Delmarva Power & Light 10-Q 2011 Q2 Quarterly report

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, 2011

Commission File Number	Name of Registrant, State of Incorporation, Address of Principal Executive Offices, and Telephone Number	I.R.S. Employer Identification Number
001-31403	PEPCO HOLDINGS, INC. (Pepco Holdings or PHI), a Delaware corporation 701 Ninth Street, N.W. Washington, D.C. 20068 Telephone: (202)872-2000	52-2297449
001-01072	POTOMAC ELECTRIC POWER COMPANY (Pepco), a District of Columbia and Virginia corporation 701 Ninth Street, N.W. Washington, D.C. 20068 Telephone: (202)872-2000	53-0127880
001-01405	DELMARVA POWER & LIGHT COMPANY (DPL), a Delaware and Virginia corporation 500 North Wakefield Drive Newark, DE 19702 Telephone: (202)872-2000	51-0084283
001-03559	ATLANTIC CITY ELECTRIC COMPANY (ACE), a New Jersey corporation 500 North Wakefield Drive Newark, DE 19702 Telephone: (202)872-2000	21-0398280

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

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

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

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

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

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

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

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

Pepco, DPL, and ACEmeet 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 July 31, 2011
Pepco Holdings		226,395,875 ($.01 par value)
Pepco		100 ($.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		103
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		171
Item 3.	- Defaults Upon Senior Securities		171
Item 4.	- Reserved		171
Item 5.	- Other Information		171
Item 6.	- Exhibits		175
Signatures			177

GLOSSARY OF TERMS

Term	Definition
ACE	Atlantic City Electric Company
ACE Funding	Atlantic City Electric Transitional Funding LLC
ADITC	Accumulated deferred investment tax credits
AMI	Advanced metering infrastructure
AOCL	Accumulated Other Comprehensive Loss
ASC	Accounting Standards Codification
BGS	Basic Generation Service (the supply of electricity by ACE to retail customers in New Jersey who have not elected to purchase electricity from a competitive supplier)
Bondable Transition Property	The principal and interest payments on the Transition Bonds and related taxes, expenses and fees
BSA	Bill Stabilization Adjustment
Budget Support Act	Fiscal year 2012 Budget Support Act of 2011 approved by the DC Council
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
CSA	Credit Support Annex
DC Council	Council for the District of Columbia
DCPSC	District of Columbia Public Service Commission
DDOE	District of Columbia Department of the Environment
Default Electricity Supply	The supply of electricity by PHI’s electric utility subsidiaries at regulated rates to retail customers who do not elect to purchase electricity from a competitive supplier, and which, depending on the jurisdiction, is also known as Standard Offer Service or BGS
Default Electricity Supply Revenue	Revenue primarily from Default Electricity Supply
DOE	U.S. Department of Energy
DPL	Delmarva Power & Light Company
DPSC	Delaware Public Service Commission
EDCs	Electric distribution companies
EDIT	Excess Deferred Income Taxes
EmPower Maryland	A Maryland demand-side management program for Pepco and DPL
Energy Services	Energy savings performance contracting services provided principally to federal, state and local government customers, and designing, constructing and operating combined heat and power, and central energy plants by Pepco Energy Services
EPA	U.S. Environmental Protection Agency
EPS	Earnings per share
Exchange Act	Securities Exchange Act of 1934, as amended
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FHACA	Flood Hazard Area Control Act
GAAP	Accounting principles generally accepted in the United States of America
GCR	Gas Cost Rate
GWh	Gigawatt hour
IRS	Internal Revenue Service
ISDA	International Swaps and Derivatives Association
ISRA	New Jersey’s Industrial Site Recovery Act
MAPP	Mid-Atlantic Power Pathway
Market Transition Charge Tax	Revenue ACE receives and pays to ACE Funding to recover income taxes associated with Transition Bond Charge revenue
MDC	MDC Industries, Inc.
MFVRD	Modified fixed variable rate design

i

Term	Definition
Mirant	Mirant Corporation
MMBtu	One Million British Thermal Units
MPSC	Maryland Public Service Commission
MSCG	Morgan Stanley Capital Group, Inc.
MWh	Megawatt hours
New Jersey Societal Benefit Charge	Charge to ACE customers, included in revenue, to recover costs associated with New Jersey Societal Benefit Programs
New Jersey Societal Benefit Programs	Various NJBPU - mandated social programs for which ACE receives revenues to recover costs
NJBPU	New Jersey Board of Public Utilities
NJDEP	New Jersey Department of Environmental Protection
Non-Utility Generation Change	Charge to ACE customers, included in revenue, to recover costs associated with utility purchase power contracts with non-utility generators, net of any revenue received from the sale of energy and capacity
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
NPL	National Priorities list, which, among other things, serves as a guide to EPA in determining which sites warrant further investigation to assess the nature and extent of the human health and environmental risks associated with a site
NUGs	Non-utility generators
NYMEX	New York Mercantile Exchange
PCB	Polychlorinated biphenyls
PCI	Potomac Capital Investment Corporation and its subsidiaries
Pepco	Potomac Electric Power Company
Pepco Energy Services	Pepco Energy Services, Inc. and its subsidiaries
Pepco Holdings or PHI	Pepco Holdings, Inc.
PHI Retirement Plan	PHI’s noncontributory retirement plan
PJM	PJM Interconnection, LLC
PJM RTO	PJM regional transmission organization
Power Delivery	PHI’s Power Delivery Business
PPA	Power purchase agreement
PRP	Potentially responsible party
PUHCA 2005	Public Utility Holding Company Act of 2005
RECs	Renewable energy credits
Regulated T&D Electric Revenue	Revenue from the transmission and the distribution of electricity to PHI’s customers within its service territories at regulated rates
RI/FS	Remedial investigation and feasibility study
ROE	Return on equity
RPM	Reliability pricing model
RPS	Renewable Energy Portfolio Standards
SEC	Securities and Exchange Commission
SERP	Supplemental Executive Retirement Plan
SOCAs	Standard Offer Capacity Agreements required to be entered into by ACE pursuant to a New Jersey law enacted to promote the construction of qualified electric generation facilities in New Jersey
SPCC	Spill Prevention, Control, and Countermeasure plans, required pursuant to federal regulations requiring plans for facilities using oil-containing equipment in proximity to surface waters
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

ii

Term	Definition
Transition Bonds	Transition Bonds issued by ACE Funding
Treasury rate lock	A hedging transaction that allows a company to “lock in” a specific interest rate corresponding to the rate of a designated Treasury bond for a determined period of time
VADEQ	Virginia Department of Environmental Quality
VaR	Value at Risk

ii

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		51		69		88
Consolidated Statements of Comprehensive Income (Loss)		3		N/A		N/A		N/A
Consolidated Balance Sheets		4		52		70		89
Consolidated Statements of Cash Flows		6		54		72		91
Notes to Consolidated Financial Statements		7		55		73		92

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

1

PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended June  30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(millions of dollars, except per share data)
Operating Revenue
Power Delivery	$	1,093		$	1,149		$	2,342		$	2,411
Pepco Energy Services		308			476			681			1,023
Other		8			11			20			21
Total Operating Revenue		1,409			1,636			3,043			3,455
Operating Expenses
Fuel and purchased energy		809			1,077			1,804			2,364
Other services cost of sales		43			35			86			60
Other operation and maintenance		209			196			443			410
Depreciation and amortization		105			93			210			182
Other taxes		109			105			220			197
Gain on early termination of finance leases held in trust		(39	)		—			(39	)		—
Deferred electric service costs		(29	)		(63	)		(32	)		(82	)
Total Operating Expenses		1,207			1,443			2,692			3,131
Operating Income		202			193			351			324
Other Income (Expenses)
Interest expense		(63	)		(89	)		(125	)		(172	)
Loss from equity investments		—			—			(1	)		(1	)
Other income		10			5			20			11
Total Other Expenses		(53	)		(84	)		(106	)		(162	)
Income from Continuing Operations Before Income Tax Expense		149			109			245			162
Income Tax Expense Related to Continuing Operations		54			33			88			58
Net Income from Continuing Operations		95			76			157			104
(Loss) Income from Discontinued Operations, Net of Income Taxes		(1	)		(130	)		1			(122	)
Net Income (Loss)		94			(54	)		158			(18	)
Retained Earnings at Beginning of Period		1,062			1,244			1,059			1,268
Dividends paid on common stock (Note 15)		(61	)		(60	)		(122	)		(120	)
Retained Earnings at End of Period	$	1,095		$	1,130		$	1,095		$	1,130
Basic and Diluted Share Information
Weighted average shares outstanding (millions)		226			223			226			223
Earnings per share of common stock from Continuing Operations	$	0.42		$	0.34		$	0.69		$	0.47
(Loss) earnings per share of common stock from Discontinued Operations		—			(0.58	)		0.01			(0.55	)
Basic and diluted earnings (loss) per share	$	0.42		$	(0.24	)	$	0.70		$	(0.08	)

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

2

PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)

	Three Months Ended June  30,						Six Months Ended June  30,
	2011			2010			2011			2010
	(millions of dollars)
Net Income (Loss)	$	94		$	(54	)	$	158		$	(18	)
Other Comprehensive Income (Loss) from Continuing Operations
Gain (losses) from continuing operations on commodity derivatives designated as cash flow hedges:
Gains (losses) arising during period		3			12			2			(78	)
Amount of losses reclassified into income		19			38			46			87
Net gains on commodity derivatives		22			50			48			9
Losses on treasury rate locks reclassified into income		—			2			—			3
Amortization of (gains) losses for prior service costs		(5	)		4			(4	)		4
Other comprehensive income from continuing operations, before income taxes		17			56			44			16
Income tax expense related to other comprehensive income from continuing operations		7			23			18			7
Other comprehensive income from continuing operations, net of income taxes		10			33			26			9
Other Comprehensive Income from Discontinued Operations, Net of Income Taxes		—			113			—			71
Comprehensive Income	$	104		$	92		$	184		$	62

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, 2011			December 31, 2010
	(millions of dollars)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	58		$	20
Restricted cash equivalents		11			11
Accounts receivable, less allowance for uncollectible accounts of $52 million and $51 million, respectively		958			1,027
Inventories		130			126
Derivative assets		22			45
Prepayments of income taxes		98			276
Deferred income tax assets, net		89			90
Prepaid expenses and other		128			51
Conectiv Energy assets held for sale		4			111
Total Current Assets		1,498			1,757
INVESTMENTS AND OTHER ASSETS
Goodwill		1,407			1,407
Regulatory assets		1,848			1,915
Investment in finance leases held in trust		1,329			1,423
Income taxes receivable		89			114
Restricted cash equivalents		9			5
Assets and accrued interest related to uncertain tax positions		9			11
Other		170			169
Conectiv Energy assets held for sale		1			6
Total Investments and Other Assets		4,862			5,050
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		12,431			12,120
Accumulated depreciation		(4,553	)		(4,447	)
Net Property, Plant and Equipment		7,878			7,673
TOTAL ASSETS	$	14,238		$	14,480

