers in the future. This change increased PHI’s 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.

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 second quarter of 2009, as a result of filing amended state returns, PHI’s uncertain tax benefits related to prior year tax positions increased by $18 million. These uncertain tax benefits were subsequently realized in the third quarter of 2009.

(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 June  30,
	2010			2009
	(millions of dollars, except per share data)
Income (Numerator):
Net income from continuing operations	$	76		$	39
Net loss from discontinued operations		(130	)		(14	)
Net (loss) income	$	(54	)	$	25
Shares (Denominator) (in millions):
Weighted average shares outstanding for basic computation:
Average shares outstanding		223			220
Adjustment to shares outstanding		—			—
Weighted Average Shares Outstanding for Computation of Basic Earnings Per Share of Common Stock		223			220
Net effect of potentially dilutive shares (a)		—			—
Weighted Average Shares Outstanding for Computation of Diluted Earnings Per Share of Common Stock		223			220
Basic and diluted earnings per share of common stock from continuing operations	$	.34		$	.18
Basic and diluted loss per share of common stock from discontinued operations		(.58	)		(.07	)
Basic and diluted (loss) earnings per share	$	(.24	)	$	.11

(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 280,266 and 369,904 for the three months ended June 30, 2010 and 2009, respectively.

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	For the Six Months Ended June 30,
	2010			2009
	(millions of dollars, except per share data)
Income (Numerator):
Net income from continuing operations	$	104		$	80
Net loss from discontinued operations		(122	)		(10	)
Net (loss) income	$	(18	)	$	70
Shares (Denominator) (in millions):
Weighted average shares outstanding for basic computation:
Average shares outstanding		223			220
Adjustment to shares outstanding		—			—
Weighted Average Shares Outstanding for Computation of Basic Earnings Per Share of Common Stock		223			220
Net effect of potentially dilutive shares (a)		—			—
Weighted Average Shares Outstanding for Computation of Diluted Earnings Per Share of Common Stock		223			220
Basic and diluted earnings per share of common stock from continuing operations	$	.47		$	.37
Basic and diluted loss per share of common stock from discontinued operations		(.55	)		(.05	)
Basic and diluted (loss) earnings per share	$	(.08	)	$	.32

(a) The number of options to purchase shares of common stock that were excluded from the calculation of diluted EPS as they are considered to be anti-dilutive were 280,266 and 358,366 for the six months ended June 30, 2010 and 2009, respectively.

(12) DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

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

Pepco Energy Services purchases energy commodity contracts in the form of electricity and natural gas futures, swaps, options and forward contracts to hedge commodity price risk in connection with the purchase of physical natural gas and electricity for delivery to customers. The primary risk management objective is to manage the spread between retail sales commitments and the cost of supply used to service those commitments to ensure stable cash flows and lock in favorable prices and margins when they become available.

Pepco Energy Services accounts for its futures and swap contracts as cash flow hedges of forecasted transactions. Certain commodity contracts that do not qualify as cash flow hedges of forecasted transactions or do not meet the requirements for normal purchase and normal sale accounting are marked-to-market through current earnings. Forward contracts that meet the requirements for normal purchase and normal sale accounting are accounted for using accrual accounting.

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

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PHI and its subsidiaries also use derivative instruments from time to time to mitigate the effects of fluctuating interest rates on debt incurred in connection with the operation of their businesses. In June 2002, PHI entered into several treasury rate lock transactions in anticipation of the issuance of several series of fixed-rate debt commencing in August 2002. Upon issuance of the fixed rate debt, 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 as interest payments are made. In connection with the debt tender offers described in Note (9), “Debt,” $15 million of these pre-tax losses ($9 million after-tax) is expected to be reclassified to income in the third quarter of 2010.

The tables below identify the balance sheet location and fair values of derivative instruments as of June 30, 2010 and December 31, 2009:

	As of June 30, 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)	$	56		$	47		$	103		$	(73	)	$	30
Derivative Assets (non-current assets)		28			15			43			(33	)		10
Total Derivative Assets		84			62			146			(106	)		40
Derivative Liabilities (current liabilities)		(160	)		(64	)		(224	)		151			(73	)
Derivative Liabilities (non-current liabilities)		(96	)		(27	)		(123	)		82			(41	)
Total Derivative Liabilities		(256	)		(91	)		(347	)		233			(114	)
Net Derivative (Liability) Asset	$	(172	)	$	(29	)	$	(201	)	$	127		$	(74	)

	As of December 31, 2009
Balance Sheet Caption	Derivatives Designated as Hedging Instruments			Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting			Net Derivative Instruments
	(millions of dollars)
Derivative Assets (current assets)	$	100		$	54		$	154		$	(132	)	$	22
Derivative Assets (non-current assets)		44			21			65			(49	)		16
Total Derivative Assets		144			75			219			(181	)		38
Derivative Liabilities (current liabilities)		(234	)		(70	)		(304	)		237			(67	)
Derivative Liabilities (non-current liabilities)		(88	)		(35	)		(123	)		69			(54	)
Total Derivative Liabilities		(322	)		(105	)		(427	)		306			(121	)
Net Derivative (Liability) Asset	$	(178	)	$	(30	)	$	(208	)	$	125		$	(83	)

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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:

	June 30, 2010		December 31, 2009
	(millions of dollars)
Cash collateral pledged to counterparties with the right to reclaim (a)	$	127	$	125

(a) Includes cash deposits on commodity brokerage accounts

As of June 30, 2010 and December 31, 2009, all PHI cash collateral pledged or received related to derivative instruments accounted for at fair value was entitled to offset under master netting agreements.

Derivatives Designated as Hedging Instruments

Cash Flow Hedges

Pepco Energy Services

For energy commodity contracts that are designated and qualify as cash flow hedges, the effective portion of the gain or loss on the derivative is reported as a component of 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 and six months ended June 30, 2010 and 2009 is provided in the tables below:

	Three Months Ended June 30,
	2010			2009
	(millions of dollars)
Amount of net pre-tax gain (loss) arising during the period included in other comprehensive loss	$	12		$	(15	)
Amount of net pre-tax (loss) gain reclassified into income:
Effective portion:
Revenue		—			—
Fuel and Purchased Energy		(39	)		(39	)
Total		(39	)		(39	)
Ineffective portion: (a)
Revenue		1			—
Fuel and Purchased Energy		—			—
Total		1			—
Total net pre-tax loss reclassified into income		(38	)		(39	)
Net pre-tax gain on commodity derivatives included in other comprehensive loss	$	50		$	24

(a) For the three months ended June 30, 2010 and 2009, amounts of less than $1 million and zero, respectively, were reclassified from AOCL to income because the forecasted hedged transactions were deemed probable not to occur.

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	Six Months Ended June 30,
	2010			2009
	(millions of dollars)
Amount of net, pre-tax loss arising during the period included in other comprehensive loss	$	(78	)	$	(106	)
Amount of net pre-tax (loss) gain reclassified into income:
Effective portion:
Revenue		—			—
Fuel and Purchased Energy		(85	)		(90	)
Total		(85	)		(90	)
Ineffective portion: (a)
Revenue		(2	)		—
Fuel and Purchased Energy		—			—
Total		(2	)		—
Total net pre-tax gain (loss) reclassified into income		(87	)		(90	)
Net pre-tax gain (loss) on commodity derivatives included in other comprehensive loss	$	9		$	(16	)

(a) For the six months ended June 30, 2010 and 2009, amounts of less than $1 million and zero, respectively, were reclassified from AOCL to income because the forecasted hedged transactions were deemed probable not to occur.

As of June 30, 2010 and December 31, 2009, Pepco Energy Services had the following types and volumes of energy commodity contracts employed as cash flow hedges of forecasted purchases and forecasted sales.

	Quantities
Commodity	June 30, 2010	December 31, 2009
Forecasted Purchases Hedges
Natural gas (One Million British Thermal Units (MMBtu))	45,802,500	54,477,500
Electricity (Megawatt hours (MWh))	6,230,648	9,708,919
Forecasted Sales Hedges
Electricity (MWh)	4,403,080	7,322,535

Power Delivery

As described above, all premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all of DPL’s gains and losses related to hedging activities, are deferred under FASB guidance on regulated operations until recovered based on the fuel adjustment clause approved by the DPSC. The following table indicates the amounts deferred as regulatory assets or liabilities and the location in the consolidated statements of income of amounts reclassified to income through the fuel adjustment clause for the three and six months ended June 30, 2010 and 2009:

	Three Months Ended June  30,						Six Months Ended June  30,
	2010			2009			2010			2009
	(millions of dollars)
Net Gain Deferred as a Regulatory Asset or Liability	$	5		$	11		$	—		$	11
Net Loss Reclassified from Regulatory Asset or Liability to Fuel and Purchased Energy Expense		(3	)		(10	)		(5	)		(26	)

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As of June 30, 2010 and December 31, 2009, Power Delivery had the following outstanding commodity forward contracts that were entered into to hedge forecasted transactions:

	Quantities
Commodity	June 30, 2010	December 31, 2009
Forecasted Purchases Hedges:
Natural Gas (MMBtu)	3,820,000	5,695,000

Cash Flow Hedges Included in Accumulated Other Comprehensive Loss

The tables below provide details regarding effective cash flow hedges included in PHI’s consolidated balance sheet as of June 30, 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 June 30, 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)	$	94	$	55	47 months
Interest Rate		20		3	266 months
Total	$	114	$	58

(a) Accumulated other comprehensive loss on PHI’s consolidated balance sheet as of June 30, 2010, includes a $15 million balance related to minimum pension liability and a $32 million balance related to Conectiv Energy. These balances are not included in this table as the minimum pension liability is not a cash flow hedge and Conectiv Energy is reported as a discontinued operation.

(b) The unrealized derivative losses recorded in Accumulated Other Comprehensive Loss are largely offset by forecasted natural gas and electricity physical purchases in gain positions that are subject to accrual accounting. These forward purchase contracts are exempted from mark-to-market accounting because they either qualify as normal purchases under FASB guidance on derivatives and hedging or they are not derivative contracts. Under accrual accounting, no asset is recorded on the balance sheet for these contracts, and the purchase cost is not recognized until the period of delivery.

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As of June 30, 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)	$	130	$	8	59 months
Interest Rate		23		3	278 months
Total	$	153	$	11

(a) Accumulated other comprehensive loss on PHI’s consolidated balance sheet as of June 30, 2009, includes a $16 million balance related to minimum pension liability and a $139 balance related to Conectiv Energy. These balances are not included in this table as the minimum pension liability is not a cash flow hedge and Conectiv Energy is reported as a discontinued operation.

(b) The unrealized derivative losses recorded in Accumulated Other Comprehensive Loss are largely offset by forecasted natural gas and electricity physical purchases in gain positions that are subject to accrual accounting. These forward purchase contracts are exempted from mark-to-market accounting because they either qualify as normal purchases under FASB guidance on derivatives and hedging or they are not derivative contracts. Under accrual accounting, no asset is recorded on the balance sheet for these contracts, and the purchase cost is not recognized until the period of delivery.

Other Derivative Activity

Pepco Energy Services

Pepco Energy Services holds certain derivatives that do not qualify as hedges. Under FASB guidance on derivatives and hedging, these derivatives are recorded at fair value through income with corresponding adjustments on the balance sheet.

For the three and six months ended June 30, 2010 and 2009, the amount of the derivative gain (loss) for Pepco Energy Services recognized in income is provided in the table below:

	Three Months Ended June 30, 2010						Three Months Ended June 30, 2009
	Revenue		Fuel and Purchased Energy Expense		Total		Revenue			Fuel and Purchased Energy Expense		Total
	(millions of dollars)
Realized mark-to-market gains (losses)	$	1	$	—	$	1	$	(2	)	$	—	$	(2	)
Unrealized mark-to-market gains (losses)		—		—		—		—			—		—
Total net mark-to-market gains (losses)	$	1	$	—	$	1	$	(2	)	$	—	$	(2	)

	Six Months Ended June 30, 2010						Six Months Ended June 30, 2009
	Revenue		Fuel and Purchased Energy Expense		Total		Revenue			Fuel and Purchased Energy Expense		Total
	(millions of dollars)
Realized mark-to-market gains (losses)	$	1	$	—	$	1	$	(2	)	$	—	$	(2	)
Unrealized mark-to-market gains (losses)		—		—		—		—			—		—
Total net mark-to-market gains (losses)	$	1	$	—	$	1	$	(2	)	$	—	$	(2	)

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As of June 30, 2010 and December 31, 2009, Pepco Energy Services had the following net outstanding commodity forward contract volumes and net position on derivatives that did not qualify for hedge accounting:

	June 30, 2010		December 31, 2009
Commodity	Quantity	Net Position	Quantity	Net Position
Electricity (MWh)	34,400	Long	—	—
Financial transmission rights (MWh)	833,592	Long	532,556	Long

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 and six months ended June 30, 2010 and 2009, the amount of the derivative loss recognized in the consolidated statements of income is provided in the table below by line item:

	Three Months Ended June  30,						Six Months Ended June  30,
	2010			2009			2010			2009
	(millions of dollars)
Gain (Loss) Deferred as a Regulatory Asset or Liability	$	7		$	4		$	1		$	(10	)
Loss Reclassified from Regulatory Asset or Liability to Fuel and Purchased Energy Expense		(6	)		(2	)		(13	)		(5	)

As of June 30, 2010 and December 31, 2009, DPL had the following net outstanding natural gas commodity forward contracts that did not qualify for hedge accounting:

	June 30, 2010		December 31, 2009
Commodity	Quantity	Net Position	Quantity	Net Position
Natural Gas (MMBtu)	9,824,825	Long	10,442,546	Long

Contingent Credit Risk Features

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

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

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sales that are accounted for off-balance sheet. If the aggregate fair value of the transactions in a net loss position exceeds the unsecured credit threshold, then collateral is required to be posted in an amount equal to the amount by which the unsecured credit threshold is exceeded. The obligations of Pepco Energy Services are usually guaranteed by PHI. The obligations of DPL are stand-alone obligations without the guaranty of PHI. If PHI’s or DPL’s credit rating were to fall below “investment grade,” the unsecured credit threshold would typically be set at zero and collateral would be required for the entire net loss position. Exchange-traded contracts are required to be fully collateralized without regard to the credit rating of the holder.

The gross fair value of PHI’s derivative liabilities, excluding the impact of offsetting transactions or collateral under master netting agreements, with credit risk-related contingent features on June 30, 2010 and December 31, 2009, was $229 million and $303 million, respectively. As of those dates, PHI had posted cash collateral of zero and $6 million, respectively, in the normal course of business against the gross derivative liability resulting in a net liability of $229 million and $297 million, respectively, before giving effect to offsetting transactions that are encompassed within master netting agreements that would reduce this amount. PHI’s net settlement amount in the event of a downgrade of PHI and DPL below “investment grade” as of June 30, 2010 and December 31, 2009, would have been approximately $193 million and $183 million, respectively, after taking into consideration the master netting agreements. The offsetting transactions or collateral that would reduce PHI’s obligation to the net settlement amount include derivatives and normal purchase and normal sale contracts in a gain position as well as letters of credit already posted as collateral.

PHI’s primary sources for posting cash collateral or letters of credit are its credit facilities. At June 30, 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 $1.4 billion, of which $918 million and $820 million, respectively, was available for the business of Pepco Energy Services and Conectiv Energy.

(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.

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The Level 2 derivative instruments primarily consist of electricity derivatives at June 30, 2010. Level 2 power swaps are priced at liquid trading hub prices or valued using the liquid hub prices plus a congestion adder that is calculated using historical regression analysis.

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

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

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

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

The following tables set forth, by level within the fair value hierarchy, PHI’s financial assets and liabilities (excluding assets and liabilities held for sale) that were accounted for at fair value on a recurring basis as of June 30, 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 June 30, 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
Electricity (a)	$	22	$	—	$	22	$	—
Cash equivalents
Treasury Fund		15		15		—		—
Executive deferred compensation plan assets
Money Market Funds		12		12		—		—
Life Insurance Contracts		62		—		42		20
	$	111	$	27	$	64	$	20
LIABILITIES
Derivative instruments
Electricity (a)	$	106	$	—	$	106	$	—
Natural Gas (b)		117		88		—		29
Executive deferred compensation plan liabilities
Life Insurance Contracts		30		—		30		—
	$	253	$	88	$	136	$	29

(a) Represents wholesale electricity futures and swaps that are used mainly as part of Pepco Energy Service’s retail energy supply business.

(b) Represents wholesale gas futures and swaps that are used mainly as part of Pepco Energy Service’s retail energy supply business.

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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
Electricity (a)	$	21	$	—	$	21	$	—
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
	$	133	$	50	$	64	$	19
LIABILITIES
Derivative instruments
Electricity (a)	$	116	$	—	$	116	$	—
Natural Gas (b)		113		84		—		29
Executive deferred compensation plan liabilities
Life Insurance Contracts		32		—		32		—
	$	261	$	84	$	148	$	29

(a) Represents wholesale electricity futures and swaps that are used mainly as part of Pepco Energy Service’s retail energy supply business.

(b) Represents wholesale gas futures and swaps that are used mainly as part of Pepco Energy Service’s retail energy supply business.

Reconciliations of the beginning and ending balances of PHI’s fair value measurements using significant unobservable inputs (Level 3) for the six months ended June 30, 2010 and 2009 are shown below:

	Six Months Ended June 30, 2010
	Natural Gas			Life Insurance Contracts
	(millions of dollars)
Beginning balance as of January 1, 2010	$	(29	)	$	19
Total gains or (losses) (realized and unrealized)
Included in income		—			2
Included in accumulated other comprehensive loss		—			—
Included in regulatory liabilities		(10	)		—
Purchases and issuances		—			(1	)
Settlements		10			—
Transfers in (out) of Level 3		—			—
Ending balance as of June 30, 2010	$	(29	)	$	20

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	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	$	2
Change in unrealized gains (losses) relating to assets still held at reporting date	$	2

	Six Months Ended June 30, 2009
	Natural Gas			Life Insurance Contracts
	(millions of dollars)
Beginning balance as of January 1, 2009	$	(24	)	$	18
Total gains or (losses) (realized and unrealized)
Included in income		—			2
Included in accumulated other comprehensive loss		—			—
Included in regulatory liabilities		(15	)		—
Purchases and issuances		—			(1	)
Settlements		7			—
Transfers in (out) of Level 3		—			—
Ending balance as of June 30, 2009	$	(32	)	$	19

	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	$	2
Change in unrealized gains relating to assets still held at reporting date	$	2

Fair Value of Debt Instruments

The estimated fair values of PHI’s non-derivative financial instruments at June 30, 2010 and December 31, 2009 are shown below:

	June 30, 2010				December 31, 2009
	(millions of dollars)
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	4,606	$	5,133	$	4,969	$	5,350
Transition Bonds issued by ACE Funding		386		433		402		427
Long-Term Project Funding		21		21		20		20
Redeemable Serial Preferred Stock		6		5		6		4

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The methods and assumptions described below were used to estimate, as of June 30, 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 June 30, 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 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 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.

• An MFVRD has been approved in concept for DPL natural gas service in Delaware. Based on a settlement among the parties to the ongoing gas decoupling proceeding, implementation of the MFVRD will be considered as part of DPL’s pending natural gas distribution base rate case filed on July 2, 2010.

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

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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 to the DPSC its 2009 Gas Cost Rate (GCR) filing, which permits DPL to recover gas procurement costs through customer rates. 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. DPL, the Delaware Division of the Public Advocate and DPSC staff have entered into a settlement agreement supporting the rates as filed. A Hearing Examiner’s report on the rate proposal is expected in the third quarter of 2010.

In September 2009, DPL submitted an application with the DPSC to increase its electric distribution base rates. The filing, as revised in March 2010, sought approval of an annual rate increase of approximately $26.2 million, assuming approval of the implementation of the MFVRD, based on a requested return on equity (ROE) of 10.75%. As permitted by Delaware law, DPL placed an increase of approximately $2.5 million annually into effect on a temporary basis in November 2009, subject to refund and pending final DPSC approval of the entirety of the requested increase. As permitted by Delaware law, DPL placed approximately $23.7 million of the remaining requested increase into effect on April 19, 2010, subject to refund and pending final DPSC approval. 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. Hearings on the unresolved issues in the case were concluded in late May 2010. In June 2010, the amount of the requested annual rate increase was lowered to approximately $24.2 million. A DPSC decision is expected by the end of 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. A settlement among the parties to this proceeding has been submitted to the DPSC and DPL anticipates that this proceeding will be merged with DPL’s natural gas base rate case discussed below.

On July 2, 2010, DPL submitted an application with the DPSC to increase its gas distribution base rates. The filing seeks approval of an annual rate increase of approximately $11.9 million, assuming the implementation of the MFVRD, based on a requested ROE of 11.00%. DPL intends to place an annual increase of approximately $2.5 million into effect on a temporary basis on August 31, 2010, subject to refund and pending final DPSC approval of the entirety of the requested increase. The DPSC is expected to issue a decision by February 2011.

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District of Columbia

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 reduced 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 approximately $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 District of Columbia Office of People’s Counsel (DC OPC) and the District of Columbia Water and Sewer Authority (WASA) also filed separate requests for reconsideration contesting certain other issues. On June 23, 2010, the DCPSC issued an order granting in part and denying in part Pepco’s application for reconsideration and denying the DC OPC’s and WASA’s respective motions for reconsideration. The impact of the decision is an additional increase in Pepco’s revenues of approximately $0.5 million annually, which took effect for customer usage on and after July 21, 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%. During the course of the proceeding, Pepco reduced its request to approximately $28.2 million. Evidentiary hearings were held in May 2010 and a decision by the Maryland Public Service Commission is expected in August 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 originally requested an annual net increase in retail distribution rates of approximately $54 million (which included 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). On February 19, 2010, ACE made a filing based on an updated test period and excluding the originally proposed reduction in the RARC, in which it reduced the requested increase to approximately $45.8 million without the adoption of the BSA (or approximately $44.1 million with the BSA). On May 12, 2010, the NJBPU approved a settlement entered into by the parties to the proceeding, which provides for an increase in electric distribution rates, effective for service rendered on and after June 1, 2010, of approximately $20 million based on a stated ROE of 10.30%. The settlement agreement provides that the BSA and certain other issues will be considered in a Phase 2 proceeding.

District of Columbia Divestiture Case

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

On May 18, 2010, the DCPSC issued an order addressing all of the remaining issues related to the sharing of the proceeds of Pepco’s divestiture of its generating assets. In the order, the DCPSC ruled that Pepco is not required to share EDIT and ADITC with customers. However, the order also disallowed certain items that Pepco had included in the costs deducted from the proceeds of the sale of the generation assets. The disallowance of these costs, together with interest on the allowed amount, increases the aggregate amount Pepco is required to distribute to customers, pursuant to the sharing formula, by approximately $11 million. On June 17, 2010, Pepco

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filed an application for reconsideration of the DCPSC’s order, contesting (i) approximately $5 million of the approximate total of $6 million in disallowances and (ii) approximately $4 million of the approximately $5 million in interest to be credited to customers (reflecting a difference in the period of time over which interest was calculated as well as the balance to which interest would be applied). On July 16, 2010, the DCPSC denied Pepco’s application for reconsideration. Pepco intends to appeal the DCPSC’s decision to the District of Columbia Court of Appeals. PHI recognized an expense of $2 million in the second quarter of 2010 with respect to this matter and, as of June 30, 2010, has $2 million accrued for this matter.

Pepco Energy Services Cooling Service Interruption – Atlantic City, New Jersey

On Thursday, July 15, 2010, Pepco Energy Services’ thermal energy business unit disconnected chilled water service to four facilities in Atlantic City, New Jersey due to a break in a 36-inch water line. Chilled water is used to provide air conditioning to the casinos and other customer facilities served by Pepco Energy Services. The affected facilities are located along the boardwalk in the Midtown area of Atlantic City; service to thermal customers not served by the water line was not affected. Pepco Energy Services secured replacement equipment including chillers, cooling towers and generators, and restored cooling service to the affected customers that needed service by Sunday, July 18, 2010. Pepco Energy Services then evaluated the water line failure, completed the permanent repair and was able to restore normal service to customers on July 23, 2010. The pre-tax cost of installing and operating the temporary cooling equipment and completing the repair of the water line is estimated to be $3 million to $4 million. Pepco Energy Services’ thermal energy service agreements with customers require Pepco Energy Services to undertake the repair of any assets that caused interruption of chilled water services. Under the agreements, the customers may seek to claim direct damages, such as costs to repair or replace customers’ assets, but are not entitled to indirect damages, such as lost profits or consequential damages. Because Pepco Energy Services incurred the costs to secure temporary chilled water service and to perform the permanent repair of the pipe leak, Pepco Energy Services currently expects that it has no additional material exposure from its customers for damages.