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

4

PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30, 2011			December 31, 2010
	(millions of dollars, except shares)
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Short-term debt	$	395		$	534
Current portion of long-term debt and project funding		111			75
Accounts payable and accrued liabilities		553			587
Capital lease obligations due within one year		8			8
Taxes accrued		143			96
Interest accrued		47			45
Liabilities and accrued interest related to uncertain tax positions		3			3
Derivative liabilities		47			66
Other		254			321
Liabilities associated with Conectiv Energy assets held for sale		3			62
Total Current Liabilities		1,564			1,797
DEFERRED CREDITS
Regulatory liabilities		525			528
Deferred income taxes, net		2,749			2,714
Investment tax credits		23			26
Pension benefit obligation		214			332
Other postretirement benefit obligations		412			429
Income taxes payable		—			2
Liabilities and accrued interest related to uncertain tax positions		41			148
Derivative liabilities		9			21
Other		180			175
Liabilities associated with Conectiv Energy assets held for sale		—			10
Total Deferred Credits		4,153			4,385
LONG-TERM LIABILITIES
Long-term debt		3,795			3,629
Transition bonds issued by ACE Funding		314			332
Long-term project funding		14			15
Capital lease obligations		82			86
Total Long-Term Liabilities		4,205			4,062
COMMITMENTS AND CONTINGENCIES (NOTE 15)
EQUITY
Common stock, $.01 par value – authorized 400,000,000 shares, 226,314,924 and 225,082,252 shares outstanding, respectively		2			2
Premium on stock and other capital contributions		3,299			3,275
Accumulated other comprehensive loss		(80	)		(106	)
Retained earnings		1,095			1,059
Total Shareholders’ Equity		4,316			4,230
Non-controlling interest		—			6
Total Equity		4,316			4,236
TOTAL LIABILITIES AND EQUITY	$	14,238		$	14,480

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

5

PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended June  30,
	2011			2010
	(millions of dollars)
OPERATING ACTIVITIES
Net income (loss)	$	158		$	(18	)
(Income) loss from discontinued operations		(1	)		122
Adjustments to reconcile net income (loss) to net cash from operating activities:
Depreciation and amortization		210			182
Non-cash rents from cross-border energy lease investments		(28	)		(26	)
Gain on early termination of finance leases held in trust		(39	)		—
Deferred income taxes		61			53
Other		(10	)		(7	)
Changes in:
Accounts receivable		63			(20	)
Inventories		(4	)		(6	)
Prepaid expenses		(34	)		(28	)
Regulatory assets and liabilities, net		(40	)		(105	)
Accounts payable and accrued liabilities		(71	)		74
Pension contributions		(110	)		—
Pension benefit obligation, excluding contributions		26			34
Cash collateral related to derivative activities		44			4
Taxes accrued		34			50
Other assets and liabilities		33			50
Conectiv Energy net assets held for sale		42			140
Net Cash From Operating Activities		334			499
INVESTING ACTIVITIES
Investment in property, plant and equipment		(387	)		(364	)
Department of Energy capital reimbursement awards received		16			—
Proceeds from early termination of finance leases held in trust		161			—
Changes in restricted cash equivalents		(3	)		3
Net other investing activities		(7	)		(1	)
Investment in property, plant and equipment associated with Conectiv Energy assets held for sale		—			(111	)
Net Cash Used By Investing Activities		(220	)		(473	)
FINANCING ACTIVITIES
Dividends paid on common stock		(122	)		(120	)
Common stock issued for the Dividend Reinvestment Plan and employee-related compensation		25			25
Redemption of preferred stock of subsidiaries		(6	)		—
Issuances of long-term debt		235			102
Reacquisition of long-term debt		(52	)		(482	)
(Repayments) issuances of short-term debt, net		(139	)		458
Cost of issuances		(2	)		(7	)
Net other financing activities		(16	)		(18	)
Net financing activities associated with Conectiv Energy assets held for sale		—			6
Net Cash Used By Financing Activities		(77	)		(36	)
Net Increase (Decrease) in Cash and Cash Equivalents		37			(10	)
Cash and Cash Equivalents at Beginning of Period		21			44
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	58		$	34
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash received for income taxes, net	$	2		$	1

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

6

PEPCO HOLDINGS

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

PEPCO HOLDINGS, INC.

(1) ORGANIZATION

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

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

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

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

PHI and each of its utility subsidiaries is registered and files periodic reports with the Securities and Exchange Commission (SEC) under the Securities Exchange Act of 1934, as amended. Together the three utilities constitute a single segment for financial reporting purposes.

Through Pepco Energy Services, Inc. and its subsidiaries (collectively, Pepco Energy Services), PHI provides energy savings performance contracting services, primarily to commercial, industrial and government customers. Pepco Energy Services is in the process of winding down its competitive electricity and natural gas retail supply business. Pepco Energy Services constitutes a separate segment for financial reporting purposes.

PHI Service Company, a subsidiary service company of PHI, provides a variety of support services, including legal, accounting, treasury, tax, purchasing and information technology services to PHI and its operating subsidiaries. These services are provided pursuant to a service agreement among PHI, PHI Service Company, and the participating operating subsidiaries. The expenses of the PHI Service Company are charged to PHI and the participating operating subsidiaries in accordance with cost allocation methodologies set forth in the service agreement.

Power Delivery

Pepco, DPL and ACE are each regulated public utilities in the jurisdictions that comprise its service territory. Each utility owns and operates a network of wires, substations and other equipment that is classified as transmission facilities, distribution facilities or common facilities (which are used for both transmission and distribution). Transmission facilities are high-voltage systems that carry wholesale electricity into, or across, the utility’s service territory. Distribution facilities are low-voltage systems that carry electricity to end-use customers in the utility’s service territory.

Each utility is responsible for the distribution of electricity, and in the case of DPL, natural gas, in its service territory for which it is paid tariff rates established by the applicable local public service commissions. Each company also supplies electricity at regulated rates to retail customers in its service territory who do not elect to purchase electricity from a competitive energy supplier. The regulatory term for this supply service is Standard Office Service in Delaware, the District of Columbia and Maryland, and Basic Generation Service in New Jersey. In these Notes to the Consolidated Financial Statements, these supply service obligations are referred to generally as Default Electricity Supply.

7

PEPCO HOLDINGS

Pepco Energy Services

Pepco Energy Services is engaged in the following businesses:

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

• providing energy efficiency services principally to federal, state and local government customers, and designing, constructing and operating combined heat and power and central energy plants, and

• providing high voltage electric construction and maintenance services to customers throughout the United States and low voltage electric construction and maintenance services and streetlight construction and asset management services to utilities, municipalities and other customers in the Washington, D.C. metropolitan area.

Pepco Energy Services also owns and operates two oil-fired generation facilities that are scheduled for deactivation in May 2012.

In December 2009, PHI announced the wind down of the retail energy supply component of the Pepco Energy Services business. Pepco Energy Services is implementing this wind down by not entering into any new supply contracts, while continuing to perform under its existing supply contracts through their expiration dates. The retail energy supply business has historically generated a substantial portion of the operating revenues and net income of the Pepco Energy Services segment. Operating revenues related to the retail energy supply business for the three months ended June 30, 2011 and 2010 were $231 million and $401 million, respectively, while operating income for the same periods was $4 million and $10 million, respectively. Operating revenues related to the retail energy supply business for the six months ended June 30, 2011 and 2010 were $536 million and $898 million, respectively, while operating income for the same periods was $16 million and $31 million, respectively.

In connection with the operation of the retail energy supply business, Pepco Energy Services provided letters of credit of $62 million and posted cash collateral of $76 million as of June 30, 2011. These collateral requirements, which are based on existing wholesale energy purchase and sale contracts and current market prices, will decrease as the contracts expire, with the collateral expected to be fully released by June 1, 2014. The energy services business will not be affected by the wind down of the retail energy supply business.

Other Business Operations

Through its subsidiary Potomac Capital Investment Corporation (PCI), PHI maintains a portfolio of cross-border energy lease investments. This activity constitutes a third operating segment for financial reporting purposes, which is designated as “Other Non-Regulated.” For a discussion of PHI’s cross-border energy lease investments, see Note (7), “Leasing Activities,” and Note (15), “Commitments and Contingencies – Regulatory and Other Matters – PHI’s Cross-Border Energy Lease Investments.”

Discontinued Operations

In April 2010, the Board of Directors of PHI approved a plan for the disposition of PHI’s competitive wholesale power generation business conducted through subsidiaries of Conectiv Energy Holding Company (Conectiv Energy). On July 1, 2010, PHI completed the sale of Conectiv Energy’s wholesale power generation business to Calpine Corporation (Calpine) for $1.64 billion. The disposition of all of Conectiv Energy’s remaining assets and businesses, consisting of its load service supply contracts, energy hedging portfolio, certain tolling agreements and other assets not included in the Calpine sale, is substantially complete. The operations of Conectiv Energy are being accounted for as a discontinued operation and no longer constitute a separate segment for financial reporting purposes. Substantially all of the information in these Notes to the Consolidated Financial Statements with respect to the operations of the former Conectiv Energy segment has been consolidated in Note (16), “Discontinued Operations.”

8

PEPCO HOLDINGS

(2) SIGNIFICANT ACCOUNTING POLICIES

Financial Statement Presentation

Pepco Holdings’ unaudited Consolidated Financial Statements are prepared in conformity with accounting principles generally accepted in the United States of America (GAAP). Pursuant to the rules and regulations of the Securities and Exchange Commission, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been omitted. Therefore, these financial statements should be read along with the annual financial statements included in PHI’s Annual Report on Form 10-K for the year ended December 31, 2010. In the opinion of PHI’s management, the Consolidated Financial Statements contain all adjustments (which all are of a normal recurring nature) necessary to present fairly Pepco Holdings’ financial condition as of June 30, 2011, in accordance with GAAP. The year-end December 31, 2010 Consolidated Balance Sheet was derived from audited financial statements, but does not include all disclosures required by GAAP. Interim results for the three and six months ended June 30, 2011 may not be indicative of PHI’s results that will be realized for the full year ending December 31, 2011, since its Power Delivery business and the retail energy supply business of Pepco Energy Services are seasonal.

Use of Estimates

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

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

Network Service Transmission Rates

In May 2011, PHI’s utility subsidiaries filed their network service transmission rates with the Federal Energy Regulatory Commission to be effective for the service year beginning June 1, 2011. The new rates include an adjustment for costs incurred in the service year ended May 31, 2011 that were not reflected in the rates charged to customers for that service year. In the second quarter of 2011, PHI’s utility subsidiaries recorded a $3 million decrease in transmission revenues as a change to the estimates recorded in previous periods primarily due to a decrease in actual rate base versus estimated rate base.

General and Auto Liability

During the second quarter of 2011, PHI’s utility subsidiaries reduced their self-insurance reserves for general and auto liability claims by approximately $4 million, based on obtaining an actuarial estimate of the unpaid loss attributed to general and auto liability claims for each of PHI’s utility subsidiaries at June 30, 2011.

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Consolidation of Variable Interest Entities

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

ACE Power Purchase Agreements

PHI, through its ACE subsidiary, is a party to three power purchase agreements (PPAs) with unaffiliated, non-utility generators (NUGs). PHI was unable to obtain sufficient information to determine whether these three entities were variable interest entities or if ACE was the primary beneficiary and as a result has applied the scope exemption from the consolidation guidance for enterprises that have not been able to obtain such information.

Net purchase activities with the NUGs for the three months ended June 30, 2011 and 2010, were approximately $55 million and $67 million, respectively, of which approximately $51 million and $62 million, respectively, consisted of power purchases under the PPAs. Net purchase activities with the NUGs for the six months ended June 30, 2011 and 2010, were approximately $112 million and $140 million, respectively, of which approximately $104 million and $129 million, respectively, consisted of power purchases under the PPAs. The power purchase costs are recoverable from ACE’s customers through regulated rates.

DPL Renewable Energy Transactions

PHI, through its DPL subsidiary, has entered into three land-based wind PPAs and one offshore wind PPA in the aggregate amount of 350 megawatts as of June 30, 2011 and one solar PPA with a 10 megawatt facility. As the wind facilities become operational, DPL is obligated to purchase energy and renewable energy credits (RECs) in amounts generated and delivered by the facilities at rates that are primarily fixed under these agreements. Under one of the PPAs, DPL is also obligated to purchase the capacity associated with the facility at rates that are generally fixed. If a wind facility does not become operational by a specified date, DPL has the right to terminate that PPA.