Retained Environmental Exposures from the Sale of the Conectiv Energy Wholesale Power Generation Business

On July 1, 2010, PHI sold the Conectiv Energy wholesale power generation business to Calpine. Under New Jersey’s Industrial Site Recovery Act (ISRA), the transfer of ownership triggered an obligation on the part of Conectiv Energy to remediate any environmental contamination at each of the eight Conectiv Energy generating facility sites located in New Jersey. Under the Purchase Agreement dated April 20, 2010, between PHI and Calpine for the sale of the Conectiv Energy wholesale power generation business (the Purchase Agreement), Calpine has assumed responsibility for performing the ISRA-required remediation and for the payment of all related ISRA compliance costs up to $10 million. According to preliminary estimates, the costs of ISRA-required remediation activities at the eight generating facility sites located in New Jersey range from approximately $7 million to $18 million. PHI has accrued $4 million as of June 30, 2010 for the ISRA-required remediation activities at the eight generating facility sites.

The sale of the Conectiv Energy wholesale power generation business to Calpine did not include a coal ash landfill site that PHI intends to close, located at Conectiv Energy’s Edge Moor generating facility. The preliminary estimate of the costs to PHI to close the coal ash landfill ranges from approximately $2 million to $3 million, plus annual post-closure operations, maintenance and monitoring costs, estimated to range between $120,000 and $193,000 per year for 30 years. In the second quarter of 2010, PHI accrued approximately $5 million for landfill closure and monitoring.

In orders issued in 2007, the New Jersey Department of Environmental Protection (NJDEP) assessed penalties against Conectiv Energy in an aggregate amount of approximately $2 million, based on NJDEP’s contention that Conectiv Energy’s Deepwater generating facility exceeded the maximum allowable hourly heat input limits during certain periods in calendar years 2004, 2005 and 2006. Conectiv Energy has appealed the NJDEP orders imposing these penalties to the New Jersey Office of Administrative Law. PHI is continuing to prosecute this appeal and, under the Purchase Agreement, has agreed to indemnify Calpine for monetary penalties, fines or assessments arising out of the NJDEP orders.

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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 June 30, 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.

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 potentially responsible party (PRP) that may have liability with respect to the site. If liable, ACE would be responsible for reimbursing EPA for clean-up costs incurred and to be incurred by the agency and for the costs of implementing an EPA-mandated remedy. 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.

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.

Indian River Oil Release

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

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the consent agreement. Based on current engineering estimates, DPL expects to incur future costs of approximately $6 million, $1 million of which will be incurred during the next 12 months, to fulfill its obligations under the consent agreement. In the second quarter of 2010, the liability for these estimated costs was increased to approximately $6 million, with a corresponding $4 million charge recorded in operating expenses for DPL.

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 June 30, 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 June 30, 2010, PHI has derived approximately $545 million in federal and state income tax benefits from the depreciation and interest deductions in excess of rental income with respect to these cross-border energy lease investments.

In 2005, the Treasury Department and IRS issued Notice 2005-13 identifying sale-leaseback transactions with certain attributes entered into with tax-indifferent parties as tax avoidance transactions, and the IRS announced its intention to disallow the associated tax benefits claimed by the investors in these transactions. PHI’s cross-border energy lease investments, each of which is with a tax-indifferent party, have been under examination by the IRS as part of the normal PHI federal income tax audits. In the final 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. During the latter part of 2010, PHI expects to pay the $74 million of additional tax claimed by the IRS to be due with respect to the cross border energy leases for 2001 and 2002, plus interest and penalties.

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 an offsetting $3 million after-tax non-cash earnings benefit during the latter part of 2010, once the tax payment for the 2001 and 2002 income tax returns is made.

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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 June 30, 2010, it would be obligated to pay approximately $655 million in additional federal and state taxes and $118 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 $773 million in federal and state taxes and interest due as of June 30, 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.

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 beginning with tax year 2011, and revises the District’s related party expense disallowance beginning with tax year 2009. Because the City Council must still enact further legislation providing guidance on how to implement combined unitary business reporting before this provision is effective, PHI believes that the legislative process was not complete as of June 30, 2010, and, therefore, the effect of the legislation for combined unitary business tax reporting has not been accounted for as of June 30, 2010. However, because the City Council is not required to enact any further legislation in order for the provisions for the disallowance of related party transactions to become effective, PHI accrued approximately $500,000 of additional income tax expense during the first quarter of 2010.

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

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

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

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

As of June 30, 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								Total
	PHI		DPL		ACE		Pepco
Energy marketing obligations of Conectiv Energy (a)	$	295	$	—	$	—	$	—	$	295
Energy procurement obligations of Pepco Energy Services (a)		361		—		—		—		361
Guaranteed lease residual values (b)		—		4		2		2		8
Total	$	656	$	4	$	2	$	2	$	664

(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 June 30, 2010, obligations under the guarantees were approximately $8 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.

Pepco Energy Services has entered into various energy savings guaranty contracts associated with the installation of energy savings equipment for federal, state and local government customers. As part of those contracts, Pepco Energy Services typically guarantees that the installed equipment will generate a specified amount of energy savings on an annual basis based on contractually established performance measures. The maximum term on the remaining guarantees ends in fifteen years with the amount of the guarantees beginning to decline in nine years. On an annual basis, Pepco Energy Services undertakes a measurement and verification process to determine the amount of energy savings for the current year and whether the annual energy savings is less than the guaranteed amount. Pepco Energy Services recognizes a liability in an amount equal to the estimated annual energy savings shortfall when it is probable that the guaranteed annual energy savings amount would not be achieved based on the actual energy savings determined through the annual measurement and verification process. During the six month period ended June 30, 2010, the liability for energy savings guaranty contracts did not change because Pepco Energy Services did not make any significant payouts under the guarantees and there was not a significant change in the guarantees issued or expired. At June 30, 2010, the liability for energy savings guaranty contracts was less than $1 million.

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

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Dividends

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

(15) DISCONTINUED OPERATIONS

On April 20, 2010, the Board of Directors of PHI approved a plan for the disposition of Conectiv Energy. The plan consists of (i) the sale of Conectiv Energy’s wholesale power generation business and (ii) the liquidation, within the succeeding twelve months, of all of Conectiv Energy’s remaining assets and businesses, including its load service supply contracts, energy hedging portfolio, certain tolling agreements and other non-generation assets. In accordance with the plan, PHI on the same day entered into the Purchase Agreement with Calpine, under the terms of which, Calpine agreed to purchase Conectiv Energy’s wholesale power generation business.

On July 1, 2010, PHI completed the sale of the wholesale power generation business to Calpine. Under the terms of the Purchase Agreement, dated April 20, 2010, the $1.65 billion sale price was subject to several adjustments, including a $49 million payment for the value of the fuel inventory at the time of the closing and a $60 million reduction in the closing payment attributable to lower capital expenditures incurred by PHI than was anticipated at the time of execution of the Purchase Agreement for Conectiv Energy’s 565 megawatt combined cycle generating facility that is under construction (known as the Delta Project) during the period from January 1, 2010 through the date of the closing. After giving effect to these and other adjustments, PHI received proceeds at the closing in the amount of approximately $1.63 billion (subject to possible post-closing adjustments).

As a result of the adoption of the plan of disposition, PHI commenced reporting the results of operations of the former Conectiv Energy segment in discontinued operations in all periods presented in the accompanying Consolidated Statements of Income. Further, the assets and liabilities of Conectiv Energy, excluding the related current and deferred income tax accounts and certain retained liabilities, are reported as held for sale as of each date presented in the accompanying Consolidated Balance Sheets.

Operating Results

The operating results of Conectiv Energy are as follows:

	Three Months Ended June  30						Six Months Ended June  30,
	2010			2009			2010			2009
	(millions of dollars)
Income (loss) from operations of discontinued operations, net of income taxes	$	2		$	(14	)	$	8		$	(10	)
Net losses from dispositions of assets and businesses of discontinued operations, net of income taxes		(132	)		—			(130	)		—
Loss From Discontinued Operations, net of income taxes	$	(130	)	$	(14	)	$	(122	)	$	(10	)

The line item “Income (loss) from operations of discontinued businesses, net of income taxes,” for both the three and six months ended June 30, 2010, includes after-tax expenses for employee severance and retention benefits of $9 million and after-tax accrued expenses for certain obligations associated with the anticipated sale of the wholesale power generation business to Calpine of $13 million, each recorded in the second quarter of 2010.

The line item “Net losses from dispositions of assets and businesses of discontinued operations, net of income taxes” includes the following:

Write-down of Wholesale Power Generation Business. With the long-lived assets of the Conectiv Energy wholesale power generation business (the disposal group) held for sale as of June 30, 2010, PHI determined that the fair value of the assets, based on the Calpine purchase price and less costs to sell, was less than the carrying value of the assets. Accordingly, PHI recorded an after-tax write-down of the long-lived assets of the Conectiv Energy wholesale power generation business of $67 million during the second quarter of 2010. The write-down includes after-tax transaction expenses of $13 million.

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The calculation of the actual after-tax loss on the sale will require a final determination of certain closing and post-closing adjustments and transaction expenses. Although PHI believes that its current estimates and assumptions reflected in the write-down are reasonable, the actual after-tax loss on the sale may differ from the estimated after-tax write-down of $67 million.

Income Tax Charges. In the second quarter of 2010, PHI recorded $14 million of additional income tax charges related to the anticipated sale of the wholesale power generation business to Calpine in order to establish valuation allowances against certain deferred tax assets associated with state net operating losses of tax-reporting entities expected to be sold in the transaction, to remeasure deferred taxes for expected changes in state income tax apportionment factors and to write off certain tax credit carryforwards no longer expected to be realized.

Liquidation of Assets and Businesses Not Sold to Calpine. In the second quarter of 2010, PHI began the process of liquidating the Conectiv Energy assets and businesses not being sold to Calpine, including its load service supply contracts, energy hedging portfolio, certain tolling agreements and other non-generation assets. With respect to certain derivative instruments associated with Conectiv Energy’s load service supply business, PHI concluded that these instruments no longer qualify for cash flow hedge accounting. Under this accounting method, the effective portion of the gain or loss on the derivative ordinarily is reported as a component of Accumulated Other Comprehensive Income (Loss) and is reclassified into income in the same period or periods during which the hedged transactions affect income. When the Board of Directors of PHI approved a plan for the disposition of Conectiv Energy on April 20, 2010, PHI determined that certain of the forecasted transactions that these derivative instruments were hedging (load service supply contracts) were probable not to occur. Accordingly, during the second quarter of 2010, PHI recognized $83 million of pre-tax unrealized losses ($50 million after tax) that previously were included in Accumulated Other Comprehensive Loss. Certain additional dispositions of load service supply contracts and related hedges contributed $1 million of after-tax net losses for the three months ended June 30, 2010 and $1 million of after-tax net gains for the six months ended June 30, 2010.

PHI currently estimates that the sale of the wholesale power generation business to Calpine and the liquidation of the remaining Conectiv Energy assets and businesses will result in a loss through the completion of the liquidation for financial reporting purposes ranging from $75 million to $100 million, after tax. This range of loss includes estimates of (i) the loss on the Calpine transaction, including transaction expenses, (ii) the additional income tax charges associated with the Calpine transaction, (iii) expenses for employee severance and retention benefits, and (iv) accrued expenses for certain obligations associated with the Calpine transaction, offset by (v) estimates of gains from the anticipated disposition of Conectiv Energy’s remaining assets and businesses not included in the Calpine sale, including load service supply contracts, the energy hedging portfolio, certain tolling agreements and other non-generation assets. The loss recognized in the second quarter of 2010 has exceeded the estimated range of loss because certain unrealized losses associated with derivative instruments that no longer qualify for cash flow hedge accounting have been recognized in the second quarter of 2010, and these losses are expected to be reduced primarily by gains from future dispositions of the load service supply contracts.

The estimated after-tax proceeds from the sale of the wholesale power generation business to Calpine and the liquidation of the remaining Conectiv Energy assets and businesses, combined with the return of cash collateral posted under the contracts, are expected to total approximately $1.7 billion, with related income tax payments approximating $200 million.

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Balance Sheet Information

Details of the assets and liabilities of Conectiv Energy held for sale at June 30, 2010 and December 31, 2009 are as follows:

	June 30, 2010			December 31, 2009
	(millions of dollars)
Current Assets
Cash and cash equivalents	$	18		$	2
Accounts receivable, less allowance for uncollectible accounts		158			194
Inventories		87			128
Derivative assets		17			21
Prepaid expenses and other		1			1
Total Current Assets		281			346
Investments And Other Assets
Derivative assets		18			27
Other		1			2
Total Investments and Other Assets		19			29
Property, Plant And Equipment
Property, plant and equipment		2,262	(a)		2,286
Accumulated depreciation		(675	)		(664	)
Net Property, Plant and Equipment		1,587			1,622
Current Liabilities
Accounts payable and accrued liabilities		118			138
Derivative liabilities		33			37
Other		13			16
Total Current Liabilities		164			191
Deferred Credits
Derivative liabilities		17			8
Other		6			11
Total Deferred Credits		23			19
Net Assets	$	1,700		$	1,787

(a) Includes pre-tax write-down to fair value less costs to sell of $115 million recorded in the second quarter of 2010.

Derivative Instruments and Hedging Activities

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

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Through June 30, 2010, Conectiv Energy has purchased energy commodity contracts in the form of futures, swaps, options and forward contracts to hedge price risk in connection with the purchase of physical natural gas, oil and coal to fuel its generation assets for sale to customers. Conectiv Energy also has purchased energy commodity contracts in the form of electricity swaps, options and forward contracts to hedge price risk in connection with the purchase of electricity for delivery to requirements-load customers. Through June 30, 2010, Conectiv Energy has sold electricity swaps, options and forward contracts to hedge price risk in connection with electric output from its generating facilities. Conectiv Energy accounts for most of its futures, swaps and certain forward contracts as cash flow hedges of forecasted transactions. Derivative contracts purchased or sold in excess of probable amounts of forecasted hedge transactions are marked-to-market through current earnings. All option contracts are marked-to-market through current earnings. Certain natural gas and oil futures and swaps have been used as fair value hedges to protect the value of natural gas transportation contracts and physical fuel inventory. Some forward contracts are accounted for using standard accrual accounting since these contracts meet the requirements for normal purchase and normal sale accounting.

The tables below identify the balance sheet location and fair values of Conectiv Energy’s derivative instruments as of June 30, 2010 and December 31, 2009:

	As of June 30, 2010
Balance Sheet Caption	Derivatives Designated as Hedging Instruments			Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting			Net Derivative Instruments
	(millions of dollars)
Derivative Assets (current assets held for sale)	$	3		$	710		$	713		$	(696	)	$	17
Derivative Assets (non-current assets held for sale)		—			65			65			(47	)		18
Total Derivative Assets		3			775			778			(743	)		35
Derivative Liabilities (current liabilities associated with assets held for sale)		(57	)		(813	)		(870	)		837			(33	)
Derivative Liabilities (non-current liabilities associated with assets held for sale)		—			(58	)		(58	)		41			(17	)
Total Derivative Liabilities		(57	)		(871	)		(928	)		878			(50	)
Net Derivative (Liability) Asset	$	(54	)	$	(96	)	$	(150	)	$	135		$	(15	)

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	As of December 31, 2009
Balance Sheet Caption	Derivatives Designated as Hedging Instruments			Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting			Net Derivative Instruments
	(millions of dollars)
Derivative Assets (current assets held for sale)	$	52		$	574		$	626		$	(605	)	$	21
Derivative Assets (non-current assets held for sale)		23			44			67			(40	)		27
Total Derivative Assets		75			618			693			(645	)		48
Derivative Liabilities (current liabilities associated with assets held for sale)		(236	)		(575	)		(811	)		774			(37	)
Derivative Liabilities (non-current liabilities associated with assets held for sale)		(14	)		(27	)		(41	)		33			(8	)
Total Derivative Liabilities		(250	)		(602	)		(852	)		807			(45	)
Net Derivative (Liability) Asset	$	(175	)	$	16		$	(159	)	$	162		$	3

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

	June 30, 2010			December 31, 2009
	(millions of dollars)
Cash collateral pledged to counterparties with the right to reclaim	$	142		$	168
Cash collateral received from counterparties with the obligation to return		(7	)		(6	)

As of June 30, 2010 and December 31, 2009, all cash collateral pledged or received related to Conectiv Energy’s derivative instruments accounted for at fair value was entitled to offset under master netting agreements.

Derivatives Designated as Hedging Instruments

Cash Flow Hedges

For energy commodity contracts that are designated and qualify as cash flow hedges, the effective portion of the gain or loss on the derivative is reported as a component of 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 of Conectiv Energy during the three and six months ended June 30, 2010 and 2009 is provided in the table below:

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	Three Months Ended June  30,						Six Months Ended June  30,
	2010			2009			2010			2009
	(millions of dollars)
Amount of net pre-tax gain (loss) arising during the period included in other comprehensive loss	$	44		$	(11	)	$	(74	)	$	(176	)
Amount of net pre-tax (loss) gain reclassified into income:
Effective portion:
Loss from Discontinued Operations, net of income taxes		(61	)		(72	)		(106	)		(119	)
Ineffective portion:
Loss from Discontinued Operations, net of income taxes (a) (b)		(84	)		3			(87	)		(3	)
Total net (loss) gain reclassified into income		(145	)		(69	)		(193	)		(122	)
Net pre-tax gain (loss) on commodity derivatives included in other comprehensive loss	$	189		$	58		$	119		$	(54	)

(a) For the three months ended June 30, 2010 and 2009, amounts of $87 million and $1 million, respectively, were reclassified from AOCL to income because the forecasted transactions were deemed probable not to occur.

(b) For the six months ended June 30, 2010 and 2009, amounts of $88 million and $3 million, respectively, were reclassified from AOCL to income because the forecasted transactions were deemed probable not to occur.

As of June 30, 2010 and December 31, 2009, Conectiv Energy had the following types and volumes of energy commodity contracts employed as cash flow hedges of forecasted purchases and forecasted sales.

	Quantities
Commodity	June 30, 2010	December 31, 2009
Forecasted Purchases Hedges
Coal (Tons)	—	325,000
Natural gas (One Million British Thermal Units (MMBtu))	—	43,032,500
Electricity (Megawatt hours (MWh))	2,519,813	10,758,844
Heating oil (Barrels)	22,000	89,000
Forecasted Sales Hedges
Coal (Tons)	—	255,000
Natural gas (MMBtu)	—	3,859,643
Electricity (MWh)	100,368	5,701,472
Electric capacity (MW-Days)	—	203,640
Financial transmission rights (MWh)	24,768	48,014

Cash Flow Hedges Included in Accumulated Other Comprehensive Loss

The tables below provide details regarding effective cash flow hedges of Conectiv Energy included in PHI’s consolidated balance sheet as of June 30, 2010 and December 31, 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:

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	Accumulated Other Comprehensive Loss After-tax (a)		Portion Expected to be Reclassified to Income during the Next 12 Months		Maximum Term
	(millions of dollars)
Energy Commodity Contracts as of June 30, 2010 (a)	$	32	$	32	6 months
Energy Commodity Contracts as of June 30, 2009 (a)	$	139	$	105	54 months

(a) The unrealized derivative losses recorded in Accumulated Other Comprehensive Loss are largely offset by forecasted natural gas and electricity physical purchases in gain positions that are subject to accrual accounting. These forward purchase contracts are exempted from mark-to-market accounting because they either qualify as normal purchases under FASB guidance on derivatives and hedging or they are not derivative contracts. Under accrual accounting, no asset is recorded on the balance sheet for these contracts, and the purchase cost is not recognized until the period of delivery.

Fair Value Hedges

In connection with its energy commodity activities, Conectiv Energy designates certain derivatives as fair value hedges. For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative as well as the offsetting gain or loss on the hedged item attributable to the hedged risk is recognized in current income. For the three and six months ended June 30, 2010, there was no such gain or loss recognized. For each of the three and six months ended June 30, 2009, the net gains recognized in Loss from Discontinued Operations, net of tax, were $1 million. As of June 30, 2010, Conectiv Energy had no outstanding commodity forward contract derivatives that were accounted for as fair value hedges of fuel inventory and natural gas transportation.

Other Derivative Activity

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

The amount of the derivative gain (loss) for Conectiv Energy included in Loss from Discontinued Operations, net of income taxes, for the three and six months ended June 30, 2010 and 2009, is provided in the table below:

	Three Months Ended June  30,						Six Months Ended June  30,
	2010			2009			2010			2009
	(millions of dollars)
Realized mark-to-market gains (losses)	$	23		$	(11	)	$	26		$	36
Unrealized mark-to-market (losses) gains		(23	)		(9	)		(24	)		(49	)
Total net mark-to-market (losses) gains	$	—		$	(20	)	$	2		$	(13	)

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As of June 30, 2010 and December 31, 2009, Conectiv Energy had the following net outstanding commodity forward contract volumes and net position on derivatives that did not qualify for hedge accounting:

	June 30, 2010		December 31, 2009
Commodity	Quantity	Net Position	Quantity	Net Position
Coal (Tons)	—	—	60,000	Long
Emissions (Tons)	325,000	Short	—	—
Natural gas (MMBtu)	3,432,911	Long	2,268,024	Long
Natural gas basis (MMBtu)	—	—	12,445,000	Long
Heating oil (Barrels)	—	—	139,000	Short
RBOB UL gasoline (Barrels)	1,000	Short	—	—
Electricity (MWh)	7,803,108	Long	76,324	Long
Electric capacity (MW-Days)	148,410	Short	—	—
Financial transmission rights (MWh)	1,165,600	Short	1,241,237	Short

Contingent Credit Risk Features

The primary contracts used by Conectiv Energy for derivative transactions are generally the same as those described in Note (12), “Derivative Instruments and Hedging Activities,” and include comparable provisions for mutual posting and administration of collateral security. If the aggregate fair value of the transactions in a net loss position exceeds the unsecured credit threshold, then collateral is required to be posted in an amount equal to the amount by which the unsecured credit threshold is exceeded. The obligations of Conectiv Energy are usually guaranteed by PHI. If PHI’s credit rating were to fall below “investment grade,” the unsecured credit threshold would typically be set at zero and collateral would be required for the entire net loss position. Exchange-traded contracts are required to be fully collateralized without regard to the credit rating of the holder.

The gross fair value of Conectiv Energy’s derivative liabilities, excluding the impact of offsetting transactions or collateral under master netting agreements, with credit risk-related contingent features on June 30, 2010 and December 31, 2009, was $209 million and $179 million, respectively. As of those dates, Conectiv Energy had posted cash collateral of $15 million and $17 million, respectively, in the normal course of business against the gross derivative liability resulting in a net liability of $194 million and $162 million, respectively, before giving effect to offsetting transactions that are encompassed within master netting agreements that would reduce this amount. Conectiv Energy’s net settlement amount in the event of a downgrade of PHI below “investment grade” as of June 30, 2010 and December 31, 2009, would have been approximately $70 million and $63 million, respectively, after taking into consideration the master netting agreements. The offsetting transactions or collateral that would reduce Conectiv Energy’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 June 30, 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, including Conectiv Energy, totaled $918 million and $820 million, respectively.

Fair Value Disclosures

Conectiv Energy 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, that is further described in Note (13), “Fair Value Disclosures.”

As of June 30, 2010 level 2 instruments primarily consist of electricity derivatives and wholesale gas futures and swaps. Power swaps are priced at liquid trading hub prices or valued using the liquid hub prices plus a congestion adder that is calculated using historical regression analysis. Natural gas futures and swaps are valued using broker quotes in liquid markets, and other observable pricing data.

The level 3 instruments with the most significant amount of fair value at June 30, 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.

The following tables set forth, by level within the fair value hierarchy, Conectiv Energy’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2010 and December 31, 2009:

	Fair Value Measurements at June 30, 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
Natural Gas (a)	$	4	$	—	$	4	$	—
Electricity (b)		29		—		6		23
Capacity		9		9		—		—
	$	42	$	9	$	10	$	23
LIABILITIES
Derivative instruments
Coal (c)	$	1	$	—	$	1	$	—
Natural Gas (a)		86		57		29		—
Electricity (b)		105		—		105		—
	$	192	$	57	$	135	$	—

(a) Represents wholesale gas futures and swaps that are used mainly as part of Conectiv Energy’s generation.

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

(b) Represent over-the-counter swaps that are part of fuel input for Conectiv Energy’s generation strategy.