One of the land-based facilities is operational and DPL is obligated to purchase energy and RECs from this facility through 2024 in amounts not to exceed 50.25 megawatts. The other two land-based wind agreements each have a 20-year term and are currently expected to become operational during 2011. DPL’s purchases under the operational wind PPAs totaled $4 million and $3 million for the three months ended June 30, 2011 and 2010, respectively, and $9 million and $6 million for the six months ended June 30, 2011 and 2010, respectively. In July 2011, the Delaware Public Service Commission (DPSC) approved amendments to one of the land-based wind PPAs to change the location of the facility and to reduce the maximum generation capacity from 60 megawatts to 38 megawatts.

The offshore wind PPA is expected to become operational during 2016. If the offshore wind facility developer is unable to obtain all necessary permits and financing commitments, this could result in delays in the construction schedule and the operational start date of the offshore wind facility.

The term of the agreement with the solar facility is 20 years and DPL is obligated to purchase RECs in an amount up to 70 percent of the energy output at a fixed price once the facility is operational, which is expected to be in the third quarter of 2011.

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

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Atlantic City Electric Transitional Funding LLC

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

ACE Standard Offer Capacity Agreements

On April 28, 2011, ACE entered into three Standard Offer Capacity Agreements (SOCAs) by order of the NJBPU, each with a different generation company. The SOCAs were established under a New Jersey law enacted to promote the construction of qualified electric generation facilities in New Jersey. The SOCAs are 15-year, financially settled transactions approved by the NJBPU that allow generators to receive payments from, or make payments to, ACE based on the difference between the fixed price in the SOCAs and the price for capacity that clears PJM Interconnection, LLC (PJM). Each of the other electricity distribution companies (EDCs) in New Jersey has entered into SOCAs having the same terms with the same generation companies. The annual share of payments or receipts for ACE and the other EDCs is based upon each company’s annual proportion of the total New Jersey load attributable to all EDCs. ACE and the other EDCs entered the SOCAs under protest based on concerns about the potential cost to distribution customers. On May 16, 2011, the NJBPU denied a joint motion for reconsideration of its order requiring each of the EDCs to enter into the SOCAs. On June 24, 2011, ACE and the other EDCs filed appeals from the NJBPU orders with the Appellate Division of the New Jersey Superior Court.

The SOCAs are associated with the construction of three distinct combined cycle, natural gas generation facilities with an aggregate capacity of 1,949 megawatts of which ACE’s share would be approximately 15 percent, or 292 megawatts. The obligation to make payments is conditioned upon the clearance of capacity from a generation facility through PJM, and the earliest capacity auction would be in May 2012 based upon the estimated June 1, 2015 operational date for two of the facilities followed by a capacity auction in May 2013 for the third facility that has an estimated June 1, 2016 operational date. Payments would begin after a facility is operational. The NJBPU has approved full recovery from distribution customers of payments made by ACE and the other EDCs, and distribution customers would be entitled to any payments received by ACE and the other EDCs.

Currently, PHI believes that FASB guidance on derivative accounting and the accounting for regulated operations would apply to a SOCA once capacity has cleared a PJM auction. Once cleared, the gain (loss) associated with the fair value of a derivative would be offset by the establishment of a regulatory liability (asset).

Goodwill

Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired at the acquisition date. Substantially all of Pepco Holdings’ goodwill was generated by Pepco’s acquisition of Conectiv in 2002 and is allocated entirely to Pepco Holdings’ Power Delivery reporting unit for

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purposes of impairment testing based on the aggregation of its components. Pepco Holdings tests its goodwill for impairment annually as of November 1 and whenever an event occurs or circumstances change in the interim that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Factors that may result in an interim impairment test include, but are not limited to: a change in the identified reporting units; an adverse change in business conditions; a decline in PHI’s stock price causing market capitalization to fall further below book value; an adverse regulatory action; or an impairment of long-lived assets in the reporting unit. PHI concluded that an interim impairment test was not required during the three months ended June 30, 2011 as described in Note (6), “Goodwill.”

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in Pepco Holdings’ gross revenues were $94 million and $88 million for the three months ended June 30, 2011 and 2010, respectively, and $190 million and $162 million for the six months ended June 30, 2011 and 2010, respectively.

Reclassifications and Adjustments

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

DPL Default Electricity Supply Revenue and Costs Adjustments

During the second quarter of 2011, DPL recorded adjustments to correct certain errors associated with the accounting for Default Electricity Supply revenue and costs. These adjustments primarily arose from the under-recognition of allowed returns on the cost of working capital and resulted in a pre-tax decrease in “Other operation and maintenance” expense of $8 million.

Pepco Energy Services Derivative Accounting Adjustments

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

Income Tax Adjustments

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

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.

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(3)NEWLY ADOPTED ACCOUNTING STANDARDS

Fair Value Measurements and Disclosures (ASC 820)

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

Goodwill (ASC 350)

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

Revenue Recognition (ASC 605)

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

(4)RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Fair Value Measurements and Disclosures (ASC 820)

In May 2011, the FASB issued new guidance on fair value measurement and disclosures that will be effective beginning with PHI’s March 31, 2012 financial statements. The new guidance would change how fair value is measured in specific instances and expand disclosures about fair value measurements. PHI is evaluating the impact of this new guidance on its financial statements.

Comprehensive Income (ASC 220)

In June 2011, the FASB issued new guidance that requires entities to report comprehensive income in one of two ways: (i) one single continuous statement that combines the income statement with the statement of other comprehensive income and totals to a comprehensive income amount; or (ii) in two separate but consecutive statements of income and other comprehensive income. PHI already applies the second option in its financial statements, so PHI expects that the guidance will have minimal impact. The new guidance is effective beginning with PHI’s March 31, 2012 financial statements.

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(5) SEGMENT INFORMATION

Pepco Holdings’ management has identified its operating segments at June 30, 2011 as Power Delivery, Pepco Energy Services and Other Non-Regulated. In the tables below, the Corporate and Other column is included to reconcile the segment data with consolidated data and includes unallocated Pepco Holdings’ (parent company) capital costs, such as acquisition financing costs. Segment financial information for continuing operations for the three and six months ended June 30, 2011 and 2010 is as follows:

	Three Months Ended June 30, 2011
	(millions of dollars)
	Power Delivery		Pepco Energy Services		Other Non- Regulated			Corporate and Other  (a)			PHI Consolidated
Operating Revenue	$	1,093	$	308	$	14		$	(6	)	$	1,409
Operating Expenses (b)		957		295		(38	)(c)		(7	)		1,207
Operating Income		136		13		52			1			202
Interest Income		—		—		1			(1	)		—
Interest Expense		52		1		4			6			63
Other Income		8		1		—			1			10
Income Tax Expense (Benefit) (d)		20		5		30			(1	)		54
Net Income (Loss) from Continuing Operations		72		8		19	(c)		(4	)		95
Total Assets (excluding Assets Held For sale)		10,803		615		1,461			1,354			14,233
Construction Expenditures	$	204	$	6	$	—		$	6		$	216

(a) Total Assets in this column includes Pepco Holdings’ goodwill balance of $1.4 billion, all of which is allocated to the Power Delivery segment for purposes of assessing impairment. Total assets also include capital expenditures related to certain hardware and software expenditures which primarily benefit the Power Delivery business. These expenditures are recorded as incurred in the Corporate and Other segment and are allocated to Power Delivery once the assets are placed in service. Additionally, Corporate and Other includes intercompany amounts of $(6) million for Operating Revenue, $(4) million for Operating Expense, $(5) million for Interest Income and $(5) million for Interest Expense.

(b) Includes depreciation and amortization of $105 million, consisting of $97 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 $39 million pre-tax ($3 million after-tax) gain from the early termination of finance leases held in trust.

(d) Includes tax benefits of $14 million for Power Delivery primarily associated with an interest benefit related to federal tax liabilities and a $22 million reversal of previously recognized tax benefits for Other Non-Regulated associated with the early termination of finance leases held in trust.

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	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 in this column includes Pepco Holdings’ goodwill balance of $1.4 billion, all of which is allocated to the Power Delivery segment for purposes of assessing impairment. Total assets also include capital expenditures related to certain hardware and software expenditures which primarily benefit the Power Delivery business. These expenditures are recorded as incurred in the Corporate and Other segment and are allocated to Power Delivery once the assets are place in service. 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.

	Six Months Ended June 30, 2011
	(millions of dollars)
	Power Delivery		Pepco Energy Services		Other Non- Regulated			Corporate and Other  (a)			PHI Consolidated
Operating Revenue	$	2,342	$	681	$	28		$	(8	)	$	3,043
Operating Expenses (b)		2,088		652		(36	)(c)		(12	)		2,692
Operating Income		254		29		64			4			351
Interest Income		—		—		2			(2	)		—
Interest Expense		102		2		7			14			125
Other Income (Expenses)		16		2		(1	)		2			19
Preferred Stock Dividends		—		—		1			(1	)		—
Income Tax Expense (Benefit) (d)		49		11		32			(4	)		88
Net Income (Loss) from Continuing Operations		119		18		25	(c)		(5	)		157
Total Assets (excluding Assets Held For Sale)		10,803		615		1,461			1,354			14,233
Construction Expenditures	$	364	$	7	$	—		$	16		$	387

(a) Total Assets in this column includes Pepco Holdings’ goodwill balance of $1.4 billion, all of which is allocated to the Power Delivery segment for purposes of assessing impairment. Total assets also include capital expenditures related to certain hardware and software expenditures which primarily benefit the Power Delivery business. These expenditures are recorded as incurred in the Corporate and Other segment and are allocated to Power Delivery once the assets are placed in service. Additionally, Corporate and Other includes intercompany amounts of $(8) million for Operating Revenue, $(6) million for Operating Expense, $(10) million for Interest Income, $(9) million for Interest Expense, and $(1) million for Preferred Stock Dividends.

(b) Includes depreciation and amortization of $210 million, consisting of $194 million for Power Delivery, $9 million for Pepco Energy Services, $1 million for Other Non-Regulated, and $6 million for Corporate and Other.

(c) Includes $39 million pre-tax ($3 million after-tax) gain from the early termination of finance leases held in trust.

(d) Includes tax benefits of $14 million for Power Delivery primarily associated with an interest benefit related to federal tax liabilities and a $22 million reversal of previously recognized tax benefits for Other Non-Regulated associated with the early termination of finance leases held in trust.

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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 (Expenses)		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 in this column includes Pepco Holdings’ goodwill balance of $1.4 billion, all of which is allocated to the Power Delivery segment for purposes of assessing impairment. Total assets also include capital expenditures related to certain hardware and software expenditures which primarily benefit the Power Delivery business. These expenditures are recorded as incurred in the Corporate and Other segment and are allocated to Power Delivery once the assets are placed in service. Additionally, Corporate and Other includes intercompany amounts of $(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.

(6) GOODWILL

PHI’s goodwill balance of $1.4 billion was unchanged during the three and six months ended June 30, 2011. Substantially all of PHI’s goodwill was generated by Pepco’s acquisition of Conectiv in 2002 and is allocated entirely to the Power Delivery reporting unit based on the aggregation of its regulated public utility company components for purposes of assessing impairment under FASB guidance on goodwill and other intangibles (ASC 350).

PHI’s annual impairment test as of November 1, 2010 indicated that goodwill was not impaired. As of June 30, 2011, PHI concluded that there were no events requiring it to perform an interim goodwill impairment test. PHI will continue to monitor for indicators of goodwill impairment.

(7) LEASING ACTIVITIES

Investment in Finance Leases Held in Trust

PHI has a portfolio of cross-border energy lease investments (the lease portfolio) consisting of hydroelectric generation facilities, coal-fired electric generation facilities and natural gas distribution networks located outside of the United States. Each lease investment is comprised of a number of leases as of June 30, 2011 and December 31, 2010, the lease portfolio consisted of seven investments with an aggregate book value of $1.3 billion and eight investments with an aggregate book value of $1.4 billion, respectively.

During the second quarter of 2011, PHI entered into early termination agreements with two lessees involving all of the leases comprising one of the eight lease investments and a small portion of the leases comprising a second lease investment. The early terminations of the leases were negotiated at the request of the lessees and

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were completed in June 2011. PHI received net cash proceeds of $161 million (net of a termination payment of $423 million used to retire the non-recourse debt associated with the terminated leases) and recorded a pre-tax gain of $39 million, representing the excess of the net cash proceeds over the carrying value of the lease investments.

With respect to the terminated leases, PHI had previously made certain business assumptions regarding foreign investment opportunities available at the end of the full lease terms. Because the leases were terminated earlier than full term, management decided not to pursue these opportunities and certain income tax benefits recognized previously were reversed in the amount of $22 million. As part of the negotiations with the lessees, the company required an early termination payment sufficient to provide a gain on the early termination of the leases. The after-tax gain on the lease terminations was $3 million, reflecting an income tax provision at the statutory federal rate of $14 million and the income tax benefit reversal. PHI has no intent to terminate early any other leases in the lease portfolio. With respect to certain of these remaining leases, management’s assumption continues to be that the foreign earnings recognized at the end of the lease term will remain invested abroad.

The components of the cross-border energy lease investments at June 30, 2011 and at December 31, 2010 are summarized below:

	June 30, 2011			December 31, 2010
	(millions of dollars)
Scheduled lease payments to PHI, net of non-recourse debt	$	2,119		$	2,265
Less: Unearned and deferred income		(790	)		(842	)
Investment in finance leases held in trust		1,329			1,423
Less: Deferred income tax liabilities		(725	)		(816	)
Net investment in finance leases held in trust	$	604		$	607

Income recognized from cross-border energy lease investments, excluding the gain on the terminated leases discussed above, was comprised of the following for the three and six months ended June 30, 2011 and 2010:

	Three Months Ended June  30,				Six Months Ended June  30,
	2011		2010		2011		2010
	(millions of dollars)
Pre-tax income from PHI’s cross-border energy lease investments (included in “Other Revenue”)	$	14	$	13	$	28	$	26
Income tax expense related to cross-border energy lease investments		7		3		10		7
Net income from PHI’s cross-border energy lease investments	$	7	$	10	$	18	$	19

PHI regularly monitors the financial performance and condition of the lessees under its cross-border energy lease investments. Changes in credit quality are assessed to determine if they should be reflected in the carrying value of the leases. PHI reviews each lessee’s performance versus annual compliance requirements set by the terms and conditions of the leases. This includes a comparison of published credit ratings to minimum credit rating requirements in the leases for lessees with public credit ratings. In addition, PHI routinely meets with senior executives of the lessees to discuss the lessee company and asset performance. If the annual compliance requirements or minimum credit ratings are not met, remedies are available under the leases. PHI believes that all lessees were in compliance with the terms and conditions of their lease agreements at June 30, 2011.

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The table below shows PHI’s net investment in these leases by the published credit ratings of the lessees as of June 30, 2011 and December 31, 2010:

Lessee Rating (a)	June 30, 2011		December 31, 2010
	(millions of dollars)
Rated Entities
AA/Aa and above	$	723	$	709
A		438		549
Total		1,161		1,258
Non Rated Entities		168		165
Total	$	1,329	$	1,423

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

(8) PENSION AND OTHER POSTRETIREMENT BENEFITS

The following Pepco Holdings information is for the three months ended June 30, 2011 and 2010:

	Pension Benefits						Other Postretirement Benefits
	2011			2010			2011			2010
	(millions of dollars)
Service cost	$	7		$	7		$	1		$	1
Interest cost		27			25			9			9
Expected return on plan assets		(33	)		(25	)		(4	)		(4	)
Amortization of prior service cost		(1	)		—			(1	)		(1	)
Amortization of net actuarial loss		11			10			2			3
Plan amendment		—			1			—			—
Termination benefits		—			—			1			5
Net periodic benefit cost	$	11		$	18		$	8		$	13

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The following Pepco Holdings information is for the six months ended June 30, 2011 and 2010:

	Pension Benefits						Other Postretirement Benefits
	2011			2010			2011			2010
	(millions of dollars)
Service cost	$	17		$	18		$	3		$	3
Interest cost		53			55			18			19
Expected return on plan assets		(64	)		(58	)		(9	)		(8	)
Amortization of prior service cost		(1	)		—			(2	)		(2	)
Amortization of net actuarial loss		24			21			6			6
Plan amendment		—			1			—			—
Termination benefits		—			—			1			5
Net periodic benefit cost	$	29		$	37		$	17		$	23

Pension and Other Postretirement Benefits

Net periodic benefit cost related to continuing operations is included in “Other operation and maintenance” expense, net of the portion of the net periodic benefit cost that is capitalized as part of the cost of labor for internal construction projects. PHI’s pension and other postretirement net periodic benefits cost for the three and six months ended June 30, 2010, includes one-time charges in the aggregate amount of $6 million related to the 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 related to continuing operations.

Pension Contributions

PHI’s funding policy with regard to PHI’s non-contributory retirement plan (the PHI Retirement Plan) is to maintain a funding level that is at least equal to the funding target level under the Pension Protection Act of 2006. 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. Although PHI had no minimum funding requirement under the Pension Protection Act guidelines, Pepco, ACE and DPL, in the first quarter of 2011, made discretionary tax-deductible contributions to the PHI Retirement Plan in the amounts of $40 million, $30 million and $40 million, respectively. The $110 million in contributions brought the PHI Retirement Plan assets to the funding target level for 2011 under the Pension Protection Act. During 2010, PHI Service Company made discretionary tax-deductible contributions totaling $100 million to the PHI Retirement Plan, which brought plan assets to the funding target level for 2010 under the Pension Protection Act. Pepco, ACE and DPL did not make contributions to the PHI Retirement Plan in 2010.

Benefit Plan Modifications Subsequent to June 30, 2011

On July 28, 2011, PHI’s Board of Directors approved revisions to certain of PHI’s existing benefit programs, including the PHI Retirement Plan. The changes to the PHI Retirement Plan were effected by PHI in order to establish a more unified approach to PHI’s retirement programs and to further align the benefits offered under PHI’s retirement programs. The changes to the PHI Retirement Plan will be effective on or after January 1, 2012 and will affect the retirement benefits payable to approximately 750 of PHI’s employees. All full time employees of PHI and certain subsidiaries are eligible to participate in the PHI Retirement Plan. Retirement benefits for all other employees remain unchanged.

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On July 28, 2011, PHI’s Board also approved a new, non-tax-qualified Supplemental Executive Retirement Plan (SERP) which will replace PHI’s two pre-existing supplemental retirement plans, effective August 1, 2011. Following the effective date of the SERP, pursuant to amendments to such plans, the Conectiv SERP Plan and the PHI Combined SERP Plan will be closed to new participants. The establishment of the new SERP is consistent with PHI’s efforts to align retirement benefits for PHI and its subsidiaries with current market practices and to provide similarly situated participants with retirement benefits that are the same or similar in value as compared to the benefits provided under the existing SERPs.

PHI does not believe that the benefit plan modifications will have a material impact on its overall financial condition, results of operations, or cash flows.

(9) DEBT

Credit Facilities

The principal credit source for PHI and its utility subsidiaries is an unsecured $1.5 billion syndicated credit facility, which can be used to borrow funds, obtain letters of credit and support the issuance of commercial paper. As of June 30, 2011, PHI’s credit limit under the facility was $875 million and the credit limit for each of Pepco, DPL and ACE was the lesser of $500 million and the maximum amount of debt each company was permitted to have outstanding by its regulatory authorities, except that the aggregate amount of credit used by Pepco, DPL and ACE collectively, at any given time, could not exceed $625 million. On August 1, 2011, PHI, Pepco, DPL and ACE entered into an amendment and restatement of the credit agreement with respect to the facility, which among other changes extends the expiration date of the facility from May 2, 2012, to August 1, 2016. The facility, as amended and restated is more fully described below under the heading “Financing Activities Subsequent to June 30, 2011.” PHI also has two bi-lateral 364 day unsecured credit agreements totaling $200 million. Under each of the credit agreements, PHI has access to revolving and floating rate loans over the terms of the agreements. Neither agreement provides for the issuance of letters of credit. Both agreements expire on October 26, 2011.

The absence of a material adverse change in PHI’s business, property and results of operations or financial condition is not a condition to the availability of credit under the $1.5 billion credit facility or either of the bi-lateral credit agreements. Neither the credit facility nor the bi-lateral credit agreements include any rating triggers.

The $1.5 billion credit facility and the two bi-lateral credit agreements are referred to herein collectively as PHI’s “primary credit facilities.” As of June 30, 2011, each borrower was in compliance with its covenants under the primary credit facilities to which it is a party.

At June 30, 2011 and December 31, 2010, the amount of cash plus unused borrowing capacity under the primary credit facilities available to meet the future liquidity needs of PHI and its utility subsidiaries on a consolidated basis totaled $1.4 billion and $1.2 billion, respectively. PHI’s utility subsidiaries had combined cash and unused borrowing capacity under the $1.5 billion credit facility of $595 million and $462 million at June 30, 2011 and December 31, 2010, respectively.

Financing Activities

In April 2011, ACE Funding made principal payments of $6 million on its Series 2002-1 Bonds, Class A-3, and $2 million on its Series 2003-1 Bonds, Class A-2.

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

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On June 1, 2011, DPL resold approximately $35 million of 0.75% Delaware Economic Development Authority tax-exempt bonds due May 1, 2026. The bonds were originally issued for the benefit of DPL in 2001 and were purchased by DPL on May 2, 2011 pursuant to a mandatory repurchase obligation triggered by the expiration of the original interest period for the bonds. The bonds are subject to mandatory purchase by DPL on June 1, 2012.

Financing Activities Subsequent to June 30, 2011

In July 2011, ACE Funding made principal payments of $6 million on its Series 2002-1 Bonds, Class A-2 and A-3, and $2 million on its Series 2003-1 Bonds, Class A-2.

On August 1, 2011, PHI, Pepco, DPL and ACE entered into an amendment and restatement of their $1.5 billion credit facility to extend the expiration date to August 1, 2016, and to make various other changes. As amended and restated, all or any portion of the facility may be used to obtain revolving loans and up to $500 million may be used to obtain letters of credit. PHI’s credit sublimit under the facility is $750 million and the sublimit of each of Pepco, DPL and ACE is $250 million. The borrowers may increase or decrease their respective sublimits during the term of the facility, except that (i) the sum of all of the borrower sublimits following any such increase or decrease must equal the total amount of the facility and (ii) the aggregate amount of credit used at any given time by (a) PHI may not exceed $1.25 billion and (b) each of Pepco, DPL or ACE may not exceed the lesser of $500 million and the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of sublimit reallocations cannot exceed eight per fiscal year during the term of the agreement.

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, the federal funds effective rate plus 0.5% and one month LIBOR plus 1.0%, 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 10% of the total amount of the facility. Any swingline loan must be repaid by the borrower within fourteen days of receipt thereof. All indebtedness incurred under the facility is unsecured.

Collateral Requirements of Pepco Energy Services

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

During periods of declining energy prices, Pepco Energy Services has been exposed to the asymmetrical risk of having to post collateral under its wholesale purchase contracts without receiving a corresponding amount of collateral from its retail customers. To partially address these asymmetrical collateral obligations, Pepco Energy Services, in the first quarter of 2009, entered into a credit intermediation arrangement with Morgan Stanley Capital Group, Inc. (MSCG). Under this arrangement, MSCG, in consideration for the payment to MSCG of certain fees, (i) assumed, by novation, the electricity purchase obligations of Pepco Energy Services in years 2009 through 2011 under several wholesale purchase contracts, and (ii) agreed to supply electricity to Pepco Energy Services on the same terms as the novated transactions, but without imposing on Pepco Energy Services any obligation to post collateral based on changes in electricity prices. The upfront fees incurred by Pepco Energy Services in 2009 in the amount of $25 million are being amortized into expense in declining amounts over the life of the arrangement based on the fair value of the underlying contracts at the time of the novation. For the three months ended June 30, 2011 and 2010, Pepco Energy Services recognized less than $1 million and approximately $3 million, respectively, of the fees in “Interest expense.” For the six months ended June 30, 2011 and 2010, Pepco Energy Services recognized less than $1 million and approximately $5 million, respectively, of the fees in “Interest expense.”