	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 (a)	$	8	$	—	$	8	$	—
Natural Gas (b)		4		—		4		—
Electricity (c)		34		—		4		30
Capacity (d)		8		8		—		—
	$	54	$	8	$	16	$	30
LIABILITIES
Derivative instruments
Coal (a)	$	6	$	—	$	6	$	—
Natural Gas (b)		74		52		22		—
Electricity (c)		126		—		123		3
Oil (e)		5		4		1		—
Capacity (d)		2		2		—		—
	$	213	$	58	$	152	$	3

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

(b) Represents wholesale gas futures and swaps that are used mainly as part of Conectiv Energy’s generation strategy.

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

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

(e) Represents oil futures that are mainly part of Conectiv Energy’s fuel input generation strategy.

Reconciliations of the beginning and ending balances of Conectiv Energy’s fair value measurements using significant unobservable inputs (Level 3) for the six months ended June 30, 2010 and 2009 are shown below:

	Six Months Ended June 30,
	2010			2009
	(millions of dollars)
Beginning balance as of January 1	$	27		$	2
Total gains or (losses) (realized and unrealized)
Included in loss from discontinued operations, net of tax (a)		47			4
Included in accumulated other comprehensive loss		2			9
Purchases and issuances		—			—
Settlements		(53	)		(2	)
Transfers in (out) of Level 3		—			—
Ending balance as of June 30	$	23		$	13

(a) For the six months ended June 30, 2010, $8 million of the $47 million gain is still held as of the reporting date. For the six months ended June 30, 2009, $4 million of the $4 million gain is still held as of the reporting date.

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POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
	(millions of dollars)
Operating Revenue	$	539		$	518		$	1,091		$	1,095
Operating Expenses
Purchased energy		261			273			576			622
Other operation and maintenance		73			81			161			160
Depreciation and amortization		40			37			78			72
Other taxes		88			74			163			147
Effect of settlement of Mirant bankruptcy claims		—			—			—			(14	)
Total Operating Expenses		462			465			978			987
Operating Income		77			53			113			108
Other Income (Expenses)
Interest and dividend income		1			—			1			1
Interest expense		(25	)		(25	)		(50	)		(50	)
Other income		2			3			5			5
Other expenses		—			(1	)		—			(1	)
Total Other Expenses		(22	)		(23	)		(44	)		(45	)
Income Before Income Tax Expense		55			30			69			63
Income Tax Expense		23			13			29			27
Net Income		32			17			40			36
Retained Earnings at Beginning of Period		713			643			730			624
Dividends paid to Parent		(25	)		—			(50	)		—
Retained Earnings at End of Period	$	720		$	660		$	720		$	660

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

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POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

(Unaudited)

	June 30, 2010			December 31, 2009
	(millions of dollars)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	157		$	213
Restricted cash equivalents		—			1
Accounts receivable, less allowance for uncollectible accounts of $20 million and $17 million, respectively		401			354
Inventories		46			43
Prepayments of income taxes		67			79
Prepaid expenses and other		16			48
Total Current Assets		687			738
INVESTMENTS AND OTHER ASSETS
Regulatory assets		175			166
Prepaid pension expense		285			295
Investment in trust		24			25
Income taxes receivable		62			64
Other		79			70
Total Investments and Other Assets		625			620
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		5,989			5,865
Accumulated depreciation		(2,543	)		(2,481	)
Net Property, Plant and Equipment		3,446			3,384
TOTAL ASSETS	$	4,758		$	4,742

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

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POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

(Unaudited)

	June 30, 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		199		154
Accounts payable due to associated companies		74		111
Capital lease obligations due within one year		7		7
Taxes accrued		61		37
Interest accrued		18		18
Other		127		124
Total Current Liabilities		486		467
DEFERRED CREDITS
Regulatory liabilities		143		145
Deferred income taxes, net		903		893
Investment tax credits		7		8
Other postretirement benefit obligation		74		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		89		92
Total Long-Term Liabilities		1,628		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		720		730
Total Equity		1,425		1,435
TOTAL LIABILITIES AND EQUITY	$	4,758	$	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)

	Six Months Ended June 30,
	2010			2009
	(millions of dollars)
OPERATING ACTIVITIES
Net income	$	40		$	36
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		78			72
Effect of settlement of Mirant bankruptcy claims		—			(14	)
Changes in restricted cash equivalents related to Mirant settlement		—			38
Deferred income taxes		23			18
Changes in:
Accounts receivable		(47	)		18
Regulatory assets and liabilities, net		(15	)		(11	)
Accounts payable and accrued liabilities		18			(40	)
Pension contributions		—			(150	)
Taxes accrued		37			91
Other assets and liabilities		20			18
Net Cash From Operating Activities		154			76
INVESTING ACTIVITIES
Investment in property, plant and equipment		(136	)		(130	)
Changes in restricted cash equivalents		1			—
Net other investing activities		1			1
Net Cash Used By Investing Activities		(134	)		(129	)
FINANCING ACTIVITIES
Dividends paid to Parent		(50	)		—
Capital contribution from Parent		—			50
Issuances of long-term debt		—			110
Reacquisition of long-term debt		(16	)		(50	)
Repayments of short-term debt, net		—			(125	)
Net other financing activities		(10	)		(9	)
Net Cash Used by Financing Activities		(76	)		(24	)
Net Decrease in Cash and Cash Equivalents		(56	)		(77	)
Cash and Cash Equivalents at Beginning of Period		213			146
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	157		$	69
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash received for income taxes (includes payments from PHI for Federal income taxes)	$	16		$	86

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. 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 June 30, 2010, in accordance with GAAP. The year-end December 31, 2009 balance sheet was derived from audited financial statements, but does not include all disclosures required by GAAP. Interim results for the three and six months ended June 30, 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 were originally estimated at March 31, 2010 to be $15 million with $11 million charged to Other Operation and Maintenance expense for repair work and $4 million recorded as capital expenditures. A portion of the costs of the restoration work relates to services provided by outside contractors and other utilities, and since billings for such services in certain instances had not been received at March 31, 2010, the costs were estimated at that date. The actual billings received during the second quarter of 2010 resulted in final costs of $10 million, with $8 million charged to Other Operation and Maintenance expense and $2 million

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recorded as capital expenditures, which reflects a reduction in the Other Operation and Maintenance expense of $3 million in the second quarter of 2010 and a reduction of $2 million originally recorded as capital expenditures.

In May 2010, Pepco provided its updated network service transmission rate to the Federal Energy Regulatory Commission (FERC) effective June 1, 2010 through May 31, 2011 that included a true-up of costs incurred in the prior service year that had not yet been reflected in rates charged to customers. The recording of the difference between the true-ups provided to the FERC and the estimated true-up calculation as of March 31, 2010 resulted in an increase in transmission service revenue of $3 million in the second quarter of 2010.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in Pepco’s gross revenues were $80 million and $62 million for the three months ended June 30, 2010 and 2009, respectively, and $142 million and $123 million for the six months ended June 30, 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 removed the concept of a qualifying special-purpose entity (QSPE) from the guidance on transfers and servicing and the QSPE scope exception in the guidance on consolidation. The new guidance also 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 its overall financial condition, results of operations, or cash flows.

Consolidation of Variable Interest Entities (ASC 810)

The FASB issued new consolidation guidance regarding variable interest entities effective January 1, 2010 that eliminated the 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 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 its overall financial condition, results of operations, or cash flows.

Fair Value Measurements and Disclosures (ASC 820)

The FASB issued new disclosure requirements for recurring and non-recurring fair value measurements. The guidance, effective beginning with Pepco’s March 31, 2010 financial statements, requires the disaggregation of balance sheet items measured at fair value into subsets of balance sheet items based on the nature and risks of the items. The standard requires descriptions of pricing inputs and valuation

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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 eliminated 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 Measurements 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 its financial statements.

(5) SEGMENT INFORMATION

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

(6) 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 June 30, 2010 and 2009, before intercompany allocations from the PHI Service Company, of $31 million and $44 million, respectively, included $13 million and $11 million, respectively, for Pepco’s allocated share. PHI’s pension and other postretirement net periodic benefit cost for the six months ended June 30, 2010 and 2009, before intercompany allocations from the PHI Service Company, of $60 million and $75 million, respectively, included $20 million and $19 million, respectively, 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 June 30, 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 $450 million and $582 million, respectively.

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(8) INCOME TAXES

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

	Three Months Ended June  30,				Six Months Ended June  30,
	2010		2009		2010		2009
Federal statutory rate	35.0	%	35.0	%	35.0	%	35.0	%
Increases (decreases) resulting from:
Depreciation	2.9		4.0		3.6		4.0
Asset removal costs	(1.1	)	(2.0	)	(1.6	)	(1.7	)
State income taxes, net of federal effect	5.4		6.0		5.5		5.9
Tax credits	(0.7	)	(1.3	)	(1.3	)	(1.4	)
Change in estimates and interest related to uncertain and effectively settled tax positions	2.2		4.0		3.2		2.7
Permanent differences related to deferred compensation funding	(0.6	)	(1.0	)	(0.7	)	(0.8	)
Other, net	(1.3	)	(1.4	)	(1.7	)	(0.8	)
Effective Income Tax Rate	41.8	%	43.3	%	42.0	%	42.9	%

Pepco’s effective tax rates for the three months ended June 30, 2010 and 2009 were 41.8% and 43.3%, respectively. The decrease in the rate primarily resulted from changes in estimates and interest relating to uncertain and effectively settled tax positions, partially offset by the effect of certain flow-through tax differences as well as an increase in the flow-through amount of software amortization.

Pepco’s effective tax rates for the six months ended June 30, 2010 and 2009 were 42.0% and 42.9%, respectively. The decrease in the rate primarily resulted from a decrease in other, most notably related to the amortization of software costs which are required by the Company’s regulators to be treated as a permanent difference. This decrease is partially offset by changes in estimates and interest related to uncertain and effectively settled tax positions 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

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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.

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

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

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

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

The following tables set forth, by level within the fair value hierarchy, Pepco’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 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.

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	Fair Value Measurements at June 30, 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		—		36		19
	$	64	$	9	$	36	$	19
LIABILITIES
Executive deferred compensation plan liabilities
Life Insurance Contracts	$	12	$	—	$	12	$	—
	$	12	$	—	$	12	$	—

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

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Reconciliations of the beginning and ending balances of Pepco’s fair value measurements using significant unobservable inputs (Level 3) for the six months ended June 30, 2010 and 2009 are shown below:

	Six Months Ended June 30, 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		2
Included in accumulated other comprehensive (losses) income		—
Purchases and issuances		(1	)
Settlements		—
Transfers in (out) of Level 3		—
Ending balance as of June 30, 2010	$	19
	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	$	2
Change in unrealized gains relating to assets still held at reporting date	$	2
	Six Months Ended June 30, 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		2
Included in accumulated other comprehensive (losses) income		—
Purchases and issuances		(1	)
Settlements		—
Transfers in (out) of Level 3		—
Ending balance as of June 30, 2009	$	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	$	2
Change in unrealized gains relating to assets still held at reporting date	$	2

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Fair Value of Debt Instruments

The estimated fair values of Pepco’s non-derivative financial instruments at June 30, 2010 and December 31, 2009 are shown below:

	June 30, 2010				December 31, 2009
	(millions of dollars)
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	1,539	$	1,757	$	1,555	$	1,707

The methods and assumptions described below were used to estimate, as of June 30, 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 June 30, 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.

(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. To date, a bill stabilization adjustment mechanism (BSA) has been approved and implemented for electric service in Maryland and 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

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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 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 return on equity (ROE) of 11.25% (subsequently reduced 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 approximately $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 District of Columbia Office of People’s Counsel (DC OPC) and the District of Columbia Water and Sewer Authority (WASA) also filed separate requests for reconsideration contesting certain other issues. On June 23, 2010, the DCPSC issued an order granting in part and denying in part Pepco’s application for reconsideration and denying the DC OPC’s and WASA’s respective motions for reconsideration. The impact of the decision is an additional increase in Pepco’s revenues of approximately $0.5 million annually, which took effect for customer usage on and after July 21, 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%. During the course of the proceeding, Pepco reduced its request to approximately $28.2 million. Evidentiary hearings were held in May 2010 and a decision by the Maryland Public Service Commission is expected in August 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 in 2000. This approval left unresolved issues of (i) whether Pepco should be required to share with customers the excess deferred income taxes (EDIT) and accumulated deferred investment tax credits (ADITC) associated with the sold assets and, if so, whether such sharing would violate the normalization provisions of the Internal Revenue Code and its implementing regulations and (ii) whether Pepco was entitled to deduct certain costs in determining the amount of proceeds to be shared.

On May 18, 2010, the DCPSC issued an order addressing all of the remaining issues related to the sharing of the proceeds of Pepco’s divestiture of its generating assets. In the order, the DCPSC ruled that Pepco is not required to share EDIT and ADITC with customers. However, the order also disallowed certain items that Pepco had included in the costs deducted from the proceeds of the sale of the generation assets. The disallowance of these costs, together with interest on the allowed amount, increases the aggregate amount Pepco is required to distribute to customers, pursuant to the sharing formula, by approximately $11 million. On June 17, 2010, Pepco filed an application for reconsideration of the DCPSC’s order, contesting (i) approximately $5 million of the approximate total of $6 million in disallowances and (ii) approximately $4 million of the approximately $5 million in interest to be credited to customers (reflecting a difference in the period of time over which interest was calculated as well as the balance to which interest would be

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applied). On July 16, 2010, the DCPSC denied Pepco’s application for reconsideration. Pepco intends to appeal the DCPSC’s decision to the District of Columbia Court of Appeals. PHI recognized an expense of $2 million in the second quarter of 2010 with respect to this matter and, as of June 30, 2010, has $2 million accrued for this matter.

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 June 30, 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 Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA) with respect to the cleanup of the Peck Iron and Metal site in Portsmouth, Virginia, 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

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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 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 beginning with tax year 2011, and revises the District’s related party expense disallowance beginning with tax year 2009. Because the City Council must still enact further legislation providing guidance on how to implement combined unitary business reporting before this provision is effective, PHI believes that the legislative process was not complete as of June 30, 2010, and, therefore, the effect of the legislation for combined unitary business tax reporting has not been accounted for as of June 30, 2010.

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

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

(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 June 30, 2010 and 2009 were approximately $41 million in each reporting period. PHI Service Company costs directly charged or allocated to Pepco for the six months ended June 30, 2010 and 2009 were approximately $85 and $84 million, respectively.

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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 June 30, 2010 and 2009 were approximately $2 million each. Amounts charged to Pepco by these companies for the six months ended June 30, 2010 and 2009 were approximately $3 million and $4 million, respectively.

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

	For the Three  Months Ended June 30,				For the Six Months Ended June 30,
Income (Expense)	2010		2009		2010		2009
	(millions of dollars)
Intercompany power purchases – Conectiv Energy Supply (a)	$	—	$	1	$	—	$	1

(a) Included in purchased energy expense.

As of June 30, 2010 and December 31, 2009, Pepco had the following balances on its balance sheets due to related parties:

	June 30, 2010			December 31, 2009
Asset (Liability)	(millions of dollars)
Payable to Related Party (current) (a)
PHI Parent Company	$	—		$	(8	)
PHI Service Company		(15	)		(3	)
Pepco Energy Services (b)		(59	)		(99	)
Other		—			(1	)
Total	$	(74	)	$	(111	)
Money Pool Balance with Pepco Holdings (included in Cash and cash equivalents)	$	146		$	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 June  30,						Six Months Ended June  30,
	2010			2009			2010			2009
	(millions of dollars)
Operating Revenue
Electric	$	260		$	251		$	559		$	572
Natural Gas		36			40			131			171
Total Operating Revenue		296			291			690			743
Operating Expenses
Purchased energy		159			161			360			380
Gas purchased		25			27			91			128
Other operation and maintenance		65			59			126			118
Depreciation and amortization		20			18			40			37
Other taxes		8			9			18			19
Total Operating Expenses		277			274			635			682
Operating Income		19			17			55			61
Other Income (Expenses)
Interest expense		(12	)		(11	)		(22	)		(22	)
Other income		2			1			3			1
Total Other Expenses		(10	)		(10	)		(19	)		(21	)
Income Before Income Tax Expense		9			7			36			40
Income Tax Expense		3			2			16			14
Net Income		6			5			20			26
Retained Earnings at Beginning of Period		486			441			472			448
Dividends Paid to Parent		(23	)		—			(23	)		(28	)
Retained Earnings at End of Period	$	469		$	446		$	469		$	446

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

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DELMARVA POWER & LIGHT COMPANY

BALANCE SHEETS

(Unaudited)

	June 30, 2010			December 31, 2009
	(millions of dollars)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	69		$	26
Accounts receivable, less allowance for uncollectible accounts of $14 million and $12 million, respectively		174			193
Inventories		38			40
Prepayments of income taxes		49			64
Prepaid expenses and other		11			19
Total Current Assets		341			342
INVESTMENTS AND OTHER ASSETS
Goodwill		8			8
Regulatory assets		226			207
Prepaid pension expense		148			157
Other		24			28
Total Investments and Other Assets		406			400
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		2,916			2,807
Accumulated depreciation		(880	)		(860	)
Net Property, Plant and Equipment		2,036			1,947
TOTAL ASSETS	$	2,783		$	2,689

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

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DELMARVA POWER & LIGHT COMPANY

BALANCE SHEETS

(Unaudited)

	June 30, 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		66		31
Accounts payable and accrued liabilities		96		106
Accounts payable due to associated companies		21		14
Taxes accrued		3		3
Interest accrued		7		6
Derivative liabilities		17		15
Other		68		64
Total Current Liabilities		383		344
DEFERRED CREDITS
Regulatory liabilities		299		290
Deferred income taxes, net		492		489
Investment tax credits		7		7
Other postretirement benefit obligation		26		23
Above-market purchased energy contracts and other electric restructuring liabilities		16		17
Liabilities and accrued interest related to uncertain tax positions		17		20
Derivative liabilities		12		13
Other		27		23
Total Deferred Credits		896		882
LONG-TERM LIABILITIES
Long-term debt		699		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		469		472
Total Equity		805		808
TOTAL LIABILITIES AND EQUITY	$	2,783	$	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)

	Six Months Ended June 30,
	2010			2009
	(millions of dollars)
OPERATING ACTIVITIES
Net income	$	20		$	26
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		40			37
Deferred income taxes		3			22
Changes in:
Accounts receivable		17			28
Inventories		2			11
Regulatory assets and liabilities, net		(6	)		38
Accounts payable and accrued liabilities		7			(47	)
Pension contributions		—			(10	)
Taxes accrued		15			(35	)
Other assets and liabilities		29			12
Net Cash From Operating Activities		127			82
INVESTING ACTIVITIES
Investment in property, plant and equipment		(133	)		(84	)
Net other investing activities		(1	)		—
Net Cash Used By Investing Activities		(134	)		(84	)
FINANCING ACTIVITIES
Dividends paid to Parent		(23	)		(28	)
Issuances of long-term debt		78			—
Issuances of short-term debt, net		—			9
Net other financing activities		(5	)		(2	)
Net Cash From (Used By) Financing Activities		50			(21	)
Net Increase (Decrease) in Cash and Cash Equivalents		43			(23	)
Cash and Cash Equivalents at Beginning of Period		26			138
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	69		$	115
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash (received) paid for income taxes (includes payments (from) to PHI for Federal income taxes)	$	(3	)	$	28

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. 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 June 30, 2010, in accordance with GAAP. The year-end December 31, 2009 balance sheet was derived from audited financial statements, but does not include all disclosures required by GAAP. Interim results for the three and six months ended June 30, 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 were originally estimated at March 31, 2010 to be $6 million with $4 million charged to Other Operation and Maintenance expense for repair work and $2 million recorded as capital expenditures. A portion of the costs of the restoration work relates to services provided by outside contractors and other utilities, and since billings for such services in certain instances had not been received at March 31, 2010, the costs were estimated at that date. The actual billings received during the second quarter of 2010 did not result in a significant change in the amounts recorded to Other Operation and Maintenance expense or capital expenditures.

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In May 2010, DPL provided its updated network service transmission rate to the Federal Energy Regulatory Commission (FERC) effective June 1, 2010 through May 31, 2011 that included a true-up of costs incurred in the prior service year that had not yet been reflected in rates charged to customers. The recording of the difference between the true-ups provided to the FERC and the estimated true-up calculation as of March 31, 2010 resulted in an increase in transmission service revenue of $3 million in the second quarter of 2010.

DPL Renewable Energy Transactions

DPL has entered into four wind power purchase agreements (PPAs) in amounts up to a total of 350 megawatts and one solar renewable energy credit (REC) purchase agreement with a nine megawatt facility. Of the wind PPAs, three of them are with land-based facilities and one is with an offshore facility. The Delaware Public Service Commission (DPSC) has approved the four wind 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. The solar agreement is being reviewed by the DPSC. The RECs purchased under all the agreements, as described below, will help DPL fulfill a portion of its requirements under the State of Delaware’s Renewable Energy Portfolio Standards Act.

One of the land-based wind facilities became operational and went into service in December 2009. DPL is obligated to purchase energy and RECs from this facility through 2024 in amounts generated and delivered not to exceed 50.25 megawatts at rates that are primarily fixed. Payments under the other wind agreements are currently expected to start in the fourth quarter of 2010 for the other two land-based contracts and 2016 for the offshore contract, if the projects are ultimately completed and operational. The terms of the agreements with the 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. The term of the agreement with the solar facility is 20 years and DPL is obligated to purchase RECs in an amount up to seventy percent of the energy output from the solar facility at a fixed price once the PPA is approved by the DPSC and the facility is operational.

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

Goodwill

Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired at the acquisition date. All of DPL’s goodwill was generated by DPL’s acquisition of Conowingo Power Company in 1995. DPL tests its goodwill for impairment annually and whenever an event occurs or circumstances change in the interim that would more likely than not reduce the fair value of DPL below its carrying amount. DPL performs its annual impairment test on November 1. Factors that may result in an interim impairment test include, but are not limited to: a change in the identified reporting units; an adverse 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 six months ended June 30, 2010.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in DPL’s gross revenues were $4 million for the three months ended June 30, 2010 and 2009, and $9 million for the six months ended June 30, 2010 and 2009.

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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 second quarter of 2009, DPL recorded an adjustment to correct certain income tax errors related to prior periods. The adjustment resulted in a decrease in income tax expense of $1 million for the three and six months ended June 30, 2009.

(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Transfers and Servicing (ASC 860)

The FASB issued new guidance that removed the concept of a qualifying special-purpose entity (QSPE) from the guidance on transfers and servicing and the QSPE scope exception in the guidance on consolidation. The new guidance also 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 its overall financial condition, results of operations, or cash flows.

Consolidation of Variable Interest Entities (ASC 810)

The FASB issued new consolidation guidance regarding variable interest entities effective January 1, 2010 that eliminated the 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 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 its overall financial condition, results of operations, or cash flows.

Fair Value Measurements and Disclosures (ASC 820)

The FASB issued new disclosure requirements for recurring and non-recurring fair value measurements. The guidance, effective beginning with DPL’s March 31, 2010 financial statements, requires the disaggregation of balance sheet items measured at fair value into subsets of balance sheet items based on the nature and risks of the items. The standard requires descriptions of pricing inputs and valuation methodologies for instruments with Level 2 or 3 valuation inputs. In addition, the standard requires information about any 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 eliminated 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 Measurements 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 its financial statements.

(5) SEGMENT INFORMATION

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

(6) GOODWILL

DPL’s goodwill balance of $8 million was unchanged during the three and six month periods ending June 30, 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 June 30, 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 June 30, 2010 and 2009, before intercompany allocations from the PHI Service Company, of $31 million and $44 million, respectively, included $10 million and $7 million, respectively, for DPL’s allocated share. PHI’s pension and other postretirement net periodic benefit cost for the six months ended June 30, 2010 and 2009, before intercompany allocations from the PHI Service Company, of $60 million and $75 million, respectively, included $14 million and $12 million, respectively, 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 June 30, 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 $450 million and $582 million, respectively.

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Other Financing Activities

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. The bonds bear interest at the fixed rate of 5.40% per annum, payable each February 1 and August 1, commencing August 1, 2010. DPL used the proceeds of the loan 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, which 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:

• $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.

As the owner of these bonds, DPL received the proceeds from the redemption of the bonds, which it used for general corporate purposes.

Financing Activity Subsequent to June 30, 2010

On July 1, 2010, DPL repurchased $31 million of tax-exempt bonds pursuant to a put provision of the bonds. DPL intends to remarket these bonds in the second half of 2010.

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(9) INCOME TAXES

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

	Three Months Ended June  30,				Six Months Ended June 30,
	2010		2009		2010		2009
Federal statutory rate	35.0	%	35.0	%	35.0	%	35.0	%
Increases (decreases) resulting from:
Depreciation	6.7		5.7		2.2		2.0
State income taxes, net of federal effect	5.6		5.7		5.0		5.5
Tax credits	(2.2	)	(2.9	)	(1.1	)	(1.0	)
Change in estimates and interest related to uncertain and effectively settled tax positions	(7.8	)	(18.6	)	3.6		(6.0	)
Other, net	(4.0	)	3.7		(0.3	)	(0.5	)
Effective Income Tax Rate	33.3	%	28.6	%	44.4	%	35.0	%

DPL’s effective tax rates for the three months ended June 30, 2010 and 2009 were 33.3% and 28.6%, 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 due to the 2009 filing of an amended state income tax return to recover unused net operating losses.

DPL’s effective tax rates for the six months ended June 30, 2010 and 2009 were 44.4% and 35.0%, respectively. The increase in the rate resulted from the change in estimates and interest related to uncertain and effectively settled tax positions, primarily related to the $2 million reversal of accrued interest income on state income tax positions in 2010 that DPL no longer believes is more likely than not to be realized and the tax benefits related to the filing of the amended state income tax returns recorded in 2009.

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.

(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.

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The table below identifies the balance sheet location and fair values of derivative instruments as of June 30, 2010 and December 31, 2009:

	As of June 30, 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)		(10	)		(17	)		(27	)		10		(17	)
Derivative Liabilities (non-current liabilities)		—			(12	)		(12	)		—		(12	)
Total Derivative Liabilities		(10	)		(29	)		(39	)		10		(29	)
Net Derivative (Liability) Asset	$	(10	)	$	(29	)	$	(39	)	$	10	$	(29	)

	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:

	June 30, 2010		December 31, 2009
	(millions of dollars)
Cash collateral pledged to counterparties with the right to reclaim	$	10	$	11

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As of June 30, 2010 and December 31, 2009, all DPL cash collateral pledged or received related to derivatives accounted for at fair value was 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 and six months ended June 30, 2010 and 2009:

	Three Months Ended June  30,						Six Months Ended June  30,
	2010			2009			2010			2009
	(millions of dollars)
Net Gain Deferred as a Regulatory Asset or Liability	$	5		$	11		$	—		$	11
Net Loss Reclassified from Regulatory Asset or Liability to Purchased Energy or Gas Purchased		(3	)		(10	)		(5	)		(26	)

As of June 30, 2010 and December 31, 2009, DPL had the following outstanding commodity forward contracts that were entered into to hedge forecasted transactions:

	Quantities
Commodity	June 30, 2010	December 31, 2009
Forecasted Purchases Hedges:
Natural Gas (One Million British Thermal Units (MMBtu))	3,820,000	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 and six months ended June 30, 2010 and 2009 the amount of the derivative gain (loss) recognized in the statements of income is provided in the table below by line item:

	Three Months Ended June  30,						Six Months Ended June  30,
	2010			2009			2010			2009
	(millions of dollars)
Net Gain (Loss) Deferred as a Regulatory Asset or Liability	$	7		$	4		$	1		$	(10	)
Net Loss Reclassified from Regulatory Asset or Liability to Purchased Energy or Gas Purchased		(6	)		(2	)		(13	)		(5	)

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As of June 30, 2010 and December 31, 2009, DPL had the following net outstanding natural gas commodity forward contracts that did not qualify for hedge accounting:

	June 30, 2010		December 31, 2009
Commodity	Quantity	Net Position	Quantity	Net Position
Natural Gas (MMBtu)	9,824,825	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 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 June 30, 2010 and December 31, 2009, was $29 million and $28 million, respectively. As of those dates, DPL had posted cash collateral of zero and less than a million dollars, respectively, in the normal course of business against the gross derivative liability resulting in a net liability of $29 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 June 30, 2010 and December 31, 2009, would have been approximately $25 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 June 30, 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 $450 million and $582 million, respectively.

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(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.

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

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

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

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

The following tables set forth, by level within the fair value hierarchy, DPL’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 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 June 30, 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	$	3	$	3	$	—	$	—
Life Insurance Contracts		1		—		—		1
	$	4	$	3	$	—	$	1
LIABILITIES
Derivative instruments
Natural Gas (a)	$	39	$	10	$	—	$	29
	$	39	$	10	$	—	$	29

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

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

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Reconciliations of the beginning and ending balances of DPL’s fair value measurements using significant unobservable inputs (Level 3) for the six months ended June 30, 2010 and 2009 are shown below:

	Six Months Ended June 30, 2010
	Natural Gas			Life Insurance Contracts
	(millions of dollars)
Beginning balance as of January 1, 2010	$	(29	)	$	1
Total gains or (losses) (realized and unrealized)
Included in income		—			—
Included in accumulated other comprehensive loss		—			—
Included in regulatory liabilities		(10	)		—
Purchases and issuances		—			—
Settlements		10			—
Transfers in (out) of Level 3		—			—
Ending balance as of June 30, 2010	$	(29	)	$	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				$	—
	Six Months Ended June 30, 2009
	Natural Gas			Life Insurance Contracts
	(millions of dollars)
Beginning balance as of January 1, 2009	$	(24	)	$	1
Total gains or (losses) (realized and unrealized)
Included in income		—			—
Included in accumulated other comprehensive loss		—			—
Included in regulatory liabilities		(15	)		—
Purchases and issuances		—			—
Settlements		7			—
Transfers in (out) of Level 3		—			—
Ending balance as of June 30, 2009	$	(32	)	$	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				$	—

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DPL

Fair Value of Debt Instruments

The estimated fair values of DPL’s non-derivative financial instruments at June 30, 2010 and December 31, 2009 are shown below:

	June 30, 2010				December 31, 2009
	(millions of dollars)
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	765	$	825	$	686	$	733

The methods and assumptions described below were used to estimate, as of June 30, 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 June 30, 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.

(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.

• An MFVRD has been approved in concept for natural gas service in Delaware. Based on a settlement among the parties to the ongoing gas decoupling proceeding, implementation of the MFVRD will be considered as part of DPL’s pending natural gas distribution base rate case filed on July 2, 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

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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 DPL’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 to the DPSC its 2009 Gas Cost Rate (GCR) filing, which permits DPL to recover gas procurement costs through customer rates. 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. DPL, the Delaware Division of the Public Advocate and DPSC staff have entered into a settlement agreement supporting the rates as filed. A Hearing Examiner’s report on the rate proposal is expected in the third quarter of 2010.

In September 2009, DPL submitted an application with the DPSC to increase its electric distribution base rates. The filing, as revised in March 2010, sought approval of an annual rate increase of approximately $26.2 million, assuming approval of the implementation of the MFVRD, based on a requested return on equity (ROE) of 10.75%. As permitted by Delaware law, DPL placed an increase of approximately $2.5 million annually into effect on a temporary basis in November 2009, subject to refund and pending final DPSC approval of the entirety of the requested increase. As permitted by Delaware law, DPL placed approximately $23.7 million of the remaining requested increase into effect on April 19, 2010, subject to refund and pending final DPSC approval. 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. Hearings on the unresolved issues in the case were concluded in late May 2010. In June 2010, the amount of the requested annual rate increase was lowered to approximately $24.2 million. A DPSC decision is expected by the end of 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. A settlement among the parties to this proceeding has been submitted to the DPSC and DPL anticipates that this proceeding will be merged with DPL’s natural gas base rate case discussed below.

On July 2, 2010, DPL submitted an application with the DPSC to increase its gas distribution base rates. The filing seeks approval of an annual rate increase of approximately $11.9 million, assuming the implementation of the MFVRD, based on a requested ROE of 11.00%. DPL intends to place an annual increase of approximately $2.5 million into effect on a temporary basis on August 31, 2010, subject to refund and pending final DPSC approval of the entirety of the requested increase. The DPSC is expected to issue a decision by February 2011.

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.

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Ward Transformer Site. In April 2009, a group of potentially responsible parties (PRPs) with respect to the Ward Transformer site in Raleigh, North Carolina, filed a complaint in the U.S. District Court for the Eastern District of North Carolina, alleging cost recovery and/or contribution claims against 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.

Indian River Oil Release

In 2001, DPL entered into a consent agreement with the Delaware Department of Natural Resources and Environmental Control for remediation, site restoration, natural resource damage compensatory projects and other costs associated with environmental contamination resulting from an oil release at the Indian River generating facility, which was sold in June 2001. DPL has a continuing obligation with respect to the costs under the consent agreement. Based on current engineering estimates, DPL expects to incur future costs of approximately $6 million, $1 million of which will be incurred during the next 12 months, to fulfill its obligations under the consent agreement. In the second quarter of 2010, the liability for these estimated costs was increased to approximately $6 million, with a corresponding $4 million charge recorded in operating expenses for DPL.

(13) RELATED PARTY TRANSACTIONS

PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries including DPL. The cost of these services is allocated in accordance with cost allocation methodologies set forth in the service agreement using a variety of factors, including the subsidiaries’ share of employees, operating expenses, assets, and other cost causal methods. These intercompany transactions are eliminated by PHI in consolidation and no profit results from these transactions at PHI. PHI Service Company costs directly charged or allocated to DPL for the three months ended June 30, 2010 and 2009 were approximately $31 million in each reporting period. PHI Service Company costs directly charged or allocated to DPL for the six months ended June 30, 2010 and 2009 were approximately $65 million and $63 million, respectively.

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

	For the Three  Months Ended June 30,						For the Six Months Ended June 30,
Income (Expenses)	2010			2009			2010			2009
	(millions of dollars)
Purchased power under Default Electricity Supply contracts with Conectiv Energy Supply, Inc. (a)	$	(20	)	$	(22	)	$	(39	)	$	(59	)
Intercompany lease transactions (b)		2			2			4			4

(a) Included in purchased energy expense.

(b) Included in electric revenue.

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As of June 30, 2010 and December 31, 2009, DPL had the following balances on its balance sheets due to related parties:

Asset (Liability)	June 30, 2010			December 31, 2009
	(millions of dollars)
Receivable from (Payable to) Related Party (current) (a)
PHI Service Company	$	(8	)	$	22
PHI Parent Company		—			(27	)
Conectiv Energy Supply, Inc.		(11	)		(7	)
Pepco Energy Services, Inc. and its subsidiaries (Pepco Energy Services) (b)		(2	)		(3	)
Other		—			1
Total	$	(21	)	$	(14	)
Money Pool Balance with PHI (included in cash and cash equivalents)	$	63		$	—

(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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ACE

ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended June  30,						Six Months Ended June  30,
	2010			2009			2010			2009
	(millions of dollars)
Operating Revenue	$	315		$	287		$	632		$	631
Operating Expenses
Purchased energy		243			239			478			516
Other operation and maintenance		47			47			97			95
Depreciation and amortization		25			24			49			49
Other taxes		6			5			12			10
Deferred electric service costs		(63	)		(57	)		(82	)		(84	)
Total Operating Expenses		258			258			554			586
Operating Income		57			29			78			45
Other Income (Expenses)
Interest expense		(16	)		(17	)		(32	)		(34	)
Other income		1			—			1			1
Total Other Expenses		(15	)		(17	)		(31	)		(33	)
Income Before Income Tax Expense		42			12			47			12
Income Tax Expense		16			4			23			2
Net Income		26			8			24			10
Retained Earnings at Beginning of Period		141			144			143			166
Dividends Paid to Parent		—			—			—			(24	)
Retained Earnings at End of Period	$	167		$	152		$	167		$	152

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

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ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30, 2010			December 31, 2009
	(millions of dollars)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	4		$	7
Restricted cash equivalents		9			10
Accounts receivable, less allowance for uncollectible accounts of $8 million and $7 million, respectively		195			176
Inventories		16			15
Prepayments of income taxes		31			38
Prepaid expenses and other		61			12
Total Current Assets		316			258
INVESTMENTS AND OTHER ASSETS
Regulatory assets		696			712
Prepaid pension expense		57			63
Income taxes receivable		71			76
Restricted cash equivalents		3			4
Assets and accrued interest related to uncertain tax positions		61			57
Other		10			9
Total Investments and Other Assets		898			921
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		2,390			2,328
Accumulated depreciation		(716	)		(699	)
Net Property, Plant and Equipment		1,674			1,629
TOTAL ASSETS	$	2,888		$	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)

	June 30, 2010		December 31, 2009
	(millions of dollars, except shares)
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Short-term debt	$	193	$	83
Current portion of long-term debt		36		35
Accounts payable and accrued liabilities		135		120
Accounts payable due to associated companies		22		58
Taxes accrued		19		5
Interest accrued		13		13
Other		39		42
Total Current Liabilities		457		356
DEFERRED CREDITS
Regulatory liabilities		94		178
Deferred income taxes, net		612		604
Investment tax credits		9		9
Other postretirement benefit obligation		28		25
Other		10		11
Total Deferred Credits		753		827
LONG-TERM LIABILITIES
Long-term debt		632		609
Transition Bonds issued by ACE Funding		351		368
Total Long-Term Liabilities		983		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		496		473
Retained earnings		167		143
Total Equity		689		642
TOTAL LIABILITIES AND EQUITY	$	2,888	$	2,808

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

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ACE

ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended June 30,
	2010			2009
	(millions of dollars)
OPERATING ACTIVITIES
Net income	$	24		$	10
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		49			49
Deferred income taxes		7			23
Changes in:
Accounts receivable		(19	)		32
Regulatory assets and liabilities, net		(84	)		(109	)
Accounts payable and accrued liabilities		(24	)		2
Pension contributions		—			(60	)
Prepaid New Jersey sales and excise tax		(52	)		(58	)
Taxes accrued		22			(3	)
Other assets and liabilities		8			6
Net Cash Used By Operating Activities		(69	)		(108	)
INVESTING ACTIVITIES
Investment in property, plant and equipment		(76	)		(67	)
Net other investing activities		2			1
Net Cash Used By Investing Activities		(74	)		(66	)
FINANCING ACTIVITIES
Dividends paid to Parent		—			(24	)
Capital contribution from Parent		23			40
Issuances of long-term debt		23			—
Reacquisition of long-term debt		(16	)		(15	)
Issuances of short-term debt, net		110			116
Net other financing activities		—			(3	)
Net Cash From Financing Activities		140			114
Net Decrease in Cash and Cash Equivalents		(3	)		(60	)
Cash and Cash Equivalents at Beginning of Period		7			65
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	4		$	5
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid (received) for income taxes (includes payments to (from) PHI for Federal income taxes)	$	1		$	(16	)

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 June 30, 2010, in accordance with GAAP. The year-end December 31, 2009 balance sheet was derived from audited financial statements, but does not include all disclosures required by GAAP. Interim results for the three and six months ended June 30, 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 were originally estimated at March 31, 2010 to be $16 million with $3 million charged to Other Operation and Maintenance expense for repair work and $13 million recorded as capital expenditures. A portion of the costs of the restoration work relates to services provided by outside contractors and other utilities, and since billings for such services in certain instances had not been received at March 31, 2010, the costs were estimated at that date. The actual billings received during the second quarter of 2010 did not result in a significant change in the amounts recorded to Other Operation and Maintenance expense or capital expenditures.

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In May 2010, ACE provided its updated network service transmission rate to the Federal Energy Regulatory Commission (FERC) effective June 1, 2010 through May 31, 2011 that included a true-up of costs incurred in the prior service year that had not yet been reflected in rates charged to customers. The recording of the difference between the true-ups provided to the FERC and the estimated true-up calculation as of March 31, 2010 resulted in an increase in transmission service revenue of $2 million in the second quarter of 2010.

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. Despite exhaustive efforts to obtain information from these entities during the three months ended June 30, 2010, PHI 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 June 30, 2010 and 2009 were approximately $67 million and $61 million, respectively, of which approximately $62 million and $59 million, respectively, consisted of power purchases under the PPAs. Net purchase activities with the NUGs for the six months ended June 30, 2010 and 2009 were approximately $140 million and $144 million, respectively, of which approximately $129 million and $131 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 non-bypassable Transition Bond Charges (the Transition Bond Charges) from ACE customers pursuant to bondable stranded costs rate orders issued by the New Jersey Board of Public Utilities (NJBPU) in an amount sufficient to fund the principal and interest payments on the Transition Bonds and related taxes, expenses and fees (Bondable Transition Property). ACE collects the Transition Bond Charges from its customers on behalf of ACE Funding and the holders of the Transition Bonds. The assets of ACE Funding, including the Bondable Transition Property, and the Transition Bond Charges collected from ACE’s customers, are not available to creditors of ACE. The holders of the Transition Bonds have recourse only to the assets of ACE Funding. ACE owns 100 percent of the equity of ACE Funding and 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 $5 million for the three months ended June 30, 2010 and 2009, and $10 million for the six months ended June 30, 2010 and 2009.

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Reclassifications and Adjustments

Certain prior period amounts have been reclassified in order to conform to current period presentation. The following adjustments have been recorded 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 and second quarters of 2009, ACE recorded adjustments to correct certain income tax errors related to prior periods. These adjustments, which were not considered material, resulted in an increase in income tax expense of $1 million for the three months ended June 30, 2009, and a decrease in income tax expense of $1 million for the six months ended June 30, 2009.

(3) NEWLY ADOPTED ACCOUNTING STANDARDS

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

The FASB issued new guidance that removed the concept of a qualifying special-purpose entity (QSPE) from the guidance on transfers and servicing and the QSPE scope exception in the guidance on consolidation. The new guidance also 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 its overall financial condition, results of operations, or cash flows.

Consolidation of Variable Interest Entities (ASC 810)

The FASB issued new consolidation guidance regarding variable interest entities effective January 1, 2010 that eliminated the 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 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 its overall financial condition, results of operations, or cash flows.

Fair Value Measurements and Disclosures (ASC 820)

The FASB issued new disclosure requirements for recurring and non-recurring fair value measurements. The guidance, effective beginning with ACE’s March 31, 2010 financial statements, requires the disaggregation of balance sheet items measured at fair value into subsets of balance sheet items based on the nature and risks of the items. The standard requires descriptions of pricing inputs and valuation methodologies for instruments with Level 2 or 3 valuation inputs. In addition, the standard requires information about any 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 eliminated 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.”

(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Fair Value Measurements 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 its financial statements.

(5) SEGMENT INFORMATION

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

(6) 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 June 30, 2010 and 2009, before intercompany allocations from the PHI Service Company, of $31 million and $44 million, respectively, included $7 million and $6 million, respectively, for ACE’s allocated share. PHI’s pension and other postretirement net periodic benefit cost for the six months ended June 30, 2010 and 2009, before intercompany allocations from the PHI Service Company, of $60 million and $75 million, respectively, included $11 million and $10 million, respectively, 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 June 30, 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 $450 million and $582 million, respectively.

Other Financing Activities

During the three months ended June 30, 2010, the following financing activities occurred:

In April 2010, ACE Funding made principal payments of $5.6 million on Series 2002-1 Bonds, Class A-2, and $2.2 million on Series 2003-1 Bonds, Class A-2.

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On June 1, 2010 ACE replaced the letters of credit associated with (i) $18.2 million of The Pollution Control Financing Authority of Salem County Pollution Control Revenue Refunding Bonds, 1997 Series A (Atlantic City Electric Company Project) due April 15, 2014 (the 1997 Series A Bonds) and (ii) $4.4 million of The Pollution Control Financing Authority of Salem County Pollution Control Revenue Refunding Bonds, 1997 Series B (Atlantic City Electric Company Project) due July 15, 2017 (the 1997 Series B Bonds), both of which expired on June 23, 2010, with new irrevocable direct pay letters of credit. The new letters of credit supporting the 1997 Series A Bonds and the 1997 Series B Bonds expire on April 15, 2014 and June 1, 2013, respectively.

(8) INCOME TAXES

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

	For the Three  Months Ended June 30,				For the Six Months Ended June 30,
	2010		2009		2010		2009
Federal statutory rate	35.0	%	35.0	%	35.0	%	35.0	%
Increases (decreases) resulting from:
Depreciation	(0.2	)	(0.8	)	(0.4	)	(2.5	)
State income taxes, net of federal effect	6.4		8.3		6.8		10.0
Tax credits	(0.5	)	(2.5	)	(1.1	)	(4.2	)
Change in estimates and interest related to uncertain and effectively settled tax positions	(2.1	)	(3.3	)	8.9		(14.2	)
Adjustment to prior year taxes	—		—		—		(8.3	)
Other, net	(0.5	)	(3.4	)	(0.3	)	0.9
Consolidated Effective Income Tax Rate	38.1	%	33.3	%	48.9	%	16.7	%

ACE’s consolidated effective tax rates for the three months ended June 30, 2010 and 2009 were 38.1% and 33.3%, respectively. The increase in the rate resulted from the amortization of tax credits, and changes in estimates and interest related to uncertain and effectively settled tax positions, partially offset by the impact of certain permanent state tax differences.

ACE’s consolidated effective tax rates for the six months ended June 30, 2010 and 2009 were 48.9% and 16.7%, respectively. The increase in the rate resulted from the amortization of tax credits and the reversal of $6 million of accrued interest income on uncertain and effectively settled state income tax positions and the $1 million non-recurring adjustment in 2009 to prior year taxes. This increase is partially offset by the impact of certain permanent state tax differences.

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.

(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

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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.

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

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

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

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 June 30, 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.

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	Fair Value Measurements at June 30, 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	$	12	$	12	$	—	$	—
	$	12	$	12	$	—	$	—
LIABILITIES
Executive deferred compensation plan liabilities
Life Insurance Contracts	$	1	$	—	$	1	$	—
	$	1	$	—	$	1	$	—

	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 June 30, 2010 and December 31, 2009 are shown below:

	June 30, 2010				December 31, 2009
	(millions of dollars)
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	633	$	727	$	610	$	674
Transition Bonds issued by ACE Funding		386		433		402		427
Redeemable Serial Preferred Stock		6		5		6		4

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The methods and assumptions described below were used to estimate, as of June 30, 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 June 30, 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.

(10) COMMITMENTS AND CONTINGENCIES

Rate Proceedings

In recent electric service distribution base rate cases, ACE has proposed the adoption of a revenue decoupling method for retail customers. To date a proposed bill stabilization adjustment mechanism (BSA) remains pending 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, ACE 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 ACE to promote energy efficiency programs for their customers, because it breaks the link between overall sales volumes and distribution revenues.

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 originally requested an annual net increase in retail distribution rates of approximately $54 million (which included a reduction to its Regulatory Asset Recovery Charge (RARC)) based on a requested return on equity (ROE) of 11.50% (or an increase of approximately $52 million, based on an ROE of 11.25%, if the BSA were approved). On February 19, 2010, ACE made a filing based on an updated test period and excluding the originally proposed reduction in the RARC, in which it reduced the requested increase to approximately $45.8 million without the adoption of the BSA (or approximately $44.1 million with the BSA). On May 12, 2010, the NJBPU approved a settlement entered into by the parties to the proceeding, which provides for an increase in electric distribution rates, effective for service rendered on and after June 1, 2010, of approximately $20 million based on a stated ROE of 10.30%. The settlement agreement provides that the BSA and certain other issues will be considered in a Phase 2 proceeding.

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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.

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 potentially responsible party (PRP) that may have liability with respect to the site. If liable, ACE would be responsible for reimbursing EPA for clean-up costs incurred and to be incurred by the agency and for the costs of implementing an EPA-mandated remedy. 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. 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.

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Appeal of New Jersey Flood Hazard Regulations. In November 2007, the New Jersey Department of Environmental Protection adopted amendments to the agency’s regulations under the Flood Hazard Area Control Act (FHACA) to minimize damage to life and property from flooding caused by development in flood plains. The amended regulations impose a new regulatory program to mitigate flooding and related environmental impacts from a broad range of construction and development activities, including electric utility transmission and distribution construction 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 June 30, 2010 and 2009 were approximately $19 million and $25 million, respectively. PHI Service Company costs directly charged or allocated to ACE for the six months ended June 30, 2010 and 2009 were approximately $45 million and $50 million, respectively.

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

	For the Three  Months Ended June 30,						For the Six Months Ended June 30,
Income (Expense)	2010			2009			2010			2009
	(millions of dollars)
Purchased power under Default Electricity Supply contracts with Conectiv Energy Supply, Inc. (a)	$	(41	)	$	(41	)	$	(80	)	$	(87	)
Meter reading services provided by Millennium Account Services LLC (b)		(1	)		(1	)		(2	)		(2	)
Intercompany lease transactions (b)		—			—			(1	)		(1	)
Intercompany use revenue (c)		1			—			1			3

(a) Included in purchased energy expense.

(b) Included in other operation and maintenance expense.

(c) Included in operating revenue.