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As of June 30, 2011, Pepco Energy Services had posted net cash collateral of $76 million and provided letters of credit of $62 million. At December 31, 2010, Pepco Energy Services had posted net cash collateral of $117 million and provided letters of credit of $113 million. As its retail energy supply business is wound down, Pepco Energy Services’ collateral requirements will be further reduced.

At June 30, 2011 and December 31, 2010, the aggregate amount of cash plus unused borrowing capacity under the credit facilities available to meet the combined future liquidity needs of Pepco Energy Services totaled $827 million and $728 million, respectively.

(10) INCOME TAXES

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

	Three Months Ended June 30,										Six Months Ended June 30,
	2011					2010					2011					2010
	(millions of dollars)
Income tax at federal statutory rate	$	52		35.0	%	$	38		35.0	%	$	86		35.0	%	$	57		35.0	%
Increases (decreases) resulting from:
State income taxes, net of federal effect		6		4.0			5		5.0			11		4.5			9		5.6
Depreciation		—		—			2		1.4			(1	)	(0.4	)		3		1.7
Cross-border energy lease investments		21		14.1			(1	)	(1.2	)		20		8.2			(2	)	(1.5	)
Change in estimates and interest related to uncertain and effectively settled tax positions		(17	)	(11.4	)		1		1.0			(15	)	(6.1	)		10		6.2
Tax credits		(1	)	(0.7	)		(1	)	(0.9	)		(2	)	(0.8	)		(2	)	(1.2	)
Medicare Part D subsidy		—		—			—		—			—		—			4		2.2
Release of valuation allowance		—		—			—		—			—		—			(8	)	(4.8	)
Change in state deferred tax balances as a result of corporate restructuring		—		—			(8	)	(7.8	)		—		—			(8	)	(5.2	)
State tax benefit related to prior years’ asset dispositions		(4	)	(2.7	)		—		—			(4	)	(1.6	)		—		—
Other, net		(3	)	(2.1	)		(3	)	(2.2	)		(7	)	(2.9	)		(5	)	(2.2	)
Consolidated income tax expense related to continuing operations	$	54		36.2	%	$	33		30.3	%	$	88		35.9	%	$	58		35.8	%

PHI’s consolidated effective tax rates from continuing operations for the three months ended June 30, 2011 and 2010 were 36.2% and 30.3%, respectively. The increase in the effective tax rate was primarily due to the impact of the early termination of certain cross border energy leases and the non-recurring tax benefit of the 2010 corporate restructuring. This increase was partially offset by interest benefits associated with the settlement with the Internal Revenue Service (IRS) discussed below (included in changes in estimates and interest related to uncertain and effectively settled tax positions) and a state tax benefit related to prior years’ asset dispositions.

As discussed further in Note (7), “Leasing Activities,” during the second quarter of 2011, PHI terminated early its interest in certain cross-border energy leases. As a result of the early terminations, PHI reversed $22 million of previously recognized income tax benefits associated with those leases which will not be realized due to the early termination.

In the second quarter of 2010, PHI recorded a non-recurring benefit related to the April 1, 2010 corporate restructuring. As a result of the restructuring, PHI recorded an $8 million decrease to its state deferred tax balances resulting from a change in state apportionment factors.

In the second quarter of 2011, PHI reached a settlement with the IRS with respect to interest due on its federal tax liabilities related to the November 2010 audit settlement for years 1996 through 2002. In connection with this agreement, PHI reallocated certain amounts that had been on deposit with the IRS since 2006 among liabilities in the settlement years and subsequent years. Primarily related to the settlement and reallocations, PHI has recorded an additional tax benefit in the amount of $17 million (after-tax). This additional interest income was recorded in the second quarter of 2011.

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Also in the second quarter of 2011, PHI received refunds of approximately $5 million and recorded tax benefits of approximately $4 million (after-tax) related to the filing of amended state tax returns. These amended returns reduced state taxable income due to an increase in tax basis reported on certain prior years’ asset dispositions.

PHI’s consolidated effective tax rates from continuing operations for the six months ended June 30, 2011 and 2010 were 35.9% and 35.8%, respectively. While the effective tax rate was substantially unchanged between the two periods, the rate was affected by several offsetting items.

The effective tax rate increased in 2011 as a result of the negative impact of the June 2011 early termination of certain cross-border energy leases of $22 million discussed above, however, this increase was substantially offset by the $17 million benefit PHI recorded during the six months ended June 30, 2011, primarily resulting from the settlement with the IRS on interest due on its 1996 through 2002 audit settlement also discussed above, and the $4 million state tax benefit related to prior years’ asset dispositions.

The 2010 effective tax rate included the non-recurring impact of the April 2010 corporate restructuring. As a result of this restructuring, PHI recorded approximately $16 million of non-recurring tax benefits in 2010 including approximately $8 million resulting from a change in state apportionment factors and the release of $8 million of valuation allowances on deferred tax assets related to state net operating losses.

The effective tax rate in 2010 was also affected by changes in estimates and interest related to uncertain and effectively settled tax positions, primarily consisting of a non-recurring $2 million reversal of accrued interest income on state income tax positions in 2010 that PHI concluded was no longer more likely than not to be realized and the reversal of $6 million of erroneously accrued interest income in 2010 on uncertain and effectively settled state income tax positions, as discussed in Note (2), “Significant Accounting Policies.” The 2010 rate was further affected by the change in taxation of the Medicare Part D subsidy that increased PHI’s effective tax rate for the six months ended June 30, 2010. This change increased PHI’s first quarter 2010 tax expense by $4 million, which was partially offset through a reduction in Operating Expenses resulting in a $2 million decrease to net income.

(11)NON-CONTROLLING INTEREST

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

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(12) EARNINGS PER SHARE

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

	Three Months Ended June 30,
	2011			2010
	(millions of dollars, except per share data)
Income (Numerator):
Net income from continuing operations	$	95		$	76
Net loss from discontinued operations		(1	)		(130	)
Net income (loss)	$	94		$	(54	)
Shares (Denominator) (in millions):
Weighted average shares outstanding for basic computation:
Average shares outstanding		226			223
Adjustment to shares outstanding		—			—
Weighted Average Shares Outstanding for Computation of Basic Earnings Per Share of Common Stock		226			223
Net effect of potentially dilutive shares (a)		—			—
Weighted Average Shares Outstanding for Computation of Diluted Earnings Per Share of Common Stock		226			223
Basic and diluted earnings per share of common stock from continuing operations	$	0.42		$	0.34
Basic and diluted loss per share of common stock from discontinued operations		—			(0.58	)
Basic and diluted earnings (loss) per share	$	0.42		$	(0.24	)

(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 was 14,900 and 280,266 for the three months ended June 30, 2011 and 2010, respectively.

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	For the Six  Months Ended June 30,
	2011		2010
	(millions of dollars, except per share data)
Income (Numerator):
Net income from continuing operations	$	157	$	104
Net income (loss) from discontinued operations		1		(122	)
Net income (loss)	$	158	$	(18	)
Shares (Denominator) (in millions):
Weighted average shares outstanding for basic computation:
Average shares outstanding		226		223
Adjustment to shares outstanding		—		—
Weighted Average Shares Outstanding for Computation of Basic Earnings Per Share of Common Stock		226		223
Net effect of potentially dilutive shares (a)		—		—
Weighted Average Shares Outstanding for Computation of Diluted Earnings Per Share of Common Stock		226		223
Basic and diluted earnings per share of common stock from continuing operations	$	0.69	$	0.47
Basic and diluted earnings (loss) per share of common stock from discontinued operations		0.01		(0.55	)
Basic and diluted earnings (loss) per share	$	0.70	$	(0.08	)

(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 was 119,766 and 280,266 for the six months ended June 30, 2011 and 2010, respectively.

(13) DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

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

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

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

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

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PHI also uses derivative instruments from time to time to mitigate the effects of fluctuating interest rates on debt issued in connection with the operation of their businesses. In June 2002, PHI entered into several treasury rate lock transactions in anticipation of the issuance of several series of fixed-rate debt commencing in August 2002. Upon issuance of the fixed-rate debt in August 2002, the treasury rate locks were terminated at a loss. The loss has been deferred in Accumulated Other Comprehensive Loss (AOCL) and is being recognized in income over the life of the debt issued as interest payments are made.

The tables below identify the balance sheet location and fair values of derivative instruments as of June 30, 2011 and December 31, 2010:

	As of June 30, 2011
Balance Sheet Caption	Derivatives Designated as Hedging Instruments			Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting			Net Derivative Instruments
	(millions of dollars)
Derivative Assets (current assets)	$	30		$	20		$	50		$	(28	)	$	22
Derivative Assets (non-current assets)		—			2			2			(2	)		—
Total Derivative Assets		30			22			52			(30	)		22
Derivative Liabilities (current liabilities)		(92	)		(38	)		(130	)		83			(47	)
Derivative Liabilities (non-current liabilities)		(24	)		(10	)		(34	)		25			(9	)
Total Derivative Liabilities		(116	)		(48	)		(164	)		108			(56	)
Net Derivative (Liability) Asset	$	(86	)	$	(26	)	$	(112	)	$	78		$	(34	)

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

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

	June  30, 2011		December 31, 2010
	(millions of dollars)
Cash collateral pledged to counterparties with the right to reclaim (a)	$	78	$	122

(a) Includes cash deposits on commodity brokerage accounts

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As of June 30, 2011 and December 31, 2010, all PHI cash collateral pledged related to derivative instruments accounted for at fair value was entitled to offset under master netting agreements.

Derivatives Designated as Hedging Instruments

Cash Flow Hedges

Pepco Energy Services

For energy commodity contracts that are designated and qualify as cash flow hedges, the effective portion of the gain or loss on the derivative is reported as a component of AOCL and is reclassified into income in the same period or periods during which the hedged transactions affect income. Gains and losses on the derivative, representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness, are recognized in income. Effective January 1, 2011, Pepco Energy Services elected to no longer apply cash flow hedge accounting to its natural gas derivatives. Amounts included in AOCL for natural gas cash flow hedges will be reflected in earnings as the hedge transactions are completed.

Cash flow hedge activity during the three and six months ended June 30, 2011 and 2010 is provided in the tables below:

	Three Months Ended June  30,					Six Months Ended June  30,
	2011		2010			2011		2010
	(millions of dollars)
Amount of net pre-tax gain (loss) arising during the period included in accumulated other comprehensive loss	$	3	$	12		$	2	$	(78	)
Amount of net pre-tax loss reclassified into income:
Effective portion:
Fuel and Purchased Energy		19		39			46		85
Ineffective portion: (a) (b)
Revenue		—		(1	)		—		2
Total net pre-tax loss reclassified into income		19		38			46		87
Net pre-tax gain on commodity derivatives included in accumulated other comprehensive loss	$	22	$	50		$	48	$	9

(a) For the three months ended June 30, 2011 and 2010, amounts of zero and less than $1 million, respectively, were reclassified from AOCL to income because the forecasted hedged transactions were deemed probable not to occur.

(b) For the six months ended June 30, 2011 and 2010, amounts of zero and less than $1 million, respectively, were reclassified from AOCL to income because the forecasted hedged transactions were deemed probable not to occur.

As of June 30, 2011 and December 31, 2010, Pepco Energy Services had the following types and quantities of outstanding energy commodity contracts employed as cash flow hedges of forecasted purchases and forecasted sales.

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	Quantities
Commodity	June 30, 2011		December 31, 2010
Forecasted Purchases Hedges
Natural gas (One Million British Thermal Units (MMBtu))		—		8,597,106
Electricity (Megawatt hours (MWh))		2,417,760		2,677,640
Electricity Capacity (MW-Days)		—		34,730
Forecasted Sales Hedges
Electricity (MWh)		1,356,480		2,517,200

Power Delivery

All premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all of DPL’s gains and losses related to hedging activities, are deferred under FASB guidance on regulated operations until recovered from customers through a fuel adjustment clause approved by the DPSC. The following table indicates the amounts of the net unrealized derivative gain (loss) deferred as a regulatory liability (regulatory asset) and the realized loss recognized in the Consolidated Statements of Income for the three and six months ended June 30, 2011 and 2010:

	Three Months  Ended June 30,						Six Months  Ended June 30,
	2011			2010			2011			2010
	(millions of dollars)						(millions of dollars)
Net Unrealized Gain Deferred as a Regulatory Liability (Asset)	$	2		$	5		$	3		$	—
Net Realized Loss Recognized in Fuel and Purchased Energy Expense		(1	)		(3	)		(3	)		(5	)

As of June 30, 2011 and December 31, 2010, DPL had the following outstanding commodity forward contracts that were entered into to hedge forecasted transactions:

	Quantities
Commodity	June 30, 2011		December 31, 2010
Forecasted Purchases Hedges
Natural Gas (MMBtu)		765,000		1,670,000

Cash Flow Hedges Included in Accumulated Other Comprehensive Loss

The tables below provide details regarding effective cash flow hedges included in PHI’s Consolidated Balance Sheet as of June 30, 2011 and 2010. Cash flow hedges are marked to market on the balance sheet with corresponding adjustments to AOCL. The data in the tables indicate the cumulative net loss after-tax related to effective cash flow hedges by contract type included in AOCL, the portion of AOCL expected to be reclassified to income during the next 12 months, and the maximum hedge or deferral term:

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	As of June 30, 2011				Maximum Term
Contracts	Accumulated Other Comprehensive Loss After-tax (a)		Portion Expected to be Reclassified to Income during the Next 12 Months
	(millions of dollars)
Energy Commodity (b)	$	49	$	35	35 months
Interest Rate		11		1	254 months
Total	$	60	$	36

(a) AOCL on PHI’s Consolidated Balance Sheet as of June 30, 2011, includes a $20 million balance related to minimum pension liability. This balance is not included in this table as the minimum pension liability is not a cash flow hedge.

(b) The unrealized derivative losses recorded in AOCL are largely offset by forecasted natural gas and electricity physical purchases for delivery to retail customers that are in gain positions and subject to accrual accounting. These forward purchase contracts are exempted from mark-to-market accounting because they either qualify as normal purchases under FASB guidance on derivatives and hedging or they are not derivative contracts. Under accrual accounting, no asset is recorded on the balance sheet for these contracts, and the purchase cost is not recognized until the period of distribution. Although Pepco Energy Services no longer designates its natural gas derivatives as cash flow hedges effective January 1, 2011, gains or losses previously deferred in AOCL as of December 31, 2010 would remain in AOCL unless it is probable that the hedged forecasted transaction will not occur. At June 30, 2011, the amount remaining in AOCL associated with natural gas derivatives was $41 million.

	As of June 30, 2010				Maximum Term
Contracts	Accumulated Other Comprehensive Loss After-tax (a)		Portion Expected to be Reclassified to Income during the Next 12 Months
	(millions of dollars)
Energy Commodity (b)	$	94	$	55	47 months
Interest Rate		20		3	266 months
Total	$	114	$	58

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

Other Derivative Activity

Pepco Energy Services

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

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For the three and six months ended June 30, 2011 and 2010, the amount of the derivative gain (loss) for Pepco Energy Services recognized in income is provided in the table below:

	Three Months Ended June 30, 2011								Three Months Ended June 30, 2010
	Revenue			Fuel and Purchased Energy Expense		Total			Revenue		Fuel and Purchased Energy Expense		Total
	(millions of dollars)
Realized mark-to-market gains (losses)	$	2		$	—	$	2		$	1	$	—	$	1
Unrealized mark-to-market gains (losses)		(5	)		—		(5	)		—		—		—
Total net mark-to-market gains (losses)	$	(3	)	$	—	$	(3	)	$	1	$	—	$	1

	Six Months Ended June 30, 2011								Six Months Ended June 30, 2010
	Revenue			Fuel and Purchased Energy Expense		Total			Revenue		Fuel and Purchased Energy Expense		Total
	(millions of dollars)
Realized mark-to-market gains (losses)	$	(2	)	$	—	$	(2	)	$	1	$	—	$	1
Unrealized mark-to-market gains (losses)		(5	)		—		(5	)		—		—		—
Total net mark-to-market gains (losses)	$	(7	)	$	—	$	(7	)	$	1	$	—	$	1

As of June 30, 2011 and December 31, 2010, Pepco Energy Services had the following net outstanding commodity forward contract quantities and net position on derivatives that did not qualify for hedge accounting:

	June 30, 2011			December 31, 2010
Commodity	Quantity		Net Position	Quantity		Net Position
Financial transmission rights (MWh)		619,226	Long		381,215	Long
Electric Capacity (MW–Days)		28,560	Long		2,265	Short
Electric (MWh)		1,106,232	Long		1,455,800	Short
Natural gas (MMBtu)		36,003,000	Long		45,889,486	Short

Power Delivery

DPL holds certain derivatives that are not in hedge accounting relationships nor are they designated as normal purchases or normal sales. These derivatives are recorded at fair value on the Consolidated Balance Sheets with the gain or loss for the change in fair value recorded in income. In accordance with FASB guidance on regulated operations, offsetting regulatory liabilities or regulatory assets are recorded on the Consolidated Balance Sheets and the recognition of the derivative gain or loss is deferred because of the DPSC-approved fuel adjustment clause. For the three and six months ended June 30, 2011 and 2010, the net amount of the unrealized derivative gain (loss) deferred as a regulatory liability (regulatory asset) and the net realized loss recognized in the Consolidated Statements of Income is provided in the table below:

	Three Months Ended June  30,						Six Months Ended June  30,
	2011			2010			2011			2010
	(millions of dollars)
Net Unrealized Gain (Loss) Deferred as a Regulatory Liability (Asset)	$	2		$	7		$	9		$	1
Net Realized Loss Recognized in Fuel and Purchased Energy Expense		(4	)		(6	)		(11	)		(13	)

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As of June 30, 2011 and December 31, 2010, DPL had the following net outstanding natural gas commodity forward contracts that did not qualify for hedge accounting:

	June 30, 2011			December 31, 2010
Commodity	Quantity		Net Position	Quantity		Net Position
Natural Gas (MMBtu)		5,892,432	Long		7,827,635	Long

Contingent Credit Risk Features

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

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

The gross fair value of PHI’s derivative liabilities, excluding the impact of offsetting transactions or collateral under master netting agreements, with credit risk-related contingent features on June 30, 2011 and December 31, 2010, was $90 million and $156 million, respectively, before giving effect to the impact of a credit rating downgrade that would increase these amounts or offsetting transactions that are encompassed within master netting agreements that would alter these amounts. As of those dates, PHI had not posted any cash collateral against the gross derivative liability. PHI’s net settlement amount in the event of a downgrade of PHI’s and DPL’s senior unsecured debt rating to below “investment grade” as of June 30, 2011 and December 31, 2010, would have been approximately $143 million and $176 million, respectively, after taking into consideration the master netting agreements. At June 30, 2011 and December 31, 2010, normal purchase and normal sale contracts in a loss position increased PHI’s obligation.

PHI’s primary sources for posting cash collateral or letters of credit are its credit facilities. At June 30, 2011 and December 31, 2010, the aggregate amount of cash plus borrowing capacity under the primary credit facilities available to meet the future liquidity needs of PHI and its subsidiaries totaled $1.4 billion and $1.2 billion, respectively, of which $827 million and $728 million, respectively, was available to Pepco Energy Services.

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(14) FAIR VALUE DISCLOSURES

Financial Instruments Measured at Fair Value on a Recurring Basis

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

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

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

PHI’s level 2 derivative instruments primarily consist of electricity derivatives at June 30, 2011. Level 2 power swaps are priced at liquid trading hub prices or valued using the liquid hub prices plus a congestion adder that is calculated using historical regression analysis.

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

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

Derivative instruments categorized as Level 3 include natural gas options purchased by DPL as part of a natural gas hedging program approved by the DPSC and natural gas physical basis contracts held by Pepco Energy Services. The valuation of the options is based, in part, on internal volatility assumptions extracted from historical NYMEX prices over a certain period of time. The physical basis contracts are valued using liquid hub prices plus a congestion adder that is calculated using historical regression analysis.

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

The following tables set forth, by level within the fair value hierarchy, PHI’s financial assets and liabilities (excluding Conectiv Energy assets and liabilities held for sale) that were accounted for at fair value on a recurring basis as of June 30, 2011 and December 31, 2010. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. PHI’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Fair Value Measurements at June 30, 2011
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)(a)		Significant Other Observable Inputs (Level 2)(a)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Derivative instruments (b)
Electricity (c)	$	11	$	—	$	11	$	—
Cash equivalents
Treasury Fund		62		62		—		—
Executive deferred compensation plan assets
Money Market Funds		16		16		—		—
Life Insurance Contracts		64		—		45		19
	$	153	$	78	$	56	$	19
LIABILITIES
Derivative instruments (b)
Electricity (c)	$	55	$	—	$	55	$	—
Natural Gas (d)		68		47		—		21
Executive deferred compensation plan liabilities
Life Insurance Contracts		30		—		30		—
	$	153	$	47	$	85	$	21

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

(b) The fair value of derivative assets and liabilities reflect netting by counterparty before the impact of collateral.

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

(d) Level 1 instruments represent wholesale gas futures and swaps that are used mainly as part of Pepco Energy Service’s retail energy supply business and level 3 instruments represent natural gas options purchased by DPL as part of a natural gas hedging program approved by the DPSC.

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	Fair Value Measurements at December 31, 2010
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)(a)		Significant Other Observable Inputs (Level 2)(a)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Derivative instruments (b)
Electricity (c)	$	22	$	—	$	22	$	—
Cash equivalents
Treasury Fund		17		17		—		—
Executive deferred compensation plan assets
Money Market Funds		9		9		—		—
Life Insurance Contracts		66		—		47		19
	$	114	$	26	$	69	$	19
LIABILITIES
Derivative instruments (b)
Electricity (c)	$	88	$	—	$	88	$	—
Natural Gas (d)		98		75		—		23
Executive deferred compensation plan liabilities
Life Insurance Contracts		30		—		30		—
	$	216	$	75	$	118	$	23

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

(b) The fair value of derivative assets and liabilities reflect netting by counterparty before the impact of collateral.

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

(d) Level 1 instruments represent wholesale gas futures and swaps that are used mainly as part of Pepco Energy Service’s retail energy supply business and level 3 instruments represent natural gas options purchased by DPL as part of a natural gas hedging program approved by the DPSC.

Reconciliations of the beginning and ending balances of PHI’s fair value measurements using significant unobservable inputs (level 3) for the six months ended June 30, 2011 and 2010 are shown below:

	Six Months Ended June 30, 2011
	Natural Gas			Life Insurance Contracts
	(millions of dollars)
Beginning balance as of January 1	$	(23	)	$	19
Total gains or (losses) (realized and unrealized)
Included in income		—			5
Included in accumulated other comprehensive loss		—			—
Included in regulatory liabilities		(2	)		—
Purchases		—			—
Issuances		—			(1	)
Settlements		8			(4	)
Transfers in (out) of level 3		(4	)		—
Ending balance as of June 30	$	(21	)	$	19

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

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

	Six Months Ended June 30,
	2011		2010
	(millions of dollars)
Total gains included in income for the period	$	5	$	2
Change in unrealized gains relating to assets still held at reporting date	$	2	$	2

Other Financial Instruments

The estimated fair values of PHI’s issued debt and equity instruments at June 30, 2011 and December 31, 2010 are shown below:

	June 30, 2011				December 31, 2010
	(millions of dollars)
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	3,866	$	4,317	$	3,665	$	4,045
Transition Bonds issued by ACE Funding		350		390		367		406
Long-Term Project Funding		18		18		19		19
Redeemable Serial Preferred Stock		—		—		6		5

The fair value of Long-Term Debt issued by PHI and its utility subsidiaries was based on actual trade prices as of June 30, 2011 and December 31, 2010. Where trade prices were not available, PHI used a discounted cash flow model to estimate fair value. The fair value of Transition Bonds issued by ACE Funding, including amounts due within one year, were derived based on bid prices obtained from brokers and validated by PHI because actual trade prices were not available.