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As of June 30, 2010 and December 31, 2009, ACE had the following balances on its balance sheets due to related parties:

Asset (Liability)	June 30, 2010			December 31, 2009
	(millions of dollars)
Payable to Related Party (current) (a)
PHI Service Company	$	(2	)	$	(38	)
PHI Parent Company		—			(3	)
Conectiv Energy Supply, Inc.		(19	)		(15	)
Other		(1	)		(2	)
Total	$	(22	)	$	(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	107
Pepco	144
DPL	151
ACE	159

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

Pepco Holdings, Inc.

General Overview

Pepco Holdings, Inc. (PHI or Pepco Holdings), a Delaware corporation incorporated in 2001, is a holding company that, through its regulated public utility subsidiaries, is engaged primarily in the distribution, transmission and default supply of electricity and the delivery and supply of natural gas (Power Delivery), PHI also has been engaged in the competitive energy generation, marketing and supply business (Competitive Energy), which it has conducted through subsidiaries of Conectiv Energy Holding Company (collectively Conectiv Energy) and through Pepco Energy Services, Inc. and its subsidiaries (collectively, Pepco Energy Services), each of which has constituted a separate segment for financial reporting purposes. As more fully described below, PHI is in the process of disposing of Conectiv Energy and is winding down the retail energy supply portion of the business of Pepco Energy Services.

The following table sets forth the percentage contributions to consolidated operating revenue and operating income from continuing operations, (including intercompany transactions) attributable to the Power Delivery and Pepco Energy Services segments.

	Three Months Ended June 30,				Six Months Ended June 30,
	2010		2009		2010		2009
Percentage of Consolidated Operating Revenue
Power Delivery	70	%	66	%	70	%	67	%
Pepco Energy Services	29	%	34	%	30	%	33	%
Intercompany transactions and other	1	%	—	%	—	%	—	%
Percentage of Consolidated Operating Income
Power Delivery	79	%	69	%	76	%	75	%
Pepco Energy Services	12	%	20	%	15	%	15	%
Intercompany transactions and other	9	%	11	%	9	%	10	%
Percentage of Power Delivery Operating Revenue
Power Delivery Electric	97	%	96	%	95	%	93	%
Power Delivery Gas	3	%	4	%	5	%	7	%

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 a single operating segment for financial reporting purposes.

The Power Delivery business is conducted by PHI’s three utility subsidiaries: Potomac Electric Power Company (Pepco), Delmarva Power & Light Company (DPL) and Atlantic City Electric Company (ACE). Each of these companies is a regulated public utility in the jurisdictions that comprise its service territory. Each company is responsible for the 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.

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

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

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 (i) 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 (ii) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that Pepco and DPL are entitled to earn based on the approved distribution charge per customer.

Competitive Energy

On April 20, 2010, the Board of Directors of PHI approved a plan for the disposition of Conectiv Energy. On July 1, 2010, PHI completed the sale of Conectiv Energy’s wholesale power generation business to Calpine Corporation (Calpine) for $1.63 billion. PHI is currently in the process of liquidating all of the Conectiv Energy segment’s remaining operations, consisting of its load service supply contracts, energy hedging portfolio, certain tolling agreements and other assets not included in the Calpine sale, which PHI expects to complete within a period of 12 months following the announcement of the disposition plan. In view of the adoption of a plan of disposition for the Conectiv Energy segment, in the financial statements for the period ended June 30, 2010, the entire Conectiv Energy segment is being accounted for as a discontinued operation and the business is no longer being treated as a separate segment for financial reporting purposes. Accordingly, in this Discussion and Analysis of Financial Condition and Results of Operations, all references to continuing operations exclude the operations of the Conectiv Energy segment.

PHI currently estimates that the sale of the wholesale power generation business to Calpine and the liquidation of the remaining Conectiv Energy assets and businesses will result in a loss through the completion of the liquidation for financial reporting purposes ranging from $75 million to $100 million, after tax. This range of loss includes estimates of (i) the loss on the Calpine transaction, including transaction expenses, (ii) the additional income tax charges associated with the Calpine transaction, (iii) expenses for employee severance and retention benefits, and (iv) accrued expenses for certain obligations associated with the Calpine transaction, offset by (v) estimates of gains from the anticipated disposition of Conectiv

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Energy’s remaining assets and businesses not included in the Calpine sale, including load service supply contracts, the energy hedging portfolio, certain tolling agreements and other non-generation assets. The loss recognized in the second quarter of 2010 has exceeded the estimated range of loss because certain unrealized losses associated with derivative instruments that no longer qualify for cash flow hedge accounting have been recognized in the second quarter of 2010, and these losses are expected to be reduced primarily by gains from future dispositions of the load service supply contracts.

The estimated after-tax proceeds from the sale of the wholesale power generation business to Calpine and the liquidation of the remaining Conectiv Energy assets and businesses, combined with the return of cash collateral posted under the contracts, are expected to total approximately $1.7 billion, with related income tax payments approximating $200 million.

The business of the Pepco Energy Services segment has consisted primarily of (i) the retail supply of electricity and natural gas and (ii) providing energy savings performance contracting services principally to federal, state and local government customers, and designing, constructing and operating combined heat and power and central energy plants for customers (Energy Services). Pepco Energy Services also owns and operates two oil-fired generation facilities. In December 2009, PHI announced that it will wind down the retail energy supply component of the Pepco Energy Services business. Pepco Energy Services is implementing this wind down by not entering into any new supply contracts, while continuing to perform under its existing supply contracts through the expiration dates of those contracts.

The retail energy supply business has historically generated a substantial portion of the operating revenues and net income of the Pepco Energy Services segment. Operating revenues related to the retail energy supply business for the three months ended June 30, 2010 and 2009 were $401 million and $534 million, respectively, while operating income for the same periods was $10 million and $31 million, respectively. Operating revenues related to the retail energy supply business for the six months ended June 30, 2010 and 2009 were $898 million and $1.17 billion, respectively, while operating income for the same periods was $31 million and $53 million, respectively. PHI anticipates that the decline in operating revenues and operating income will continue as the retail energy supply business winds down. In connection with the operation of the retail energy supply business, as of June 30, 2010, Pepco Energy Services provided letters of credit of $172 million and posted net cash collateral of $121 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 the collateral is expected to be fully released over time by June 1, 2014. The 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, PHI maintains a portfolio of cross-border energy sale-leaseback transactions with a book value at June 30, 2010 of approximately $1.4 billion. This activity constitutes a third operating segment, which is designated as “Other Non-Regulated,” for financial reporting purposes. For a discussion of PHI’s cross-border 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.

Organizational Review

With the ongoing wind down of the retail energy supply business of Pepco Energy Services and the recent approval by the Board of Directors of a plan for the disposition of Conectiv Energy, PHI has repositioned itself for the future primarily as a regulated transmission and distribution company. As a result of this repositioning, PHI commenced a comprehensive organizational review in the second quarter of 2010 to identify opportunities to streamline the organization and to achieve certain reductions in corporate overhead costs that were previously allocated to these non-regulated businesses. The organizational review is still underway and PHI is in the final stages of developing a detailed plan identifying headcount reductions and other

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cost reduction opportunities that will result in the elimination of at least $20 million in annual corporate overhead costs. PHI expects to begin implementation of the organizational and other related changes resulting from this review beginning in the third and fourth quarters of 2010, with full implementation expected by the end of 2010. PHI also expects to incur certain employee severance and other restructuring costs associated with the reduction of overhead costs, but estimates of such costs will not be available until a detailed plan has been finalized and approved.

Earnings Overview

Three Months Ended June 30, 2010 Compared to Three Months Ended June 30, 2009

PHI’s net income from continuing operations for the three months ended June 30, 2010 was $76 million, or $0.34 per share, compared to $39 million, or $0.18 per share, for the three months ended June 30, 2009.

PHI’s net loss from discontinued operations for the three months ended June 30, 2010 was $130 million, or $0.58 per share, compared to a loss of $14 million, or $0.07 per share, for the three months ended June 30, 2009.

PHI’s net (loss) income for the three months ended June 30, 2010 and 2009, by operating segment, is set forth in the table below (in millions of dollars):

	2010			2009			Change
Power Delivery	$	65		$	31		$	34
Pepco Energy Services		10			10			—
Other Non-Regulated		6			8			(2	)
Corporate and Other		(5	)		(10	)		5
Net Income from Continuing Operations		76			39			37
Discontinued Operations		(130	)		(14	)		(116	)
Total PHI Net (Loss) Income	$	(54	)	$	25		$	(79	)

Discussion of Operating Segment Net Income Variances:

Power Delivery’s $34 million increase in earnings is primarily due to the following:

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

• an $11 million increase due to higher distribution sales, primarily due to warmer weather and customer growth / rate mix; and

• a $5 million increase due to distribution rate increases (Pepco in the District of Columbia effective November 2009 and March 2010; DPL in Maryland effective December 2009; DPL in Delaware effective April 2010; and ACE in New Jersey effective June 2010).

• $8 million increase from higher transmission revenue primarily attributable to the accrual of true-ups to reflect costs incurred in the June 2009 through May 2010 service period that were included in the final determination of network service transmission rates effective June 1, 2010 through May 31, 2011, which include rate adjustments for such true-ups.

• $9 million increase associated with ACE Basic Generation Service primarily attributable to an increase in unbilled revenue (higher usage).

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Corporate and Other’s $5 million increase in earnings is primarily due to the favorable impact from deferred state tax benefits related to the April 1, 2010 corporate restructuring.

The $116 million increase in the net loss from discontinued operations for the three months ended June 30, 2010 as compared to June 30, 2009 was primarily due to the recognition of a write-down associated with the anticipated sale of the wholesale power generation business to Calpine Corporation and unrealized losses on derivative instruments no longer qualifying for cash flow hedge accounting, partially offset by gains on sales of load service supply contracts.

Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009

PHI’s net income from continuing operations for the six months ended June 30, 2010 was $104 million, or $0.47 per share, compared to $80 million, or $0.37 per share, for the six months ended June 30, 2009.

Net income from continuing operations for the six months ended June 30, 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 from continuing operations would have been $72 million, or $0.33 per share, for the six months ended June 30, 2009.

PHI’s net loss from discontinued operations for the six months ended June 30, 2010 was $122 million, or $0.55 per share, compared to a loss of $10 million, or $0.05 per share, for the six months ended June 30, 2009.

PHI’s net (loss) income for the six months ended June 30, 2010 and 2009, by operating segment, is set forth in the table below (in millions of dollars):

	2010			2009			Change
Power Delivery	$	85		$	73		$	12
Pepco Energy Services		23			18			5
Other Non-Regulated		10			14			(4	)
Corporate and Other		(14	)		(25	)		11
Net Income from Continuing Operations		104			80			24
Discontinued Operations		(122	)		(10	)		(112	)
Total PHI Net (Loss) Income	$	(18	)	$	70		$	(88	)

Discussion of Operating Segment Net Income Variances:

Power Delivery’s $12 million increase in earnings is primarily due to the following:

• $18 million increase from higher distribution revenue consisting of:

• a $9 million increase due to distribution rate increases (Pepco in the District of Columbia effective November 2009 and March 2010; DPL in Maryland effective December 2009; DPL in Delaware effective April 2010; and ACE in New Jersey effective June 2010); and

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• a $9 million increase due to higher distribution sales, primarily due to customer growth / rate mix and warmer weather.

• $9 million increase from higher transmission revenue primarily attributable to the accrual of true-ups to reflect costs incurred in the June 2009 through May 2010 service period that were included in the final determination of network service transmission rates effective June 1, 2010 through May 31, 2011, which include rate adjustments for such true-ups.

• $11 million increase associated with ACE Basic Generation Service primarily attributable to an increase in unbilled revenue (higher usage).

• $12 million decrease due to income tax adjustments for the six months ended June 30, 2010, primarily related to interest on uncertain and effectively settled tax positions.

• $8 million decrease due to higher earnings in 2009 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.

• $4 million decrease due to higher operating and maintenance costs primarily resulting from February 2010 storm restoration activity.

Pepco Energy Services’ $5 million increase in earnings is primarily due to higher generation output and lower Reliability Pricing Model charges associated with generating facilities; partially offset by lower retail electric commodity earnings due to lower electricity sales volumes due to the ongoing wind down of the retail electricity supply business.

Other Non-Regulated’s $4 million decrease in earnings is primarily due to the write-down of a financial investment.

Corporate and Other’s $11 million increase in earnings is primarily due to the favorable impact from deferred state tax benefits related to the April 1, 2010 corporate restructuring; partially offset by the write off of a deferred tax asset due to a change in law which eliminates the tax deductibility of Medicare Part D subsidized prescription drug costs after 2012.

The $112 million increase in the net loss from discontinued operations for the six months ended June 30, 2010 as compared to June 30, 2009 was primarily due to the recognition of a write-down associated with the anticipated sale of the wholesale power generation business to Calpine Corporation and unrealized losses on derivative instruments no longer qualifying for cash flow hedge accounting, partially offset by gains on sales of load service supply contracts.

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Consolidated Results of Operations

The following results of operations discussion is for the three months ended June 30, 2010, compared to the three months ended June 30, 2009. All amounts in the tables (except sales and customers) are in millions of dollars.

Continuing Operations

Operating Revenue

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

	2010			2009			Change
Power Delivery	$	1,149		$	1,095		$	54
Pepco Energy Services		476			560			(84	)
Other Non-Regulated		13			14			(1	)
Corporate and Other		(2	)		(3	)		1
Total Operating Revenue	$	1,636		$	1,666		$	(30	)

Power Delivery Business

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

	2010		2009		Change
Regulated T&D Electric Revenue	$	449	$	394	$	55
Default Electricity Supply Revenue		646		642		4
Other Electric Revenue		18		19		(1	)
Total Electric Operating Revenue		1,113		1,055		58
Regulated Gas Revenue		24		30		(6	)
Other Gas Revenue		12		10		2
Total Gas Operating Revenue		36		40		(4	)
Total Power Delivery Operating Revenue	$	1,149	$	1,095	$	54

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 the PJM Interconnection, LLC (PJM) at rates regulated by FERC.

Default Electricity Supply Revenue is the revenue received from the supply of electricity by PHI’s electric utility subsidiaries at regulated rates to retail customers who do not elect to purchase electricity from a competitive energy supplier. Depending on the jurisdiction, Default Electricity Supply is also known as Standard Offer Service or Basic Generation Service (BGS). The costs related to Default Electricity Supply are included in Fuel and Purchased Energy. Default Electricity Supply Revenue also includes revenue from Transition Bond Charges (revenue ACE receives, and pays to Atlantic City Electric Transition Funding LLC (ACE Funding), to fund the principal and interest payments on Transition Bonds issued by ACE Funding and related taxes, expenses and fees) and other ACE 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 includes the revenue DPL receives from on-system natural gas delivered sales and the transportation of natural gas for customers within its service territory at regulated rates.

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

Regulated T&D Electric

Regulated T&D Electric Revenue	2010		2009		Change
Residential	$	149	$	130	$	19
Commercial and industrial		224		202		22
Other		76		62		14
Total Regulated T&D Electric Revenue	$	449	$	394	$	55

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

Regulated T&D Electric Sales (Gigawatt hours (GWh))	2010	2009	Change
Residential	3,773	3,448	325
Commercial and industrial	8,227	7,819	408
Other	56	56	—
Total Regulated T&D Electric Sales	12,056	11,323	733

Regulated T&D Electric Customers (in thousands)	2010	2009	Change
Residential	1,628	1,614	14
Commercial and industrial	198	197	1
Other	2	2	—
Total Regulated T&D Electric Customers	1,828	1,813	15

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 $55 million primarily due to:

• An increase of $13 million in transmission revenue primarily attributable to (i) the accrual of true-ups to reflect costs incurred in the June 2009 through May 2010 service period that were included in the final determination of network service transmission rates effective June 1, 2010 through May 31, 2011, which include rate adjustments for such true-ups and (ii) other transmission rate increases.

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• An increase of $12 million due to distribution rate increases in several jurisdictions:

• $6 million, Pepco in the District of Columbia, effective November 2009 and March 2010

• $2 million, DPL in Maryland, effective December 2009

• $2 million, DPL in Delaware, placed into effect April 2010, subject to refund and pending final Delaware Public Service Commission approval

• $2 million, ACE in New Jersey, effective June 2010

• An increase of $12 million due to higher sales in the District of Columbia, Delaware and New Jersey service territories as a result of warmer weather during the 2010 spring months as compared to 2009. Distribution revenue in Maryland is decoupled from consumption in the second quarter of both 2009 and 2010 and, therefore, the period-to-period comparison is not affected by weather. Distribution revenue in the District of Columbia is not decoupled from consumption in the second quarter of 2009 and, therefore, the period-to-period comparison is affected by weather.

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

• An increase of $4 million due to the implementation of the EmPower Maryland (demand side management program for Pepco and DPL) surcharge rate in March 2010 (which is substantially offset by a corresponding increase in Depreciation and Amortization).

Default Electricity Supply

Default Electricity Supply Revenue	2010		2009		Change
Residential	$	418	$	383	$	35
Commercial and industrial		188		232		(44	)
Other		40		27		13
Total Default Electricity Supply Revenue	$	646	$	642	$	4

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	3,586	3,328	258
Commercial and industrial	1,749	2,148	(399	)
Other	23	21	2
Total Default Electricity Supply Sales	5,358	5,497	(139	)

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Default Electricity Supply Customers (in thousands)	2010	2009	Change
Residential	1,568	1,568	—
Commercial and industrial	155	163	(8	)
Other	1	2	(1	)
Total Default Electricity Supply Customers	1,724	1,733	(9	)

Default Electricity Supply Revenue increased by $4 million primarily due to:

• An increase of $57 million due to higher sales as a result of warmer weather during the 2010 spring months as compared to 2009.

• An increase of $11 million in wholesale energy and capacity revenues primarily due to higher market prices for the sale of electricity purchased from NUGs.

The aggregate amount of these increases was partially offset by:

• A decrease of $54 million due to lower sales, primarily as a result of commercial customer migration to competitive suppliers.

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

The increase in total Default Electricity Supply Revenue includes an increase of $15 million in unbilled revenue attributable to ACE’s BGS. Under the BGS terms approved by the New Jersey Board of Public Utilities (NJBPU), ACE is entitled to recover from its customers all of its costs of providing BGS. If the costs of providing BGS exceed the BGS revenue, then the excess costs are deferred in Deferred Electric Service Costs. ACE’s BGS unbilled revenue is not included in the deferral calculation, and therefore has an impact on the results of operations in the period during which it is accrued. While the change in the amount of unbilled revenue from year to year typically is not significant, for the three months ended June 30, 2010, BGS unbilled revenue increased by $15 million as compared to the three months ended June 30, 2009, which resulted in a $9 million increase in PHI’s net income. The increase was primarily due to warmer weather during the unbilled revenue period at the end of the three months ended June 30, 2010 as compared to the corresponding period in 2009.

Regulated Gas

Regulated Gas Revenue	2010		2009		Change
Residential	$	14	$	17	$	(3	)
Commercial and industrial		8		11		(3	)
Transportation and other		2		2		—
Total Regulated Gas Revenue	$	24	$	30	$	(6	)
Regulated Gas Sales (billion cubic feet)	2010		2009		Change
Residential		1		1		—
Commercial and industrial		1		—		1
Transportation and other		1		1		—
Total Regulated Gas Sales		3		2		1

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Regulated Gas Customers (in thousands)	2010	2009	Change
Residential	113	113	—
Commercial and industrial	9	9	—
Transportation and other	—	—	—
Total Regulated Gas Customers	122	122	—

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 $6 million primarily due to lower sales as a result of milder weather during the 2010 spring months as compared to 2009.

Other Gas Revenue

Other Gas Revenue increased by $2 million primarily due to higher revenue from off-system sales as a result of higher demand from electric generators and gas marketers.

Pepco Energy Services

Pepco Energy Services’ operating revenue decreased $84 million primarily due to:

• A decrease of $143 million due to lower volumes of retail electric load served as a result of the continuing expiration of existing retail contracts associated with the decision to wind down the retail energy supply business.

The decrease was partially offset by:

• An increase of $45 million due to higher electricity generation output that resulted from planned transmission construction projects and operations associated with warmer than normal weather, and lower Reliability Pricing Model charges associated with the generating facilities.

• An increase of $9 million due to higher retail gas supply 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.

• An increase of $5 million due to increased high voltage and energy services construction activities.

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Operating Expenses

Fuel and Purchased Energy and Other Services Cost of Sales

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

	2010			2009			Change
Power Delivery	$	688		$	700		$	(12	)
Pepco Energy Services		427			505			(78	)
Corporate and Other		(3	)		(1	)		(2	)
Total	$	1,112		$	1,204		$	(92	)

Power Delivery Business

Power Delivery’s Fuel and Purchased Energy consists of the cost of electricity and gas purchased by its utility subsidiaries to fulfill their respective Default Electricity Supply and Regulated Gas obligations and, as such, is recoverable from customers in accordance with the terms of public service commission orders. It also includes the cost of gas purchased for off-system sales. Fuel and Purchased Energy expense decreased by $12 million primarily due to:

• A decrease of $75 million primarily due to commercial customer migration to competitive suppliers.

• A decrease of $30 million in deferred electricity expense due to a lower rate of recovery from customers of electricity supply costs.

The aggregate amount of these decreases was partially offset by:

• An increase of $59 million due to higher electricity sales as a result of warmer weather during the 2010 spring months as compared to 2009.

• An increase of $37 million due to higher average electricity costs under Default Electricity Supply contracts.

Pepco Energy Services

Pepco Energy Services’ Fuel and Purchased Energy and Other Services Cost of Sales decreased $78 million primarily due to:

• A decrease of $117 million due to lower volumes of electricity purchased to serve decreased retail customer load as a result of the continuing expiration of existing retail contracts associated with the decision to wind down the retail energy supply business.

The decrease was partially offset by:

• An increase of $17 million due to higher fuel usage by the generating facilities.

• An increase of $16 million due to higher retail gas supply load from 2009 customer acquisitions prior to the commencement of the wind down of the retail energy supply business, partially offset by lower wholesale natural gas prices.

• An increase of $5 million due to increased high voltage and energy services construction activities.

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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	$	184		$	185		$	(1	)
Pepco Energy Services		21			21			—
Other Non-Regulated		1			2			(1	)
Corporate and Other		(10	)		(7	)		(3	)
Total	$	196		$	201		$	(5	)

Other Operation and Maintenance expense for Power Delivery decreased by $1 million; however, excluding an increase of $3 million primarily related to bad debt and administrative expenses that are deferred and recoverable in Default Electricity Supply Revenue, Other Operation and Maintenance expense decreased by $4 million. The $4 million decrease was primarily due to:

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

• A decrease of $3 million primarily due to lower emergency restoration costs, as further described below.

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 were originally estimated at March 31, 2010 at $37 million with $19 million charged to Other Operation and Maintenance expense for repair work and $18 million recorded as capital expenditures. A portion of the costs of the restoration work relates to services provided by outside contractors and other utilities, and since billings for such services in certain instances had not been received at March 31, 2010, the costs were estimated at that date. The actual billings received during the second quarter of 2010 resulted in final costs of $32 million, with $15 million charged to Other Operation and Maintenance expense and $17 million recorded as capital expenditures, which reflects a reduction in Other Operation and Maintenance expense of $4 million in the second quarter of 2010 and a reduction of $1 million originally recorded as capital expenditures.

The aggregate amount of these decreases was partially offset by:

• An increase of $4 million in environmental remediation costs related to a 1999 oil release at the Indian River generating facility then owned by DPL, as further discussed under “Indian River Oil Release” in Note (14), “Commitments and Contingencies” to the consolidated financial statements of PHI.

In July 2010, the service territories of each of Pepco, DPL and ACE experienced severe thunderstorms. These storms caused significant damage to their respective electric transmission and distribution systems, with the vast majority of the damage occurring in the Pepco service territory. The cost of system restoration is currently expected to range from $10 million to $13 million. A portion of the restoration cost will be expensed with the balance being charged to capital. The actual cost of system restoration could vary significantly from these estimates, because a large portion of the cost relates to services provided by outside contractors and other utilities for which the companies have not yet been billed.

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Depreciation and Amortization

Depreciation and Amortization expenses increased by $8 million to $93 million in 2010 from $85 million in 2009 primarily due to:

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

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

Other Taxes

Other Taxes increased by $16 million to $105 million in 2010 from $89 million in 2009. The increase was primarily due to increased pass-throughs experienced by Power Delivery (which are substantially offset by a corresponding increase in Regulated T&D Electric Revenue) resulting from rate increases in utility taxes imposed by the taxing jurisdictions.

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 decreased by $6 million, to an expense reduction of $63 million in 2010 as compared to an expense reduction of $57 million in 2009, primarily due to a decrease in deferred electricity expense due to a lower rate of recovery from customers of electricity supply costs.

Income Tax Expense

PHI’s effective tax rates for the three months ended June 30, 2010 and 2009 were 30.3% and 38.1%, respectively. The reduction in the rate is primarily due to an $8 million state tax benefit from a change in state tax apportionment factors arising from a 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 from corporations to single member limited liability companies. In addition to increased organization flexibility and reduced administrative costs, a consequence of converting these entities was to allow PHI to include income or losses in the former corporations in a single state income tax return, thus increasing the utilization of state income tax attributes.

During the second quarter of 2009, as a result of filing amended state returns, PHI’s uncertain tax benefits related to prior year tax positions increased by $18 million.

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Discontinued Operations

For the three months ended June 30, 2010, the loss from discontinued operations, net of income taxes, of $130 million includes income from operations of $2 million for Conectiv Energy, which includes the after-tax effects of employee severance and retention benefits of $9 million and after-tax accruals of certain obligations associated with the anticipated sale of the wholesale power generation business to Calpine of $13 million, each recorded in the second quarter of 2010. Most of the $130 million after-tax loss from discontinued operations was associated with the $132 million of net losses from disposition of assets and businesses of discontinued operations, net of income taxes, and includes (i) the $67 million write-down related to the wholesale power generation business being sold to Calpine, (ii) certain additional income tax charges of $14 million associated with the sale of the wholesale power generation business, and (iii) $51 million of net losses from the disposition of other assets and businesses of Conectiv Energy. The $51 million of net losses from the disposition of other assets and businesses of Conectiv Energy primarily reflects $50 million of after-tax unrealized losses on derivative instruments associated with Conectiv Energy’s load service business that were required to be recorded in earnings as a result of the intention to liquidate certain load service supply contracts included in this business. These unrealized losses are expected to be reduced over the remainder of the year by gains from the liquidation of these load service supply contracts and other remaining assets.

The following results of operations discussion is for the six months ended June 30, 2010, compared to the six months ended June 30, 2009. All amounts in the tables (except sales and customers) are in millions of dollars.

Continuing Operations

Operating Revenue

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

	2010			2009			Change
Power Delivery	$	2,411		$	2,467		$	(56	)
Pepco Energy Services		1,023			1,217			(194	)
Other Non-Regulated		26			27			(1	)
Corporate and Other		(5	)		(8	)		3
Total Operating Revenue	$	3,455		$	3,703		$	(248	)

Power Delivery Business

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

	2010		2009		Change
Regulated T&D Electric Revenue	$	846	$	781	$	65
Default Electricity Supply Revenue		1,401		1,478		(77	)
Other Electric Revenue		33		37		(4	)
Total Electric Operating Revenue		2,280		2,296		(16	)
Regulated Gas Revenue		111		149		(38	)
Other Gas Revenue		20		22		(2	)
Total Gas Operating Revenue		131		171		(40	)
Total Power Delivery Operating Revenue	$	2,411	$	2,467	$	(56	)

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Regulated T&D Electric

Regulated T&D Electric Revenue	2010		2009		Change
Residential	$	298	$	274	$	24
Commercial and industrial		407		382		25
Other		141		125		16
Total Regulated T&D Electric Revenue	$	846	$	781	$	65

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

Regulated T&D Electric Sales (GWh)	2010	2009	Change
Residential	8,650	8,222	428
Commercial and industrial	15,428	15,312	116
Other	124	126	(2	)
Total Regulated T&D Electric Sales	24,202	23,660	542
Regulated T&D Electric Customers (in thousands)	2010	2009	Change
Residential	1,628	1,614	14
Commercial and industrial	198	197	1
Other	2	2	—
Total Regulated T&D Electric Customers	1,828	1,813	15

Regulated T&D Electric Revenue increased by $65 million primarily due to:

• An increase of $15 million in transmission revenue primarily attributable to (i) the accrual of true-ups to reflect costs incurred in the June 2009 through May 2010 service period that were included in the final determination of network service transmission rates effective June 1, 2010 through May 31, 2011, which include rate adjustments for such true-ups and (ii) other transmission rate increases.

• An increase of $14 million due to distribution rate increases in several jurisdictions:

• $5 million, DPL in Maryland, effective December 2009

• $5 million, Pepco in District of Columbia, effective November 2009 and March 2010

• $2 million, DPL in Delaware, placed into effect April 2010, subject to refund and pending final Delaware Public Service Commission approval

• $2 million, ACE in New Jersey, effective June 2010

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• An increase of $13 million due to higher pass-through revenue (which is substantially offset by a corresponding increase in Other Taxes) primarily the result of rate increases in utility taxes that are collected on behalf of taxing jurisdictions.

• An increase of $9 million due to higher sales in the District of Columbia, Delaware and New Jersey service territories as a result of warmer weather during the 2010 spring months as compared to 2009. Distribution revenue in Maryland is decoupled from consumption in the first six months of both 2009 and 2010 and, therefore, the period-to-period comparison is not affected by weather. Distribution revenue in the District of Columbia is not decoupled from consumption in the first six months of 2009 and, therefore, the period-to-period comparison is affected by weather.

• An increase of $6 million due to the implementation of the EmPower Maryland (demand side management program at Pepco and DPL) surcharge rate in March 2010 (which is substantially offset by a corresponding increase in Depreciation and Amortization).

• An increase of $4 million due to customer growth of 1% primarily in the residential class in 2010.

Default Electricity Supply

Default Electricity Supply Revenue	2010		2009		Change
Residential	$	939	$	900	$	39
Commercial and industrial		367		492		(125	)
Other		95		86		9
Total Default Electricity Supply Revenue	$	1,401	$	1,478	$	(77	)

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 NUGs.

Default Electricity Supply Sales (GWh)	2010	2009	Change
Residential	8,266	7,966	300
Commercial and industrial	3,504	4,620	(1,116	)
Other	48	48	—
Total Default Electricity Supply Sales	11,818	12,634	(816	)
Default Electricity Supply Customers (in thousands)	2010	2009	Change
Residential	1,568	1,568	—
Commercial and industrial	155	163	(8	)
Other	1	2	(1	)
Total Default Electricity Supply Customers	1,724	1,733	(9	)

Default Electricity Supply Revenue decreased by $77 million primarily due to:

• A decrease of $125 million due to lower sales, primarily as a result of commercial customer migration to competitive suppliers.

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The decrease was partially offset by:

• An increase of $42 million due to higher sales as a result of warmer weather during the 2010 spring months as compared to 2009.

The decrease in total Default Electricity Supply Revenue includes an increase of $16 million in unbilled revenue attributable to ACE’s BGS. Under the BGS terms approved by the NJBPU, ACE is entitled to recover from its customers all of its costs of providing BGS. If the costs of providing BGS exceed the BGS revenue, then the excess costs are deferred in Deferred Electric Service Costs. ACE’s BGS unbilled revenue is not included in the deferral calculation, and therefore has an impact on the results of operations in the period during which it is accrued. While the change in the amount of unbilled revenue from year to year typically is not significant, for the six months ended June 30, 2010, BGS unbilled revenue increased by $16 million as compared to the six months ended June 30, 2009, which resulted in a $10 million increase in PHI’s net income. The increase was primarily due to warmer weather during the unbilled revenue period at the end of the six months ended June 30, 2010 as compared to the corresponding period in 2009.

Regulated Gas

Regulated Gas Revenue	2010		2009		Change
Residential	$	69	$	92	$	(23	)
Commercial and industrial		38		53		(15	)
Transportation and other		4		4		—
Total Regulated Gas Revenue	$	111	$	149	$	(38	)
Regulated Gas Sales (billion cubic feet)	2010		2009		Change
Residential		5		5		—
Commercial and industrial		3		3		—
Transportation and other		3		3		—
Total Regulated Gas Sales		11		11		—
Regulated Gas Customers (in thousands)	2010		2009		Change
Residential		113		113		—
Commercial and industrial		9		9		—
Transportation and other		—		—		—
Total Regulated Gas Customers		122		122		—

Regulated Gas Revenue decreased by $38 million primarily due to:

• A decrease of $31 million due to lower sales as a result of milder weather during the 2010 winter months as compared to 2009.

• A decrease of $21 million due to Gas Cost Rate decreases effective March 2009 and November 2009.

The aggregate amount of these decreases was partially offset by:

• An increase of $14 million due to higher non-weather related average customer usage.

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Other Gas Revenue

Other Gas Revenue decreased by $2 million primarily due to lower revenue from capacity release sales which represent the short-term release of interstate pipeline transportation and storage capacity not needed to serve customers.

Pepco Energy Services

Pepco Energy Services’ operating revenue decreased $194 million primarily due to:

• A decrease of $294 million due to lower volumes of retail electric load served as a result of the continuing expiration of existing retail contracts associated with the decision to wind down the retail energy supply business.

The decrease was partially offset by:

• An increase of $61 million due to higher electricity generation output that resulted from planned transmission construction projects and operations associated with warmer than normal weather, and lower Reliability Pricing Model charges associated with the generating facilities.

• An increase of $28 million due to higher retail gas supply 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.

• And increase of $12 million due to increased high voltage and energy services construction activities.

Operating Expenses

Fuel and Purchased Energy and Other Services Cost of Sales

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

	2010			2009			Change
Power Delivery	$	1,505		$	1,646		$	(141	)
Pepco Energy Services		923			1,119			(196	)
Corporate and Other		(4	)		(5	)		1
Total	$	2,424		$	2,760		$	(336	)

Power Delivery Business

Power Delivery’s Fuel and Purchased Energy consists of the cost of electricity and gas purchased by its utility subsidiaries to fulfill their respective Default Electricity Supply and Regulated Gas obligations and, as such, is recoverable from customers in accordance with the terms of public service commission orders. It also includes the cost of gas purchased for off-system sales. Fuel and Purchased Energy expense decreased by $141 million primarily due to:

• A decrease of $141 million primarily due to commercial customer migration to competitive suppliers.

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• A decrease of $52 million in deferred electricity expense due to a lower rate of recovery from customers of electricity supply costs.

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

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

• 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 $51 million due to higher average electricity costs under Default Electricity Supply contracts.

• An increase of $41 million due to higher electricity sales as a result of warmer weather during the 2010 spring months as compared to 2009.

Pepco Energy Services

Pepco Energy Services’ Fuel and Purchased Energy and Other Services Cost of Sales decreased $196 million primarily due to:

• A decrease of $247 million due to lower volumes of electricity purchased to serve decreased retail customer load as a result of the continuing expiration of existing retail contracts associated with the decision to wind down the retail energy supply business.

The decrease was partially offset by:

• An increase of $26 million due to higher retail gas supply load from 2009 customer acquisitions prior to the commencement of the wind down of the retail energy supply business, partially offset by lower wholesale natural gas prices.

• An increase of $14 million due to higher fuel usage by the generating facilities.

• An increase of $11 million due to increased high voltage and energy services construction activities.

Other Operation and Maintenance

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

	2010			2009			Change
Power Delivery	$	382		$	371		$	11
Pepco Energy Services		42			44			(2	)
Other Non-Regulated		2			2			—
Corporate and Other		(16	)		(12	)		(4	)
Total	$	410		$	405		$	5

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Other Operation and Maintenance expense for Power Delivery increased by $11 million; however, excluding an increase of $3 million primarily related to administrative and bad debt expenses that are deferred and recoverable in Default Electricity Supply Revenue, Other Operation and Maintenance expense increased by $8 million. The $8 million increase was primarily due to:

• An increase of $18 million in emergency restoration costs largely due to the February 2010 severe winter storms.

• An increase of $4 million in environmental remediation costs related to a 1999 oil release at the Indian River generating facility then owned by DPL, as further discussed under “Indian River Oil Release” in Note (14), “Commitments and Contingencies” to the consolidated financial statements of PHI.

The aggregate amount of these increases was partially offset by:

• A decrease of $10 million in employee-related costs, primarily due to lower pension and other postretirement benefit expenses.

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

• A decrease of $2 million primarily due to lower tree trimming and preventative maintenance costs.

In July 2010, the service territories of each of Pepco, DPL and ACE experienced severe thunderstorms. These storms caused significant damage to their respective electric transmission and distribution systems, with the vast majority of the damage occurring in the Pepco service territory. The cost of system restoration is currently expected to range from $10 million to $13 million. A portion of the restoration cost will be expensed with the balance being charged to capital. The actual cost of system restoration could vary significantly from these estimates, because a large portion of the cost relates to services provided by outside contractors and other utilities for which the companies have not yet been billed.

Depreciation and Amortization

Depreciation and Amortization expenses increased by $10 million to $182 million in 2010 from $172 million in 2009 primarily due to:

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

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

Other Taxes

Other Taxes increased by $18 million to $197 million in 2010 from $179 million in 2009. The increase was primarily due to increased pass-throughs experienced by Power Delivery (which are substantially offset by a corresponding increase in Regulated T&D Electric Revenue) resulting from rate increases in utility taxes imposed by the taxing jurisdictions.

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Deferred Electric Service Costs

Deferred Electric Service Costs, which relate only to ACE, 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 $2 million, to an expense reduction of $82 million in 2010 as compared to an expense reduction of $84 million in 2009, primarily due to an increase in deferred electricity expense due to a higher rate of recovery from customers 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 six months ended June 30, 2010 and 2009 were 35.8% and 36.5%, respectively. The decrease in the rate resulted primarily from approximately $8 million of state apportionment factor benefits recognized in the second quarter of 2010, and the release of $8 million of valuation allowances on deferred tax assets related to state net operating losses recognized in the first quarter of 2010, both of which related to the April 1, 2010 restructuring. This was partially offset by 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 for the six months ended June 30, 2010 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. Under this legislation, 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 legislation, the costs incurred for those prescription drugs were tax deductible. The legislation includes a provision, effective beginning in 2013, which eliminates the tax deductibility of the prescription drug costs. As a result, in the first quarter of 2010, PHI wrote off $5 million of deferred tax assets. Of this amount, $3 million was established as a regulatory asset, which PHI anticipates will be recoverable from its utility customers in the future. This change increased PHI’s 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.

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 Part 1, Item 1 of this Form 10-Q, for additional discussion.

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During the second quarter of 2009, as a result of filing amended state returns, PHI’s uncertain tax benefits related to prior year tax positions increased by $18 million. These uncertain tax benefits were subsequently realized in the third quarter of 2009.

Discontinued Operations

For the six months ended June 30, 2010, the net loss from discontinued operations, net of income taxes, of $122 million includes income from operations of $8 million for Conectiv Energy, which includes the after-tax effects of employee severance and retention benefits of $9 million and after-tax accruals of certain obligations associated with the anticipated sale of the wholesale power generation business to Calpine of $13 million, each recorded in the second quarter of 2010. Most of the $122 million after-tax loss from discontinued operations was associated with the $130 million of net losses from dispositions of assets and businesses of discontinued operations, net of income taxes, and includes (i) the $67 million write-down related to the wholesale power generation business being sold to Calpine, (ii) certain additional income tax charges of $14 million associated with the sale of the wholesale power generation business, and (iii) and $49 million of net losses from the disposition of other assets and businesses of Conectiv Energy. The $49 million of net losses from the disposition of other assets and businesses of Conectiv Energy primarily reflects $50 million of after-tax unrealized losses on derivative instruments associated with Conectiv Energy’s load service business that were required to be recorded in earnings as a result of the intention to liquidate certain load service supply contracts included in this business. These unrealized losses are expected to be reduced over the remainder of the year by gains from the liquidation of these load service supply contracts and other remaining assets.

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 June 30, 2010, Pepco Holdings’ current assets on a consolidated basis totaled $1.9 billion and its current liabilities totaled $3.4 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 $1.1 billion decrease in working capital from December 31, 2009 to June 30, 2010 was due primarily to the reclassification of $944 million of its senior notes to current liabilities pursuant to the Debt Tender Offers discussed below. In July 2010, PHI concluded the repurchases of these notes using proceeds received from the sale of Conectiv Energy’s wholesale power generation business to Calpine.

At June 30, 2010, Pepco Holdings’ cash and current cash equivalents totaled $52 million, of which $18 million is reflected on the Balance Sheet in Conectiv Energy assets held for sale, $3 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 $9 million. At December 31, 2009, Pepco Holdings’ cash and current cash equivalents totaled $46 million, of which $2 million is reflected on the Balance Sheet in Conectiv Energy assets held for sale, and its current restricted cash equivalents totaled $11 million.

PHI expects the working capital deficit (after giving effect to the repurchase of the $944 million of senior notes in July 2010 using a portion of the proceeds of the sale of the Conectiv Energy wholesale power generation business) will be funded during 2010 through cash flow from operations. Additional working capital will be provided by reduced collateral requirements of the Pepco Energy Services business and the disposition of the Conectiv Energy business.

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

	As of June 30, 2010 (millions of dollars)
Type	PHI Parent		Pepco		DPL		ACE		ACE Funding		Pepco Energy Services		PHI Consolidated
Variable Rate Demand Bonds	$	—	$	—	$	105	$	23	$	—	$	18	$	146
Bridge Loan Facility		450		—		—		—		—		—		450
Commercial Paper		222		—		—		170		—		—		392
Total Short-Term Debt	$	672	$	—	$	105	$	193	$	—	$	18	$	988
Current Maturities of Long-Term Debt and Project Funding	$	944	$	—	$	66	$	1	$	35	$	5	$	1,051
	As of December 31, 2009 (millions of dollars)
Type	PHI Parent		Pepco		DPL		ACE		ACE Funding		Pepco Energy Services		PHI Consolidated
Variable Rate Demand Bonds	$	—	$	—	$	105	$	23	$	—	$	18	$	146
Commercial Paper		324		—		—		60		—		—		384
Total Short-Term Debt	$	324	$	—	$	105	$	83	$	—	$	18	$	530
Current Maturities of Long-Term Debt and Project Funding	$	450	$	16	$	31	$	1	$	34	$	4	$	536

Financing Activity During the Three Months Ended June 30, 2010

In April 2010, ACE Funding made principal payments of $5.6 million on Series 2002-1 Bonds, Class A-2, and $2.2 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. 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

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proceeds of the loan 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, which 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:

• $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.

As the owner of these bonds, DPL received the proceeds from the redemption of the bonds, which it used for general corporate purposes.

In May 2010, PHI paid at maturity $200 million in aggregate principal amount of its 4.00% Notes due May 15, 2010. In June 2010, PHI paid at maturity $250 million in aggregate principal amount of its Floating Rate Notes due June 1, 2010. Both payments were funded with loans under the $450 million bridge loan discussed below under Credit Facilities.

On June 1, 2010, ACE replaced the letters of credit associated with (i) $18.2 million of The Pollution Control Financing Authority of Salem County Pollution Control Revenue Refunding Bonds, 1997 Series A (Atlantic City Electric Company Project) due April 15, 2014 (the 1997 Series A Bonds) and (ii) $4.4 million of The Pollution Control Financing Authority of Salem County Pollution Control Revenue Refunding Bonds, 1997 Series B (Atlantic City Electric Company Project) due July 15, 2017 (the 1997 Series B Bonds), both of which expired on June 23, 2010, with new irrevocable direct pay letters of credit. The new letters of credit supporting the 1997 Series A Bonds and the 1997 Series B Bonds expire on April 15, 2014 and June 1, 2013, respectively.

Financing Activity Subsequent to June 30, 2010

On July 1, 2010, DPL repurchased $31 million of tax-exempt bonds pursuant to a put provision of the bonds. DPL intends to remarket these bonds in the second half of 2010.

Debt Tender Offers

On July 2, 2010, PHI purchased, pursuant to a cash tender offer, $640.1 million in principal amount of its 6.45% senior notes due 2012 (6.45% Notes) for an aggregate purchase price of $713 million, plus accrued and unpaid interest. The tender offer for the 6.45% Notes also constituted a solicitation of the consent of the holders of the 6.45% Notes to an amendment of the terms of the 6.45% Notes to reduce the notice period for the redemption from not less than 30 days and not more than 60 days to three business days. This amendment, which required the consent of the holders of a majority of the outstanding 6.45% Notes, was approved upon the repurchase of the 6.45% Notes pursuant to the tender offer. On July 2, 2010, PHI

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terminated the tender offer and issued a notice of redemption for the balance of the 6.45% Notes. On July 8, 2010, PHI redeemed the remaining $109.9 million of outstanding 6.45% Notes at an aggregate redemption price of $122 million, plus accrued and unpaid interest.

On July 20, 2010, PHI purchased pursuant to a cash tender offer (i) $128.9 million of its 6.125% senior notes due 2017 (6.125% Notes), at an aggregate purchase price of $145 million, plus accrued and unpaid interest, and (ii) $65.1 million of 7.45% senior notes due 2032 (7.45% Notes), at an aggregate purchase price of $78 million, plus accrued and unpaid interest.

The repurchases of the 6.45% Notes, 6.125% Notes and the 7.45% Notes were funded using the proceeds realized by PHI from the sale of Conectiv Energy’s wholesale power generation business to Calpine.

As a result of the aforementioned repurchases of debt, an after-tax loss on extinguishment of debt of $70 million will be recorded in the third quarter of 2010.

In June 2002, PHI entered into several treasury rate lock transactions to hedge changes in interest rates related to the anticipated issuance in August 2002 of several series of senior notes, including the 6.45% Notes and the 7.45% Notes. Upon issuance of the fixed rate debt, the rate locks were terminated at a loss that has been deferred in Accumulated Other Comprehensive Loss and is being recognized in income over the life of the debt issued as interest payments are made. In connection with the repurchases of the 6.45% Notes and the 7.45% Notes, PHI expects to accelerate the recognition of $9 million of these after-tax losses by reclassifying these losses from Accumulated Other Comprehensive Loss to income in the third quarter of 2010.

Credit Facilities

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

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

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

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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.

PHI also has a $400 million unsecured credit facility with a syndicate of nine lenders, which has a termination date of 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. 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.

In addition, PHI has a $50 million bilateral credit agreement with The Bank of Nova Scotia in effect though October 2010, which only can be used for the purpose of obtaining letters of credit. As of June 30, 2010, $25 million in letters of credit were outstanding under the agreement.

Under the terms of each of these facilities, the sale of the Conectiv Energy wholesale power generation business required the consent of the lenders. In each case, the sale was approved without any requirement that the terms of the facility be modified by reason of the sale.

On April 20, 2010, PHI entered into a $450 million unsecured bridge loan facility with Morgan Stanley Bank, N.A. and Credit Suisse AG (the Bridge Loan Facility). PHI used the proceeds of the loans drawn under the facility 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. On July 1, 2010, PHI repaid all amounts outstanding under this facility with the proceeds from the sale of the Conectiv Energy wholesale power generation business to Calpine, thereby terminating the facility.

Cash and Credit Facilities Available as of June 30, 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		193		188		5
Commercial Paper outstanding		392		222		170
Remaining Credit Facilities Available		1,365		915		450
Cash Invested in Money Market Funds (b)		3		3		—
Total Cash and Credit Facilities Available	$	1,368	$	918	$	450

(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 $34 million, which includes the $3 million invested in money market funds and $31 million held in cash and uncollected funds.

At June 30, 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 $1.4 billion, of which $450 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.

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Collateral Requirements

At June 30, 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 Pepco Energy Services and Conectiv Energy totaled $918 million and $820 million, respectively.

Collateral Requirements of Pepco Energy Services

In conducting its retail energy supply business, Pepco Energy Services, during periods of declining energy prices, has been exposed to the asymmetrical risk of having to post collateral under its wholesale purchase contracts without receiving a corresponding amount of collateral from its retail customers. To partially address these asymmetrical collateral obligations, Pepco Energy Services, in the first quarter of 2009, entered into a credit intermediation arrangement with Morgan Stanley Capital Group, Inc. (MSCG). Under this arrangement, MSCG, in consideration for the payment to MSCG of certain fees, (i) 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 June 30, 2010, approximately 7% 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 June 30, 2010 and 2009, approximately $3 million and $7 million, respectively, of the fees have been amortized and reflected in interest expense. For the six months ended June 30, 2010 and 2009, approximately $5 million and $8 million, respectively, of the fees have been amortized and reflected in interest expense.

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

Depending on the contract terms, the collateral required to be posted by Pepco Energy Services can be of varying forms, including cash and letters of credit. As of June 30, 2010, Pepco Energy Services had posted net cash collateral of $121 million and letters of credit of $172 million.

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

Remaining Collateral Requirements of Conectiv Energy

Depending on the contract terms, the collateral required to be posted by Conectiv Energy is of varying forms, including cash and letters of credit. As of June 30, 2010, Conectiv Energy had posted net cash collateral of $195 million and letters of credit of $12 million. After giving effect to the sale of the wholesale power generation business, effective July 1, 2010, the net cash collateral posted by Conectiv Energy was reduced to cash of $184 million and letters of credit of $8 million.