The fair value of the Redeemable Serial Preferred Stock was derived based on quoted market prices.

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

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(15) COMMITMENTS AND CONTINGENCIES

Regulatory and Other Matters

District of Columbia Divestiture Case

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

In May 2010, the DCPSC issued an order addressing all of the remaining issues related to the sharing of the proceeds of Pepco’s divestiture of its generating assets. In the order, the DCPSC ruled that Pepco is not required to share EDIT and ADITC with customers. However, the order also disallowed certain items that Pepco had included in the costs deducted from the proceeds of the sale of the generation assets. The disallowance of these costs, together with interest on the disallowed amount, increased the aggregate amount Pepco was required to distribute to customers, pursuant to the sharing formula, by approximately $11 million, which PHI recognized as an expense in 2010 and refunded the amounts to its customers. In June 2010, Pepco filed an application for reconsideration of the DCPSC’s order, contesting (i) approximately $5 million of the total of $6 million in disallowances and (ii) approximately $4 million of the $5 million in interest to be credited to customers (reflecting a difference in the period of time over which interest was calculated as well as the balance to which interest would be applied). In July 2010, the DCPSC denied Pepco’s application for reconsideration. In September 2010, Pepco filed an appeal of the DCPSC’s decision with the District of Columbia Court of Appeals. On April 12, 2011, the Court of Appeals affirmed the DCPSC order. Pepco does not intend to appeal this decision.

Maryland Public Service Commission Reliability Investigation

In August 2010, following the major storm events that occurred in July and August 2010, the Maryland Public Service Commission (MPSC) initiated a proceeding for the purpose of investigating the reliability of the Pepco distribution system and the quality of distribution service Pepco is providing its customers. On February 10, 2011, the MPSC issued a notice expanding the scope of issues on which it requested testimony to include suggested remedies for the MPSC to consider imposing if the MPSC finds that Pepco has failed to meet its public service obligations. The possible remedies identified in the notice were the imposition of civil penalties, changes in the manner of Pepco’s operations, modification of Pepco’s service territory and revocation of Pepco’s authority to exercise its public utility franchise. On March 2, 2011, an independent consultant retained by the MPSC to review and make recommendations regarding the reliability of Pepco’s distribution system and the quality of its service filed its report with the MPSC. Pepco and the other parties submitted written testimony and the MPSC held four days of hearings in mid-June 2011. The parties filed their initial briefs on July 20, 2011. Pepco’s position in this proceeding is that while it is implementing a comprehensive program that will improve the reliability of its distribution system and its planning for, and response to, adverse weather events, there is no evidentiary support to impose sanctions for past performance. The other parties, including the staff of the MPSC, the Maryland Office of People’s Counsel, the Maryland Energy Administration, and Montgomery County, Maryland, contend that Pepco’s service reliability has not met an acceptable level. The other parties have recommended a variety of sanctions, including, but not limited to, the imposition of significant fines, the denial of rate recovery for reliability improvement costs, a reduction in Pepco’s return on equity (ROE), restrictions on dividends to PHI in order to fund reliability improvement costs, compliance with enhanced reliability requirements within a specified period and various reporting

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requirements. While Pepco is committed to improving the reliability of its electric service, it is vigorously opposing the imposition of the sanctions requested by the other parties, which Pepco believes are unsupported by the record in this case. Pepco is unable to predict the outcome of this proceeding at this time.

Rate Proceedings

Over the last several years, PHI’s utility subsidiaries have proposed in each of their respective service territories the adoption of a mechanism to decouple retail distribution revenue from the amount of power delivered to retail customers. To date:

• A bill stabilization adjustment (BSA) has been approved and implemented for Pepco and DPL electric service in Maryland and for Pepco electric service in the District of Columbia. The MPSC has initiated a proceeding to review how the BSA operates in Maryland to recover revenues lost as a result of major storm outages (as discussed below).

• A modified fixed variable rate design (MFVRD) has been approved in concept for DPL electric service in Delaware, but the implementation has been deferred by the DPSC pending the development of an implementation plan and a customer education plan. DPL anticipates that the MFVRD will be in place for electric service early in 2012.

• A MFVRD has been approved in concept for DPL natural gas service in Delaware, but implementation likewise has been deferred until development of an implementation plan and a customer education plan.

• In New Jersey, a BSA that had been proposed by ACE as part of a Phase 2 to the base rate proceeding filed in August 2009 has not been included in a Stipulation of Settlement approved by the NJBPU on May 16, 2011. Accordingly, there is no BSA proposal currently pending in New Jersey.

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

On February 1, 2011, the MPSC initiated proceedings involving Pepco and DPL, as well as unaffiliated utilities including Baltimore Gas & Electric Company and Southern Maryland Electric Cooperative, for the purpose of reviewing how the BSA operates to recover revenues lost as a result of major storm outages. In its orders initiating the proceedings, the MPSC expressed concern that the utilities’ respective BSAs may be allowing them to recover revenues lost during extended outages, therefore unintentionally eliminating an incentive to restore service quickly. The MPSC will consider whether the BSA, as currently in effect, is appropriate, whether the calculations or determinant factors for calculating the BSA should be modified, and if so, what modifications should be made. On July 22, 2011, the MPSC held a legislative-style hearing on this matter. The potential financial impact of any modification to the BSA cannot be assessed until the details of

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the modification are known. A provision that excludes revenues lost as a result of major storm outages from the calculation of future BSA adjustments is already included in the BSA for Pepco in the District of Columbia as approved by the DCPSC. If the MPSC were to implement a change similar to the provision in effect in the District of Columbia, the financial impact of service interruptions due to a major storm would generally depend on the scope and duration of the outages.

Delaware

DPL makes an annual Gas Cost Rate (GCR) filing with the DPSC for the purpose of allowing DPL to recover gas procurement costs through customer rates. In August 2010, DPL made its 2010 GCR filing, which proposes rates that would allow DPL to recover an amount equal to a two-year amortization of currently under-recovered gas costs. In October 2010, the DPSC issued an order allowing DPL to place the new rates into effect on November 1, 2010, subject to refund and pending final DPSC approval. The effect of the proposed two-year amortization upon rates is an increase of 0.1% in the level of GCR. The parties in the proceeding submitted a proposed settlement to the hearing examiner on June 3, 2011, which includes DPL’s two-year amortization but provides that DPL will forego the interest associated with that amortization. The proposed settlement is subject to review of the hearing examiner and final review and approval by the DPSC.

In July 2010, DPL submitted an application with the DPSC to increase its natural gas distribution base rates. As subsequently amended in September 2010 (to replace test year data for the twelve months ended June 2010 with the actual data) and in October 2010 (based on an update to DPL’s natural gas advanced metering infrastructure implementation schedule), the filing sought approval of an annual rate increase of approximately $10.2 million, assuming the implementation of the MFVRD, based on a requested ROE of 11.00%. As permitted by Delaware law, DPL placed an annual increase of approximately $2.5 million annually into effect, on a temporary basis, on August 31, 2010, and the remainder of approximately $7.7 million of the requested increase was placed into effect on February 2, 2011, in each case subject to refund and pending final DPSC approval. On February 9, 2011, DPL, DPSC staff, and the Attorney General of Delaware entered into a proposed settlement agreement, which provides for an annual rate increase of approximately $5.8 million, based on an ROE of 10%. In the settlement agreement, the parties agreed to defer the implementation of the MFVRD until an implementation plan and a customer education plan are developed. On June 21, 2011, the DPSC approved the proposed settlement agreement, effective for service rendered on and after July 1, 2011. The excess amount collected will be refunded to customers through a bill credit.

District of Columbia

On July 8, 2011, Pepco filed an application with the DCPSC to increase its electric distribution base rates by approximately $42 million annually, based on an ROE of 10.75%. A decision by the DCPSC is expected in the second quarter of 2012.

Maryland

In December 2009, Pepco filed an electric distribution base rate case in Maryland. The filing sought approval of an annual rate increase of approximately $40 million, based on a requested ROE of 10.75%. During the course of the proceeding, Pepco reduced its request to approximately $28.2 million. In August 2010, the MPSC issued an order approving a rate increase of approximately $7.8 million, based on an ROE of 9.83% Pepco implemented the new rates on August 19, 2010, effective for services rendered on and after July 29, 2011. In September 2010, Pepco filed with the MPSC a motion for reconsideration of the following issues, which, if approved, in the aggregate would have increased annual revenue by approximately $8.5 million: (i) denial of inclusion in rate base of certain reliability plant investments, which occurred subsequent to the test period but before the rate effective period; (ii) denial of Pepco’s request to increase depreciation rates to reflect a corrected formula relating to the cost of removal expenses; and (iii) imposition of imputed cost savings to partially offset the costs of Pepco’s enhanced vegetation management program. On June 8, 2011, the MPSC denied the motion for reconsideration, thus bringing the matter to a conclusion.

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On December 21, 2010, DPL filed an application with the MPSC to increase its electric distribution base rates by $17.8 million annually, based on an ROE of 10.75%. On May 25, 2011, DPL and the other parties to the proceeding filed a unanimous stipulation and settlement providing for a rate increase of approximately $12.2 million and proposing a Phase II proceeding to explore methods to address the issue of regulatory lag (which is the delay experienced by DPL in recovering increased costs in its distribution rate base). Although no ROE was specified in the proposed settlement, it did provide that the ROE for purposes of calculating the allowance for funds used during construction and regulatory asset carrying costs would remain unchanged. The current ROE for those items is 10%. On July 8, 2011, the MPSC approved the proposed settlement.

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

On July 1, 2010, PHI sold the Conectiv Energy wholesale power generation business to Calpine. Under New Jersey’s Industrial Site Recovery Act (ISRA), the transfer of ownership triggered an obligation on the part of Conectiv Energy to remediate any environmental contamination at each of the nine Conectiv Energy generating facility sites located in New Jersey. Under the terms of the sale, Calpine has assumed responsibility for performing the ISRA-required remediation and for the payment of all related ISRA compliance costs up to $10 million. PHI is obligated to indemnify Calpine for any ISRA compliance remediation costs in excess of $10 million. According to preliminary estimates, the costs of ISRA-required remediation activities at the nine generating facility sites located in New Jersey are in the range of approximately $7 million to $18 million. PHI has accrued approximately $4 million as of June 30, 2011 for the ISRA-required remediation activities at the nine generating facility sites.

The sale of the Conectiv Energy wholesale power generation business to Calpine did not include a coal ash landfill site located at the Edge Moor generating facility, which PHI intends to close. The preliminary estimate of the costs to PHI to close the coal ash landfill ranges from approximately $2 million to $3 million, plus annual post-closure operations, maintenance and monitoring costs, estimated to range between $120,000 and $193,000 per year for 30 years. As of June 30, 2011, PHI had accrued approximately $5 million for landfill closure and monitoring.