At December 31, 2009, Conectiv Energy had posted net cash collateral of $240 million and letters of credit of $22 million.

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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.

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.

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 currently projects there will be no minimum funding requirement under the Pension Protection Act guidelines in 2010, PHI intends to make discretionary tax-deductible contributions in 2010 in the aggregate amount of approximately $100 million to bring its plan assets to at least the funding target level for 2010 under the Pension Protection Act. As of June 30, 2010, no 2010 contributions had been made. Subsequent to June 30, 2010, PHI Service Company contributed $35 million to the PHI Retirement Plan on each of July 1, 2010 and August 2, 2010.

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 $114 million. This includes one time charges of $6 million related to sale of the Conectiv Energy wholesale power generation business. The utility subsidiaries are responsible for substantially all of the total PHI net periodic pension and other postretirement benefit costs. Historically, on an annual basis, 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.

Cash Flow Activity

PHI’s cash flows for the six months ended June 30, 2010 and 2009 are summarized below:

	Cash (Use) Source
	2010			2009			Change
	(millions of dollars)
Operating Activities	$	499		$	7		$	492
Investing Activities		(473	)		(382	)		(91	)
Financing Activities		(36	)		111			(147	)
Net (decrease) increase in cash and cash equivalents	$	(10	)	$	(264	)	$	254

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Operating Activities

Cash flows from operating activities during the six months ended June 30, 2010 and 2009 are summarized below:

	Cash (Use) Source
	2010		2009			Change
	(millions of dollars)
Net Income from continuing operations	$	104	$	80		$	24
Non-cash adjustments to net income		149		128			21
Pension contributions		—		(220	)		220
Changes in cash collateral related to derivative activities		4		(30	)		34
Changes in other assets and liabilities		102		40			62
Changes in Conectiv Energy net assets held for sale		140		9			131
Net cash from operating activities	$	499	$	7		$	492

Net cash from operating activities was $492 million higher for the six months ended June 30, 2010, compared to the same period in 2009. In addition to the increase in net income from continuing operations, portions of the increase are attributable to a 2010 decrease in pension plan contributions compared to 2009 and a decrease in collateral requirements as a result of the credit intermediation arrangement entered into by Pepco Energy Services in 2009. Changes in Conectiv Energy net assets held for sale represent the fluctuations in Conectiv Energy assets and liabilities which have been included in discontinued operations. The change in Conectiv Energy net assets held for sale is impacted by a decrease in collateral requirements between 2009 and 2010 as a result of derivative instruments being liquidated as further described in Note (15), “Discontinued Operations.”

Investing Activities

Cash flows from investing activities during the six months ended June 30, 2010 and 2009 are summarized below:

	Cash (Use) Source
	2010			2009			Change
	(millions of dollars)
Investment in property, plant and equipment	$	(364	)	$	(297	)	$	(67	)
Changes in restricted cash equivalents		3			1			2
Net other investing activities		(1	)		5			(6	)
Change in assets held for sale		(111	)		(91	)		(20	)
Net cash used by investing activities	$	(473	)	$	(382	)	$	(91	)

Net cash used by investing activities increased $91 million for the six months ended June 30, 2010 compared to the same period in 2009. The increase was due primarily to a $64 million increase in Power Delivery capital expenditures.

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Financing Activities

Cash flows from financing activities during the six months ended June 30, 2010 and 2009 are summarized below:

	Cash (Use) Source
	2010			2009			Change
	(millions of dollars)
Dividends paid on common stock	$	(120	)	$	(119	)	$	(1	)
Common stock issued for the Dividend Reinvestment Plan		15			15			—
Issuance of common stock		10			11			(1	)
Issuances of long-term debt		102			110			(8	)
Reacquisition of long-term debt		(482	)		(67	)		(415	)
Issuances of short-term debt, net		458			175			283
Net other financing activities		(25	)		(15	)		(10	)
Change in assets held for sale		6			1			5
Net cash (used by) from financing activities	$	(36	)	$	111		$	(147	)

Net cash related to financing activities decreased $147 million for the six months ended June 30, 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 six months ended June 30, 2010 and for the six months ended June 30, 2009 are summarized in the charts below:

	2010		2009
Issuances	(millions of dollars)
Pepco
6.2% Tax-exempt bonds due 2022 (a)	$	—	$	110
DPL
5.4% Tax-exempt bonds due 2031		78		—
ACE
4.875% Tax-exempt bonds due 2029 (b)		23		—
Pepco Energy Services		1		—
Total issuances of long-term debt	$	102	$	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		16		15
		16		15
PHI
4.00% Notes due to May 15, 2010		200		—
Floating Rate Notes due June 1, 2010		250		—
		450		—
Pepco Energy Services		—		2
Total reacquisition of long-term debt	$	482	$	67

(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 increased during the six months ended June 30, 2010 as compared to the same period in 2009, primarily due to borrowings under the Bridge Loan Facility entered into in April 2010, the proceeds of which were used to redeem (i) $200 million of 4.00% Notes due May 15, 2010 and (ii) $250 million of Floating Rate Notes due June 1, 2010.

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 six months ended June 30, 2010 totaled $364 million, of which $136 million was incurred by Pepco, $133 million was incurred by DPL and $76 million was incurred by ACE. The remainder was incurred primarily by the PHI Service Company. The Power Delivery expenditures were primarily related to capital costs associated with new customer services, distribution reliability, and transmission.

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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. 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 July 22, 2010, Pepco Holdings’ Board of Directors declared a dividend on common stock of 27 cents per share payable September 30, 2010, to shareholders of record on September 10, 2010. PHI had approximately $1,130 million and $1,268 million of retained earnings free of restrictions at June 30, 2010 and December 31, 2009, respectively.

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 both the Conectiv Energy and Pepco Energy Services segments) with respect to energy commodity contracts for the six months ended June 30, 2010. The balances in the table are pre-tax and the derivative assets and liabilities reflect netting by counterparty before the impact of collateral.

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	Energy Commodity Activities  (a)
	(millions of dollars)
Total Fair Value of Energy Contract Net Liabilities at December 31, 2009	$	(328	)
Current period unrealized gains		—
Effective portion of changes in fair value – recorded in Accumulated Other Comprehensive Loss		(76	)
Cash flow hedge ineffectiveness – recorded in income		(2	)
Recognition of realized gains (losses) on settlement of contracts		85
Derivative activity associated with Conectiv Energy		9
Total Fair Value of Energy Contract Net Liabilities at June 30, 2010	$	(312	)
	Total
Detail of Fair Value of Energy Contract Net Liabilities at June 30, 2010 (see above)
Derivative assets (current assets)	$	12
Derivative assets (non-current assets)		10
Derivative assets held for sale		42
Total Fair Value of Energy Contract Assets		64
Derivative liabilities (current liabilities)		(155	)
Derivative liabilities (non-current liabilities)		(29	)
Derivative liabilities held for sale		(192	)
Total Fair Value of Energy Contract Liabilities		(376	)
Total Fair Value of Energy Contract Net Liabilities	$	(312	)

(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 $312 million net liability on energy contracts at June 30, 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 six months of 2010, which resulted in unrealized losses on the energy contracts of the Competitive Energy business. Competitive Energy recorded unrealized losses of $76 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 June 30, 2010 and are subject to change as a result of changes in these factors:

	Fair Value of Contracts at June 30, 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	$	(76	)	$	(27	)	$	(18	)	$	(4	)	$	(125	)
Prices provided by other external sources (b)		(80	)		(44	)		(80	)		(6	)		(210	)
Modeled (c)		8			4			4			7			23
Total	$	(148	)	$	(67	)	$	(94	)	$	(3	)	$	(312	)

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 (consisting of both the Conectiv Energy and Pepco Energy Services segments) 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 June 30, 2010, a downgrade in the unsecured debt credit ratings of PHI and each of its rated subsidiaries to below “investment grade” would increase the collateral obligation of PHI and its subsidiaries by up to $457 million, $118 million of which is related to discontinued operations, and $193 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 $146 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 June 30, 2010, Pepco Holdings’ subsidiaries engaged in Competitive Energy activities and Default Electricity Supply activities provided net cash collateral in the amount of $316 million in connection with these activities.

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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.

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 transmission and distribution facilities, and the recovery of purchased power expenses;

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

• Weather conditions;

• Population growth rates and demographic patterns;

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

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

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• 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 PHI’s business and profitability;

• Pace of entry into new markets;

• Volatility in customer demand for electricity and natural gas;

• 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

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

General Overview

Pepco is engaged in the transmission and distribution of electricity in the District of Columbia and major portions of Montgomery County and Prince George’s County in suburban Maryland. Pepco also provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its service territories who do not elect to purchase electricity from a competitive 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 June 30, 2010, approximately 57% of delivered electricity sales were to Maryland customers and approximately 43% were to the District of Columbia customers.

Effective June 2007, the Maryland Public Service Commission 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 (i) a positive adjustment equal to the amount by which revenue from Maryland and District of Columbia retail distribution sales falls short of the revenue that Pepco is entitled to earn based on the approved distribution charge per customer or (ii) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that Pepco is entitled to earn based on the approved distribution charge per customer.

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

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Results Of Operations

The following results of operations discussion compares the six months ended June 30, 2010 to the six months ended June 30, 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	$	482	$	443	$	39
Default Electricity Supply Revenue		592		634		(42	)
Other Electric Revenue		17		18		(1	)
Total Operating Revenue	$	1,091	$	1,095	$	(4	)

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 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	$	134	$	122	$	12
Commercial and industrial		289		270		19
Other		59		51		8
Total Regulated T&D Electric Revenue	$	482	$	443	$	39

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

Regulated T&D Electric Sales (Gigawatt hours (GWh))	2010	2009	Change
Residential	4,003	3,792	211
Commercial and industrial	9,277	9,135	142
Other	77	78	(1	)
Total Regulated T&D Electric Sales	13,357	13,005	352
Regulated T&D Electric Customers (in thousands)	2010	2009	Change
Residential	707	695	12
Commercial and industrial	74	73	1
Other	—	—	—
Total Regulated T&D Electric Customers	781	768	13

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

• An increase of $13 million due to higher pass-through revenue (which is substantially offset by a corresponding increase in Other Taxes) primarily the result of rate increases in utility taxes that are collected on behalf of the taxing jurisdictions.

• An increase of $7 million in transmission revenue primarily attributable to the accrual of a true-up to reflect costs incurred in the June 2009 through May 2010 service period that were included in the final determination of the network service transmission rate effective June 1, 2010 through May 31, 2011, which includes rate adjustments for the true-up.

• An increase of $5 million due to distribution rate increases in the District of Columbia that became effective in November 2009 and March 2010.

• An increase of $4 million due to customer growth of 2% primarily in the residential class in 2010.

• An increase of $4 million due to the implementation of the EmPower Maryland (demand side management program) surcharge rate in March 2010 (which is substantially offset by a corresponding increase in Depreciation and Amortization).

• An increase of $3 million due to higher sales in the District of Columbia service territory as a result of warmer weather during the 2010 spring months as compared to 2009. The BSA was not implemented in the District of Columbia until November 2009; therefore, a change in weather was a factor when comparing revenue from period to period.

Default Electricity Supply

Default Electricity Supply Revenue	2010		2009		Change
Residential	$	424	$	410	$	14
Commercial and industrial		162		220		(58	)
Other		6		4		2
Total Default Electricity Supply Revenue	$	592	$	634	$	(42	)

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Default Electricity Supply Sales (GWh)	2010	2009	Change
Residential	3,680	3,582	98
Commercial and industrial	1,566	2,101	(535	)
Other	5	4	1
Total Default Electricity Supply Sales	5,251	5,687	(436	)
Default Electricity Supply Customers (in thousands)	2010	2009	Change
Residential	657	657	—
Commercial and industrial	49	52	(3	)
Other	—	—	—
Total Default Electricity Supply Customers	706	709	(3	)

Default Electricity Supply Revenue decreased by $42 million primarily due to:

• A decrease of $62 million due to lower sales, primarily as a result of commercial customer migration to competitive suppliers.

The decrease was partially offset by:

• An increase of $21 million due to higher sales as a result of warmer weather during the 2010 spring months as compared to 2009.

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 six months ended June 30.

	2010		2009
Sales to District of Columbia customers	29	%	34	%
Sales to Maryland customers	47	%	51	%

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 $46 million to $576 million in 2010 from $622 million in 2009 primarily due to:

• A decrease of $64 million primarily due to commercial customer migration to competitive suppliers.

• A decrease of $36 million in deferred electricity expense due to a lower rate of recovery from customers of electricity supply costs.

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The aggregate amount of these decreases was partially offset by:

• An increase of $38 million due to higher average electricity costs under Default Electricity Supply contracts.

• An increase of $19 million due to higher sales as a result of warmer weather during the 2010 spring months as compared to 2009.

Other Operation and Maintenance

Other Operation and Maintenance increased by $1 million to $161 million in 2010 from $160 million in 2009 primarily due to:

• An increase of $8 million in emergency restoration costs largely due to the February 2010 severe winter storms.

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

The aggregate amount of these increases was partially offset by:

• A decrease of $4 million in employee-related costs, primarily due to lower pension and other postretirement benefits expenses.

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

• A decrease of $2 million primarily due to lower corrective maintenance costs.

In July 2010, the Pepco service territory experienced severe thunderstorms. These storms caused significant damage to Pepco’s electric transmission and distribution system. The cost of system restoration is currently expected to range from $10 million to $13 million. A portion of the restoration cost will be expensed with the balance being charged to capital. The actual cost of system restoration could vary significantly from these estimates, because a large portion of the cost relates to services provided by outside contractors and other utilities for which Pepco has not yet been billed.

Depreciation and Amortization

Depreciation and Amortization expenses increased by $6 million to $78 million in 2010 from $72 million in 2009 primarily due to:

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

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

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Other Taxes

Other Taxes increased by $16 million to $163 million in 2010 from $147 million in 2009. The increase (which is substantially offset by a corresponding increase in Regulated T&D Electric Revenue) was primarily due to increased pass-throughs resulting from rate increases in utility taxes imposed by the taxing jurisdictions.

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 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 six months ended June 30, 2010 and 2009 were 42.0% and 42.9%, respectively. The decrease in the rate primarily resulted from a decrease in other, most notably related to the amortization of software costs which are required by the Company’s regulators to be treated as a permanent difference. This decrease is partially offset by changes in estimates and interest related to uncertain and effectively settled tax positions as a percentage of pre-tax income.

Capital Requirements

Capital Expenditures

Pepco’s capital expenditures for the six months ended June 30, 2010, totaled $136 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. Pepco was awarded $149 million with $105 million to be used in the Maryland Service territory and $44 million to be used in the District of Columbia service territory.

In April 2010, PHI and the DOE signed agreements formalizing Pepco’s $149 million share of the $168 million award. Of the $149 million, $118 million 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.

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Forward-Looking Statements

Some of the statements contained in this Quarterly Report on Form 10-Q are forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and are subject to the safe harbor created by the Private Securities Litigation Reform Act of 1995. These statements include declarations regarding 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 transmission and distribution facilities, and the recovery of purchased power expenses;

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

• Weather conditions;

• Population growth rates and demographic patterns;

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

• 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 customer demand for electricity;

• 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.

150

DPL

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

Delmarva Power & Light Company

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

General Overview

DPL is engaged in the transmission and distribution of electricity in Delaware and portions of Maryland. DPL also provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its service territories who do not elect to purchase electricity from a competitive 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 June 30, 2010, approximately 65% of delivered electricity sales were to Delaware customers and approximately 35% were to Maryland customers. In northern Delaware, DPL also supplies and distributes natural gas to retail customers and provides transportation-only services to retail customers that purchase natural gas from other suppliers. DPL’s natural gas distribution service territory covers approximately 275 square miles and has a population of approximately 500,000.

Effective June 2007, the Maryland Public Service Commission approved a bill stabilization adjustment mechanism (BSA) for retail electric 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 (FERC) under PUHCA 2005.

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Results Of Operations

The following results of operations discussion compares the six months ended June 30, 2010 to the six months ended June 30, 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	$	176	$	170	$	6
Default Electricity Supply Revenue		373		390		(17	)
Other Electric Revenue		10		12		(2	)
Total Electric Operating Revenue	$	559	$	572	$	(13	)

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 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, 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	$	87	$	80	$	7
Commercial and industrial		53		50		3
Other		36		40		(4	)
Total Regulated T&D Electric Revenue	$	176	$	170	$	6

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

Regulated T&D Electric Sales (Gigawatt hours (GWh))	2010	2009	Change
Residential	2,558	2,469	89
Commercial and industrial	3,550	3,612	(62	)
Other	25	25	—
Total Regulated T&D Electric Sales	6,133	6,106	27

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Regulated T&D Electric Customers (in thousands)	2010	2009	Change
Residential	439	438	1
Commercial and industrial	59	59	—
Other	1	1	—
Total Regulated T&D Electric Customers	499	498	1

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

• An increase of $5 million due to a distribution rate increase in Maryland that became effective in December 2009.

• An increase of $2 million due to a distribution rate increase in Delaware that was placed into effect in April 2010, subject to refund and pending final Delaware Public Service Commission approval.

• An increase of $2 million due to higher sales as a result of warmer weather during the 2010 spring months as compared to 2009.

The aggregate amount of these increases was partially offset by:

• A decrease of $4 million in transmission service revenue primarily due to a transmission rate decrease in June 2009.

Default Electricity Supply

Default Electricity Supply Revenue	2010		2009		Change
Residential	$	278	$	275	$	3
Commercial and industrial		90		111		(21	)
Other		5		4		1
Total Default Electricity Supply Revenue	$	373	$	390	$	(17	)
Default Electricity Supply Sales (GWh)	2010		2009		Change
Residential		2,499		2,423		76
Commercial and industrial		929		1,054		(125	)
Other		21		21		—
Total Default Electricity Supply Sales		3,449		3,498		(49	)
Default Electricity Supply Customers (in thousands)	2010		2009		Change
Residential		430		430		—
Commercial and industrial		46		48		(2	)
Other		1		1		—
Total Default Electricity Supply Customers		477		479		(2	)

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

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

• A decrease of $11 million as a result of lower Default Electricity Supply rates.

The aggregate amount of these decreases was partially offset by:

• An increase of $8 million due to higher sales as a result of warmer weather during the 2010 spring months as compared to 2009.

• An increase of $6 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 six months ended June 30:

	2010		2009
Sales to Delaware customers	52	%	53	%
Sales to Maryland customers	64	%	65	%

Natural Gas Operating Revenue

	2010		2009		Change
Regulated Gas Revenue	$	111	$	149	$	(38	)
Other Gas Revenue		20		22		(2	)
Total Natural Gas Operating Revenue	$	131	$	171	$	(40	)

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	$	69	$	92	$	(23	)
Commercial and industrial		38		53		(15	)
Transportation and other		4		4		—
Total Regulated Gas Revenue	$	111	$	149	$	(38	)
Regulated Gas Sales (billion cubic feet)	2010		2009		Change
Residential		5		5		—
Commercial and industrial		3		3		—
Transportation and other		3		3		—
Total Regulated Gas Sales		11		11		—
Regulated Gas Customers (in thousands)	2010		2009		Change
Residential		113		113		—
Commercial and industrial		9		9		—
Transportation and other		—		—		—
Total Regulated Gas Customers		122		122		—

Regulated Gas Revenue decreased by $38 million primarily due to:

• A decrease of $31 million due to lower sales as a result of milder weather during the 2010 winter months as compared to 2009.

• A decrease of $21 million due to Gas Cost Rate decreases effective March 2009 and November 2009.

The aggregate amount of these decreases was partially offset by:

• An increase of $14 million due to higher non-weather related average customer usage.

Other Gas Revenue

Other Gas Revenue decreased by $2 million primarily due to lower revenue from capacity release sales, which represent the short-term release of interstate pipeline transportation and storage capacity not needed to serve customers.

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 $20 million to $360 million in 2010 from $380 million in 2009 primarily due to:

• A decrease of $17 million in deferred electricity expense due to a lower rate of recovery from customers of electricity supply costs.

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• A decrease of $12 million primarily due to commercial and residential customer migration to competitive suppliers.

The aggregate amount of these decreases was partially offset by:

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

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 $37 million to $91 million in 2010 from $128 million in 2009 primarily due to:

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

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

• 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.

Other Operation and Maintenance

Other Operation and Maintenance increased by $8 million to $126 million in 2010 from $118 million in 2009. Excluding an increase of $2 million primarily related to administrative expenses that are deferred and recoverable in Default Electricity Supply Revenue, Other Operation and Maintenance expense increased by $6 million. The $6 million increase was primarily due to:

• An increase of $5 million in emergency restoration costs largely due to the February 2010 severe winter storms.

• An increase of $4 million in environmental remediation costs related to a 1999 oil release at the Indian River generating facility then owned by DPL, as further discussed under “Indian River Oil Release” in Note (12), “Commitments and Contingencies” to the financial statements of DPL.

The aggregate amount of these increases was partially offset by:

• A decrease of $3 million due to lower non-deferrable bad debt expenses.

• A decrease of $2 million in employee-related costs, primarily due to lower pension and other postretirement benefit expenses.

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Income Tax Expense

DPL’s effective tax rates for the six months ended June 30, 2010 and 2009 were 44.4 % and 35.0%, 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 the $2 million reversal of accrued interest income on state income tax positions in 2010 that DPL no longer believes is more likely than not to be realized and the tax benefits related to the filing of the amended state income tax returns recorded in 2009.

Capital Requirements

Capital Expenditures

DPL’s capital expenditures for the six months ended June 30, 2010, totaled $133 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 transmission and distribution facilities, and the recovery of purchased power expenses;

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

• Weather conditions;

• Population growth rates and demographic patterns;

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

• 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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DPL

• 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 customer demand for electricity and natural gas;

• 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.

158

ACE

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

Atlantic City Electric Company

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

General Overview

ACE is engaged in the transmission and distribution of electricity in southern New Jersey. ACE also provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its service territory who do not elect to purchase electricity from a competitive supplier. Default Electricity Supply is also known as Basic Generation Service (BGS) in New Jersey. ACE’s service territory covers approximately 2,700 square miles and has a population of approximately 1.1 million.

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

Results Of Operations

The following results of operations discussion compares the six months ended June 30, 2010 to the six months ended June 30, 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	$	188	$	168	$	20
Default Electricity Supply Revenue		436		454		(18	)
Other Electric Revenue		8		9		(1	)
Total Operating Revenue	$	632	$	631	$	1

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 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 BGS. The costs related to Default Electricity Supply are included in Purchased Energy. Default Electricity Supply Revenue also includes revenue from Transition Bond Charges (revenue ACE receives, and pays to Atlantic City Electric Transition Funding LLC (ACE Funding), to fund the principal and interest payments on Transition Bonds issued by ACE Funding and related taxes, expenses and fees), other restructuring related revenues, and transmission enhancement credits that ACE receives as a transmission owner from PJM for approved regional transmission expansion plan costs.

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

Regulated T&D Electric

Regulated T&D Electric Revenue	2010		2009		Change
Residential	$	77	$	72	$	5
Commercial and industrial		65		62		3
Other		46		34		12
Total Regulated T&D Electric Revenue	$	188	$	168	$	20

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

Regulated T&D Electric Sales (Gigawatt hours (GWh))	2010	2009	Change
Residential	2,089	1,961	128
Commercial and industrial	2,601	2,565	36
Other	22	23	(1	)
Total Regulated T&D Electric Sales	4,712	4,549	163
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 $20 million primarily due to:

• An increase of $12 million in transmission revenue primarily attributable to (i) the accrual of a true-up to reflect costs incurred in the June 2009 through May 2010 service period that were included in the final determination of the network service transmission rate effective June 1, 2010 through May 31, 2011, which includes rate adjustments for the true-up and (ii) other transmission rate increases.

• An increase of $4 million due to higher sales as a result of warmer weather during the 2010 spring months as compared to 2009.

• An increase of $2 million due to a distribution rate increase that became effective in June 2010.

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ACE

Default Electricity Supply

Default Electricity Supply Revenue	2010		2009		Change
Residential	$	237	$	215	$	22
Commercial and industrial		115		161		(46	)
Other		84		78		6
Total Default Electricity Supply Revenue	$	436	$	454	$	(18	)

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

Default Electricity Supply Sales (GWh)	2010	2009	Change
Residential	2,087	1,961	126
Commercial and industrial	1,009	1,465	(456	)
Other	22	23	(1	)
Total Default Electricity Supply Sales	3,118	3,449	(331	)
Default Electricity Supply Customers (in thousands)	2010	2009	Change
Residential	481	481	—
Commercial and industrial	60	63	(3	)
Other	—	1	(1	)
Total Default Electricity Supply Customers	541	545	(4	)

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

• A decrease of $42 million due to lower sales, primarily as a result of commercial customer migration to competitive suppliers.

The decrease was partially offset by:

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

• An increase of $6 million primarily due to an increase in revenue from transmission enhancement credits.

• An increase of $4 million due to higher non-weather related average customer usage.

The decrease in total Default Electricity Supply Revenue includes an increase of $16 million in unbilled revenue attributable to ACE’s BGS. Under the BGS terms approved by the New Jersey Board of Public Utilities, ACE is entitled to recover from its customers all of its costs of providing BGS. If the costs of providing BGS exceed the BGS revenue, then the excess costs are deferred in Deferred Electric Service Costs. ACE’s BGS unbilled revenue is not included in the deferral calculation, and therefore has an impact on the results of operations in the period during which it is accrued. While the change in the amount of unbilled revenue from year to year typically is not significant, for the six months ended June 30, 2010, BGS unbilled revenue increased by $16 million as compared to the six months ended June 30, 2009, which resulted in a $10 million increase in ACE’s net income. The increase was primarily due to warmer weather during the unbilled revenue period at the end of the six months ended June 30, 2010 as compared to the corresponding period in 2009.

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ACE

For the six months ended June 30, 2010 and 2009, the percentages of ACE’s total distribution sales that are derived from customers receiving Default Electricity Supply are 66% and 76%, 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 $38 million to $478 million in 2010 from $516 million in 2009 primarily due to:

• A decrease of $65 million due to lower sales, primarily due to commercial customer migration to competitive suppliers.

The decrease was partially offset by:

• An increase of $16 million due to higher sales as a result of warmer weather during the 2010 spring months as compared to 2009.

• An increase of $11 million due to higher average electricity costs under Default Electricity Supply contracts.

Other Operation and Maintenance

Other Operation and Maintenance increased by $2 million to $97 million in 2010 from $95 million in 2009 primarily due to:

• An increase of $6 million in emergency restoration costs largely due to the February 2010 severe winter storms.

The increase was partially offset by:

• A decrease of $4 million in employee-related costs, primarily due to lower pension and other postretirement benefit expenses.

Deferred Electric Service Costs

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

Deferred Electric Service Costs increased by $2 million, to an expense reduction of $82 million in 2010 as compared to an expense reduction of $84 million in 2009, primarily due to an increase in deferred electricity expense due to a higher rate of recovery from customers of electricity supply costs.

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ACE

Income Tax Expense

ACE’s consolidated effective tax rates for the six months ended June 30, 2010 and 2009 were 48.9% and 16.7% respectively. The increase in the rate resulted from amortization of tax credits and the reversal of $6 million of accrued interest income on uncertain and effectively settled state income tax positions in 2010 and the $1 million non-recurring adjustment in 2009 to prior year taxes. This increase is partially offset by the impact of certain permanent state tax differences.

Capital Requirements

Capital Expenditures

ACE’s capital expenditures for the six months ended June 30, 2010, totaled $76 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, of which $19 million was for ACE’s service territory.

In April 2010, PHI and the DOE signed agreements formalizing ACE’s $19 million share of the $168 million award. Of the $19 million, $12 million 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.

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 transmission and distribution facilities, and the recovery of purchased power expenses;

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ACE

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

• Weather conditions;

• Population growth rates and demographic patterns;

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

• 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 customer demand for electricity;

• Interest rate fluctuations and credit and capital market conditions; and

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

Any forward-looking statements speak only as to the date of this Quarterly Report and ACE undertakes no obligation to update any forward-looking statements to reflect events or circumstances after the date on which such statements are made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for ACE to predict all such factors, nor can ACE assess the impact of any such factor on ACE’s business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.

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

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Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Risk management policies for PHI and its subsidiaries are determined by PHI’s Corporate Risk Management Committee, the members of which are PHI’s Chief Risk Officer, Chief Operating Officer, Chief Financial Officer, General Counsel, Chief Information Officer and other senior executives. The Corporate Risk Management Committee monitors interest rate fluctuation, commodity price fluctuation, and credit risk exposure, and sets risk management policies that establish limits on unhedged risk and determine risk reporting requirements. For information about PHI’s derivative activities, other than the information disclosed herein, refer to Note (2), “Significant Accounting Policies – Accounting For Derivatives,” 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 business (consisting of both the Conectiv Energy and Pepco Energy Services segments) engages in commodity risk management activities to reduce their financial exposure to changes in the value of their assets and obligations due to commodity price fluctuations. Certain of these risk management activities are conducted using instruments classified as derivatives based on Financial Accounting Standards Board (FASB) guidance on derivatives and hedging (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 objective is to manage the spread between wholesale and retail sales commitments and the cost of supply used to service those commitments in order to ensure stable and known cash flows and fix favorable prices and margins. Prior to the sale of the wholesale power generation business on July 1, 2010, the risk management objective of the Conectiv Energy segment also included the management of the spread between the cost of fuel used to operate its electric generating facilities and the revenue received from the sale of the power produced by those facilities by selling forward a portion of their projected generating facility output and buying forward a portion of their projected fuel supply requirements.

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 of both the Conectiv Energy and Pepco Energy Services segments for the six months ended June 30, 2010 in millions of dollars:

	VaR for Competitive Energy  Commodity Activities (a)
95% confidence level, one-day holding period, one-tailed
Period end	$	4
Average for the period	$	3
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.

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Prior to the sale of Conectiv Energy’s wholesale power generation business on July 1, 2010, Conectiv Energy engaged in the economic hedging of both its estimated generating facility output and fuel requirements as the estimated levels of output and fuel needs changed. These economic hedges included 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).

Prior to the sale of Conectiv Energy’s wholesale power generation business, Conectiv Energy maintained 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 computed the probability of run-time derived from forward market prices for power and fuel, and then computed the desired hedge positions, over the succeeding 36 months. Conectiv Energy executed 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 was 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. With the adoption in April 2010 of the plan for disposition of the Conectiv Energy segment, the Conectiv Energy economic hedging program was modified by reducing the term of the hedges to cover only the expected generating facility output through the target closing date of the sale of the wholesale power penetration business.

Since the inception of the Reliability Pricing Model (RPM) in PJM, Conectiv Energy sold a portion of its generating capacity forward in the over-the-counter market.

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. Forward contracts that meet the requirements for normal purchase and normal sale accounting under FASB guidance on derivatives and hedging are accounted for using accrual accounting.

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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 June 30, 2010, in millions of dollars:

Rating	Exposure Before Credit Collateral (b)		Credit Collateral (c)		Net Exposure		Number of Counterparties Greater Than 10% (d)	Net Exposure  of Counterparties Greater Than 10%
Investment Grade (a)	$	262	$	—	$	262	3	$	165
Non-Investment Grade		5		—		5	—		—
No External Ratings		12		7		5	—		—
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 June 30, 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.

Changes in Internal Control Over Financial Reporting

During the three months ended June 30, 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.

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In April 2010, a regulated subsidiary of PHI, DPL, began activation of the Advanced Metering Infrastructure (AMI) for purposes of collecting customer meter reading data for billing and other purposes. DPL’s activation process is expected to continue through early 2011.

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 June 30, 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 June 30, 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.

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 June 30, 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 June 30, 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.

In April 2010, DPL began activation of the Advanced Metering Infrastructure (AMI) for purposes of collecting customer meter reading data for billing and other purposes. The activation process is expected to continue through early 2011.

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 June 30, 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

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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 June 30, 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. There have been no material changes to Pepco Holdings’ risk factors as disclosed in the 10-K, except that:

(1) Each of the following risk factors supersedes the risk factor with the same heading in the Form 10-K:

Pepco may be required to make additional divestiture proceeds gain-sharing payments to customers in the District of Columbia. (PHI and Pepco only)

Pepco currently is involved in regulatory proceedings in the District of Columbia related to the sharing of the net proceeds from the sale in 2000 of its generation-related assets. In an order issued in May 2010, the District of Columbia Public Service Commission (DCPSC) disallowed certain costs that Pepco had deducted from the proceeds of the generation asset sale in determining the portion of the gains from the

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sale that Pepco was required to share with its District of Columbia customers in accordance with the sharing formula adopted by the DCPSC. Under the terms of the DCPSC order, Pepco will be required to distribute to its District of Columbia customers additional proceeds, which together with interest total approximately $10.8 million. In July 2010, the DCPSC denied Pepco’s application for reconsideration in which it contested $9.6 million of the $10.8 million. Pepco intends to appeal the DCPSC’s decision to the District of Columbia Court of Appeals, although there is no assurance that the appeal will result in modification of the order.

The operating results of the Power Delivery business and the Competitive Energy business fluctuate on a seasonal basis and can be adversely affected by changes in weather.

The Power Delivery business historically has been seasonal and weather has had a material impact on its operating performance. Demand for electricity is generally higher in the summer months associated with cooling and demand for electricity and natural gas is generally higher in the winter months associated with heating as compared to other times of the year. Accordingly, each of PHI, Pepco, DPL and ACE historically has generated less revenue and income when temperatures are warmer than normal in the winter and cooler than normal in the summer. The recent adoption for retail customers of Pepco and DPL in Maryland and for Pepco retail customers in the District of Columbia, of a bill stabilization adjustment mechanism which decouples distribution revenue for a given reporting period from the amount of power delivered during the period, has had the effect of eliminating changes in the use of electricity by such retail customers due to weather conditions or for other reasons as a factor having an impact on reported distribution revenue and income.

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

Historically, the competitive energy operations of Conectiv Energy and Pepco Energy Services also have produced less gross margin when weather conditions are milder than normal. With the sale of the Conectiv Energy generation assets, upon the completion of the ongoing liquidation of Conectiv Energy’s load supply contracts and hedging portfolio, the completion of the ongoing wind down of Pepco Energy Services’ retail energy supply business and the deactivation of Pepco Energy Services’ two generating plants (scheduled for May 2012), PHI’s financial results no longer will be affected by the impact of weather on the Competitive Energy business. The Energy Services business of Pepco Energy Services, which includes providing energy savings performance contracting services principally to federal, state and local government customers, and designing, constructing and operating combined heat and power energy plants for customers, is not seasonal.

Facilities may not operate as planned or may require significant maintenance expenditures, which could decrease revenues or increase expenses.

Operation of the Pepco, DPL and ACE transmission and distribution facilities and Pepco Energy Services’ generation facilities (scheduled for deactivation in May 2012) involves many risks, including the breakdown or failure of equipment, accidents, labor disputes and performance below expected levels. Older facilities and equipment, even if maintained in accordance with sound engineering practices, may require significant capital expenditures for additions or upgrades to keep them operating at peak efficiency, to comply with changing environmental requirements, or to provide reliable operations. Natural disasters and weather-related incidents, including tornadoes, hurricanes and snow and ice storms, also can disrupt generation, transmission and distribution delivery systems. Operation of generation, transmission and distribution facilities below expected capacity levels can reduce revenues and result in the incurrence of additional expenses that may not be recoverable from customers or through insurance, including deficiency charges imposed by PJM on generation facilities at a rate of up to two times the

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capacity payment that the generation facility receives. Furthermore, the generation and transmission facilities of the PHI companies are subject to reliability standards imposed by the North American Electric Reliability Corporation. Failure to comply with the standards may result in substantial monetary penalties.

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

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

The operations of PHI’s subsidiaries, including Pepco, DPL and ACE, are subject to extensive federal, state and local environmental laws and regulations relating to air quality, water quality, spill prevention, waste management, natural resources, site remediation, and health and safety. These laws and regulations may require significant capital and other expenditures to, among other things, meet emissions and effluent standards, conduct site remediation, complete environmental studies, and perform environmental monitoring. If a company fails to comply with applicable environmental laws and regulations, even if caused by factors beyond its control, such failure could result in the assessment of civil or criminal penalties and liabilities and the need to expend significant sums to come into compliance.

In addition, PHI’s subsidiaries are required to obtain and comply with a variety of environmental permits, licenses, inspections and other approvals. If there is a delay in obtaining any required environmental regulatory approval, or if there is a failure to obtain, maintain or comply with any such approval, operations at affected facilities could be halted or subjected to additional costs.

There is growing concern at the federal and state levels regarding the implications of CO₂ and other greenhouse gas emissions on the global climate. The U.S. Congress has had under consideration climate change legislation, including the possibility of a carbon cap and trade program. The implementation of a federal cap and trade program for CO₂ and other greenhouse gases or regulatory action by the U.S. Environmental Protection Agency prior to the May 2012 deactivation of Pepco Energy Services’ generating facilities could require Pepco Energy Services to incur increased capital expenditures or operating costs to replace existing equipment, install additional pollution control equipment or purchase CO₂ allowances and offsets. Alternatively, Pepco Energy Services could be required to discontinue or curtail the operations of one or more units prior to their planned deactivation date.

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

PHI’s Competitive Energy business is highly competitive. (PHI only)

With the sale of the Conectiv Energy generation assets, upon the completion of the ongoing liquidation of Conectiv Energy’s load supply contracts and hedging portfolio, the completion of the ongoing wind down of Pepco Energy Services’ retail energy supply business and the deactivation of Pepco Energy Services’ generating plants scheduled for May 2012, PHI will have completely exited the unregulated energy generation, supply and marketing businesses. Pepco Energy Services’ continuing energy management services business is highly competitive. This competition generally has had the effect of reducing margins and requiring a continual focus on controlling costs.

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PHI’s Competitive Energy business relies on some generation, transmission, storage, and distribution assets that they do not own or control to deliver wholesale and retail electricity and natural gas and to obtain fuel for its remaining generating facilities. (PHI only)

PHI’s Competitive Energy business depends on electric generation and transmission facilities, natural gas pipelines, and natural gas storage facilities owned and operated by others. If the operation of these facilities is disrupted or their capacity is inadequate or unavailable, the ability of the Competitive Energy business to buy and receive and/or sell and deliver wholesale and retail power and natural gas, and therefore to fulfill its contractual obligations, could be adversely affected. With the sale of the Conectiv Energy generation assets , upon the completion of the ongoing liquidation of Conectiv Energy’s load supply contracts and hedging portfolio and the completion of the ongoing wind down of Pepco Energy Services’ retail energy supply business, these factors will no longer have the potential for affecting PHI’s results of operations.

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

PHI’s risk management procedures may not prevent losses in the operation of its Competitive Energy business. (PHI only)

The operations of PHI’s Competitive Energy business have been conducted in accordance with sophisticated risk management systems that are designed to quantify and control risk. However, actual results sometimes deviate from modeled expectations. With the sale of the Conectiv Energy generation assets, upon the completion of the ongoing liquidation of Conectiv Energy’s load supply contracts and hedging portfolio, the completion of the ongoing wind down of Pepco Energy Services’ retail energy supply business and the deactivation of Pepco Energy Services’ two generating plants (scheduled for May 2012), this risk no longer will be material to the operations of the Competitive Energy business.

The commodity hedging procedures used by the Competitive Energy business may not protect it from significant losses caused by volatile commodity prices. (PHI only)

To lower the financial exposure related to commodity price fluctuations, Conectiv Energy entered into contracts to hedge the value of its assets and operations. As part of this strategy, Conectiv Energy has utilized fixed-price, forward, physical purchase and sales contracts, tolling agreements, futures, financial swaps and option contracts traded in the over-the-counter markets or on exchanges. Due to the high heat rate of the Pepco Energy Services generating facilities, Pepco Energy Services generally has not entered into wholesale contracts to lock in the forward value of its plants. To the extent that the Competitive Energy business has unhedged positions or its hedging procedures do not work as planned, fluctuating commodity prices could result in significant losses. Conversely, by engaging in hedging activities, PHI may not realize gains that otherwise could result from fluctuating commodity prices.

With the sale of the Conectiv Energy generation assets, upon the completion of the ongoing liquidation of Conectiv Energy’s load supply contracts and hedging portfolio, this risk no longer will be material to the Competitive Energy business.

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PHI and its subsidiaries have significant exposure to counterparty risk. (PHI only)

Historically, both Conectiv Energy and Pepco Energy Services have entered into transactions with numerous counterparties. These include both commercial transactions for the purchase and sale of electricity and natural gas, and derivative and other transactions, to manage the risk of commodity price fluctuations. Under these arrangements, the Competitive Energy business is exposed to the risk that the counterparty may fail to perform its obligation to make or take delivery under the contract, fail to make a required payment or fail to return collateral posted by the Competitive Energy business when no longer required. Under many of these contracts, Conectiv Energy and Pepco Energy Services are entitled to receive collateral or other types of performance assurance from the counterparty, which may be in the form of cash, letters of credit or parent guarantees, to protect against performance and credit risk. Even where collateral is provided, capital market disruptions can prevent the counterparty from meeting its collateral obligations or degrade the value of letters of credit and guarantees as a result of the lowered rating or insolvency of the issuer or guarantor. In the event of a bankruptcy of a counterparty, bankruptcy law, in some circumstances, could require Conectiv Energy or Pepco Energy Services to surrender collateral held or payments received. With the sale of Conectiv Energy’s generation assets, upon the completion of the ongoing liquidation of Conectiv Energy’s load supply contracts and hedging portfolio and the deactivation of Pepco Energy Services’ two generating plants (scheduled for May 2012), this risk no longer will be material to the operations of the Competitive Energy business.

Business operations could be adversely affected by terrorism.

The threat of, or actual acts of, terrorism may affect the operations of PHI and its subsidiaries in unpredictable ways and may cause changes in the insurance markets, force an increase in security measures and cause disruptions of fuel supplies and markets. If any of its infrastructure facilities, including its transmission or distribution facilities, were to be a direct target, or an indirect casualty, of an act of terrorism, the operations of PHI, Pepco, DPL or ACE could be adversely affected. Corresponding instability in the financial markets as a result of terrorism also could adversely affect the ability to raise needed capital.

(2) The following risk factor supersedes, as it relates to PHI, the risk factor in the Form 10-K with the heading having as its introductory sentence, “Changes in technology may adversely affect the Power Delivery business and the Competitive Energy business”:

Changes in technology may adversely affect the Power Delivery business

Increased conservation made possible through advances in technology could reduce demand for electricity supply and distribution and advances in technology could alter the channels through which retail electricity is distributed to customers. Such developments could adversely affect the Power Delivery business.

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(3) The following risk factor supersedes, as it relates to PHI, the risk factor in the Form 10-K with the heading having as its introductory sentence, “The operations of the Competitive Energy business can give rise to significant collateral requirements”:

The operations of the Competitive Energy business can give rise to significant collateral requirements. (PHI only)

A substantial portion of Pepco Energy Services’ business has been the sale of electricity and natural gas to retail customers. In conducting this business, Pepco Energy Services typically entered into electricity and natural gas sale contracts under which it committed to supply the electricity or natural gas requirements of its retail customers over a specified period at agreed upon prices. To acquire the required energy, Pepco Energy Services entered into wholesale purchase contracts for electricity and natural gas. These contracts typically impose collateral requirements on each party designed to protect the other party against the risk of nonperformance between the date the contract was entered into and the date the energy is paid for. The collateral required to be posted can be of varying forms, including cash, letters of credit and guarantees. When energy market prices decrease relative to the supplier contract prices, Pepco Energy Service’s collateral obligations increase. While Pepco Energy Services no longer enters into new energy supply contracts, it has continuing supply obligations based on prior contracts and corresponding wholesale purchase contracts that extend through 2014. Particularly in periods of energy market price volatility, the collateral obligations associated with the these wholesale purchase contracts can be substantial, although they can be expected to diminish as the Pepco Energy Services retail energy supply business is wound down. These collateral demands could negatively affect PHI’s liquidity by requiring PHI to draw on its capacity under its credit facilities and other financing sources.

In addition, Conectiv Energy and Pepco Energy Services historically have entered into contracts to buy and sell electricity, various fuels, and related products, including derivative instruments, to reduce their financial exposure to changes in the value of their assets and obligations due to energy price fluctuations. These contracts usually required the posting of collateral. Under certain contracts, the required collateral was provided in the form of an investment grade guaranty issued by PHI. Under these contracts, a reduction in PHI’s credit rating could trigger a requirement to post additional collateral. To satisfy these obligations when required, PHI and its non-utility subsidiaries relied primarily on cash balances, access to the capital markets and existing credit facilities. With the sale of Conectiv Energy’s generation assets, upon the completion of the ongoing liquidation of Conectiv Energy’s load supply contracts and hedging portfolio and the deactivation of Pepco Energy Services’ two generating plants (scheduled for May 2012), these collateral requirements no longer will apply.

Pepco

For a discussion of Pepco’s risk factors, please refer to Item 1A “Risk Factors” in Pepco’s Annual Report on Form 10-K for the year ended December 31, 2009. There have been no material changes to Pepco’s risk factors as disclosed in the 10-K, except that the following risk factor supersedes the risk factor with the same heading in the Form 10-K:

Pepco may be required to make additional divestiture proceeds gain-sharing payments to customers in the District of Columbia.

Pepco currently is involved in regulatory proceedings in the District of Columbia related to the sharing of the net proceeds from the sale in 2000 of its generation-related assets. In an order issued in May 2010, the District of Columbia Public Service Commission (DCPSC) disallowed certain costs that Pepco had deducted from the proceeds of the generation asset sale in determining the portion of the gains from the sale that Pepco was required to share with its District of Columbia customers in accordance with the sharing formula adopted by the DCPSC. Under the terms of the DCPSC order, Pepco will be required to distribute to its District of Columbia customers additional proceeds, which together with interest total approximately $10.8 million. In July 2010, the DCPSC denied Pepco’s application for reconsideration in which it contested $9.6 million of the $10.8 million. Pepco intends to appeal the DCPSC’s decision to the District of Columbia Court of Appeals, although there is no assurance that the appeal will result in modification of the order.

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DPL

For a discussion of DPL’s risk factors, please refer to Item 1A “Risk Factors” in DPL’s Annual Report on Form 10-K for the year ended December 31, 2009. There have been no material changes to DPL’s risk factors as disclosed in the 10-K.

ACE

For a discussion of ACE’s risk factors, please refer to Item 1A “Risk Factors” in ACE’s Annual Report on Form 10-K for the year ended December  31, 2009. There have been no material changes to ACE’s risk factors as disclosed in the 10-K.

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

Pepco Holdings

None.

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

Item 3. DEFAULTS UPON SENIOR SECURITIES

Pepco Holdings

None.

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

Item 4. RESERVED

Item 5. OTHER INFORMATION

Pepco Holdings

None.

Pepco

None.

DPL

None.

ACE

None.

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Item 6. EXHIBITS

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

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
2.1	PHI	Purchase Agreement, dated as of April 20, 2010, by and among Pepco Holdings, Inc., Conectiv, LLC, Conectiv Energy Holding Company, LLC and New Development Holdings, LLC	Exhibit 2.1 to PHI’s Form 8-K, 7/8/2010
12.1	PHI	Statements Re: Computation of Ratios	Filed herewith.
12.2	Pepco	Statements Re: Computation of Ratios	Filed herewith.
12.3	DPL	Statements Re: Computation of Ratios	Filed herewith.
12.4	ACE	Statements Re: Computation of Ratios	Filed herewith.
31.1	PHI	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	Filed herewith.
31.2	PHI	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	Filed herewith.
31.3	Pepco	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	Filed herewith.
31.4	Pepco	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	Filed herewith.
31.5	DPL	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	Filed herewith.
31.6	DPL	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	Filed herewith.
31.7	ACE	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	Filed herewith.
31.8	ACE	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	Filed herewith.
32.1	PHI	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	Furnished herewith.
32.2	Pepco	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	Furnished herewith.
32.3	DPL	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	Furnished herewith.
32.4	ACE	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	Furnished herewith.
101. INS	PHI, Pepco, DPL, ACE	XBRL Instance Document	Submitted herewith.
101. SCH	PHI, Pepco, DPL, ACE	XBRL Taxonomy Extension Schema Document	Submitted herewith.
101. CAL	PHI, Pepco, DPL, ACE	XBRL Taxonomy Extension Calculation Linkbase Document	Submitted herewith.
101. DEF	PHI, Pepco, DPL, ACE	XBRL Taxonomy Extension Definition Linkbase Document	Submitted herewith.
101. LAB	PHI, Pepco, DPL, ACE	XBRL Taxonomy Extension Label Linkbase Document	Submitted herewith.
101. PRE	PHI, Pepco, DPL, ACE	XBRL Taxonomy Extension Presentation Linkbase Document	Submitted herewith.

176

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)
August 6, 2010	By	/s/    A.J. KAMERICK
		Anthony J. Kamerick
		Senior Vice President and Chief Financial Officer, PHI, Pepco and DPL Chief Financial Officer, ACE

177

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