In orders issued in 2007, the New Jersey Department of Environmental Protection (NJDEP) assessed penalties against Conectiv Energy in an aggregate amount of approximately $2 million, based on NJDEP’s contention that Conectiv Energy’s Deepwater generating facility exceeded the maximum allowable hourly heat input limits during certain periods in calendar years 2004, 2005 and 2006. Conectiv Energy appealed the NJDEP orders imposing these penalties to the New Jersey Office of Administrative Law. In connection with the sale of the generating facility to Calpine, PHI agreed to indemnify Calpine for any monetary penalties, fines or assessments arising out of the NJDEP orders. In May 2011, Calpine entered into a stipulation of settlement with NJDEP to resolve the appeal of the penalty orders. The stipulation of settlement required payment of a $96,000 penalty to the State of New Jersey and a $50,000 supplemental environmental project contribution to a third party for truck stop electrification projects in New Jersey. On May 27, 2011, PHI made the penalty payment and paid the contribution to fulfill its indemnity obligation to Calpine.

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General Litigation

Pepco

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, 2011, there are approximately 180 cases still pending against Pepco in the State Courts of Maryland, of which approximately 90 cases were filed after December 19, 2000, and were tendered to Mirant Corporation (Mirant) for defense and indemnification in connection with the sale by Pepco of its generation assets to Mirant in 2000.

While the aggregate amount of monetary damages sought in the remaining suits (excluding those tendered to Mirant) is approximately $360 million, PHI and Pepco believe the amounts claimed by the remaining plaintiffs are greatly exaggerated. The amount of total liability, if any, and any related insurance recovery cannot be determined at this time; however, based on information and relevant circumstances known at this time, PHI and Pepco do not believe these suits will have a material adverse effect on their respective financial conditions, results of operations or cash flows. However, if an unfavorable decision were rendered against Pepco, it could have a material adverse effect on Pepco’s and PHI’s financial condition, results of operations and cash flows.

Environmental Litigation

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

Franklin Slag Pile Site. In November 2008, ACE received a general notice letter from the U.S. Environmental Protection Agency (EPA) concerning the Franklin Slag Pile site in Philadelphia, Pennsylvania, asserting that ACE is a potentially responsible party (PRP) that may have liability with respect to the site. If liable, ACE would be responsible for reimbursing EPA for clean-up costs incurred and to be incurred by the agency and for the costs of implementing an EPA-mandated remedy. EPA’s claims are based on ACE’s sale of boiler slag from the B.L. England generating facility, then owned by ACE, to MDC Industries, Inc. (MDC) during the period June 1978 to May 1983. EPA claims that the boiler slag ACE sold to MDC contained copper and lead, which are hazardous substances under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA), and that the sales transactions may have constituted an arrangement for the

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disposal or treatment of hazardous substances at the site, which could be a basis for liability under CERCLA. The EPA letter also states that, as of the date of the letter, EPA’s expenditures for response measures at the site have exceeded $6 million. EPA estimates the cost for future response measures will be approximately $6 million. ACE understands that EPA sent similar general notice letters to three other companies and various individuals.

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

Peck Iron and Metal Site. EPA informed Pepco in a May 2009 letter that Pepco may be a PRP under CERCLA with respect to the cleanup of the Peck Iron and Metal site in Portsmouth, Virginia, for costs EPA has incurred in cleaning up the site. The EPA letter states that Peck Iron and Metal purchased, processed, stored and shipped metal scrap from military bases, governmental agencies and businesses and that Peck’s metal scrap operations resulted in the improper storage and disposal of hazardous substances. EPA bases its allegation that Pepco arranged for disposal or treatment of hazardous substances sent to the site on information provided by Peck Iron and Metal personnel, who informed EPA that Pepco was a customer at the site. Pepco has advised EPA by letter that its records show no evidence of any sale of scrap metal by Pepco to the site. Even if EPA has such records and such sales did occur, Pepco believes that any such scrap metal sales are entitled to the recyclable material exemption from CERCLA liability. In a Federal Register notice published on November 4, 2009, EPA placed the Peck Iron and Metal site on the National Priorities List (NPL). The NPL, among other things, serves as a guide to EPA in determining which sites warrant further investigation to assess the nature and extent of the human health and environmental risks associated with a site. In a July 12, 2011 letter, EPA invited Pepco to enter into discussions with the agency to conduct a remedial investigation/feasibility study (RI/FS) at the site. Pepco is evaluating EPA’s invitation, but cannot at this time predict the costs of the RI/FS, the cost of performing a remedy at the site or the amount of such costs that EPA might impose on Pepco. Based on current information, PHI and Pepco do not believe this matter will have a material adverse effect on their respective financial conditions, results of operations or cash flows.

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

Benning Road Site. In September 2010, PHI received a letter from EPA stating that EPA and the District of Columbia Department of the Environment (DDOE) have identified the Benning Road location, consisting of a transmission and distribution facility operated by Pepco and a generation facility operated by Pepco Energy Services, as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. The letter stated that the principal contaminants of concern are polychlorinated biphenyls (PCBs) and polycyclic aromatic hydrocarbons, that EPA is monitoring the efforts of DDOE and that EPA intends to use federal authority to address the Benning Road site if an agreement for a comprehensive study to evaluate

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(and, if necessary, to clean up) the facility is not reached. In an October 2010 letter, the Office of the Attorney General of the District of Columbia notified PHI of the District’s intent to sue Pepco Energy Services and Pepco under the Resource Conservation and Recovery Act for abatement of conditions related to their historical activities, including the discharge of PCBs at the Benning Road site, and under CERCLA for reimbursement of response costs incurred by the District. The District’s letter stated that EPA will list the Benning Road site on the NPL if contamination at the facility is not addressed in a timely manner.

In January 2011, in response to these EPA and District of Columbia letters, Pepco and Pepco Energy Services entered into a proposed consent decree with DDOE that requires Pepco and Pepco Energy Services to conduct a RI/FS for the Benning Road site and an approximately 10-15 acre portion of the adjacent Anacostia River. The RI/FS will form the basis for DDOE’s selection of a remedial action for the Benning Road site and for the Anacostia River sediment associated with the site. In February 2011, the District filed a complaint against Pepco and Pepco Energy Services in the United States District Court for the District of Columbia for the purpose of obtaining judicial approval of the consent decree. At the time of the filing, it was not expected that the filing of this complaint would lead to active litigation. Rather, after receiving public comment on the proposed consent decree, DDOE planned to file a motion requesting the District Court to enter the consent decree. However, in April 2011, Anacostia Riverkeeper, Inc., the Anacostia Watershed Society and the Natural Resources Defense Council (collectively, the Environmental Organizations) filed a motion to intervene as plaintiffs in the District Court action. Pepco and Pepco Energy Services and DDOE have filed briefs opposing their intervention. If the District Court allows the Environmental Organizations to intervene and become parties to the litigation, the settlement of the litigation by means of the consent decree will require their agreement, which could require changes to the terms of the proposed consent decree. DDOE, Pepco and Pepco Energy Services have agreed to certain revisions to the consent decree to address some of the comments from the Environmental Organizations. DDOE intends to file the amended consent decree with the District Court in the near future, and to request that the court approve and enter the consent decree. Whether the court agrees to enter the consent decree likely will depend on whether it decides to grant the Environmental Organizations’ intervention motion. Work on the RI/FS is not expected to begin until this matter is resolved.

At the present time, in light of the efforts by DDOE, Pepco and Pepco Energy Services to address the site through the proposed consent decree, Pepco and Pepco Energy Services anticipate that EPA will continue to refrain from listing the Benning Road facility on the NPL. The current estimate of the costs for performing the RI/FS is approximately $1 million. The remediation costs cannot be determined until the RI/FS is completed and the nature and scope of any remedial action are defined. However, the remediation costs are preliminarily projected to be approximately $13 million. As of June 30, 2011, PHI had an accrued liability of approximately $14 million with respect to this matter.

Price’s Pit Site. ACE owns a transmission and distribution right-of-way that traverses the Price’s Pit superfund site in Egg Harbor Township, New Jersey. EPA placed Price’s Pit on the NPL in 1983 and NJDEP undertook an environmental investigation to identify and implement remedial action at the site. NJDEP’s investigation revealed that landfill waste had been disposed on ACE’s right-of-way and NJDEP determined that ACE was a responsible party as the owner of a facility on which a hazardous substance has been deposited. ACE, EPA and NJDEP entered into a settlement agreement to resolve ACE’s alleged liability (which was fully executed as of June 21, 2011, but will not be effective until after a public notice period, which will close on August 5, 2011, and receipt by ACE of notice of effectiveness from EPA). The settlement agreement requires ACE to make a payment of approximately $1 million to the EPA Hazardous Substance Superfund and donate a four-acre parcel of land adjacent to the site to NJDEP.

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Appeal of New Jersey Flood Hazard Regulations. In November 2007, NJDEP adopted amendments to the agency’s regulations under the Flood Hazard Area Control Act (FHACA) to minimize damage to life and property from flooding caused by development in flood plains. The amended regulations impose a new regulatory program to mitigate flooding and related environmental impacts from a broad range of construction and development activities, including electric utility transmission and distribution construction, which were previously unregulated under the FHACA. These regulations impose restrictions on construction of new electric transmission and distribution facilities and increase the time and personnel resources required to obtain permits and conduct maintenance activities. In November 2008, ACE filed an appeal of these regulations with the Appellate Division of the Superior Court of New Jersey. The grounds for ACE’s appeal include the lack of administrative record justification for the FHACA regulations and conflict between the FHACA regulations and other state and federal regulations and standards for maintenance of electric power transmission and distribution facilities. The Appellate Division’s decision upholding the amended FHACA regulations was issued on July 22, 2011. ACE currently is evaluating that ruling, including the financial impact related compliance with the amended regulations. Based on current information, PHI and ACE do not believe these regulations will have a material adverse effect on their respective financial conditions, results of operations or cash flows.

Indian River Oil Release. In 2001, DPL entered into a consent agreement with the Delaware Department of Natural Resources and Environmental Control for remediation, site restoration, natural resource damage compensatory projects and other costs associated with environmental contamination resulting from an oil release at the Indian River generating facility, which was sold in June 2001. As of June 30, 2011, DPL’s accrual for expected future costs to fulfill its obligations under the consent agreement was approximately $5 million, of which approximately $1 million is expected to be incurred during the remainder of 2011.

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

The release falls within the regulatory jurisdiction of multiple federal and state agencies, each of which has responded to the release in some way. Beginning in March 2011, DDOE issued a series of compliance directives that require Pepco to prepare an incident report, provide certain records, and prepare and implement plans for sampling surface water and river sediments and assessing ecological risks and natural resources damages. Pepco is complying with DDOE’s compliance directives.

On March 16, 2011, the Virginia Department of Environmental Quality (VADEQ) requested documentation regarding the release and the preparation of an emergency response report, which Pepco submitted to the agency on April 20, 2011. On March 25, 2011, Pepco received a notice of violation from VADEQ, which advised Pepco of information on which VADEQ may rely to institute an administrative or judicial enforcement action and stated that Pepco may be asked to enter into a consent order to formalize a corrective action plan and schedule.

In March 2011, EPA conducted an inspection of the Potomac River substation to review compliance with federal regulations regarding Spill Prevention, Control, and Countermeasure (SPCC) plans for facilities using oil-containing equipment in proximity to surface waters. Following the inspection, EPA advised Pepco that it had identified several potential violations of the SPCC regulations relating to SPCC plan content, recordkeeping, and secondary containment. Pepco responded to EPA’s allegations and expects to engage in further discussions that may lead to an EPA demand for noncompliance penalties. In addition, as a result of the oil release, Pepco is reevaluating certain physical changes to existing containment systems and revising its SPCC plan.

The U.S. Coast Guard has assessed a $5,000 penalty for the release of oil into the waters of the United States.

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The amount of penalties, if any, that may be imposed by DDOE, VADEQ and/or EPA and the costs associated with possible changes to the containment system cannot be predicted at this time; however, based on current information, PHI and Pepco do not believe this matter will have a material adverse effect on their respective financial conditions, results of operations or cash flows.

PHI’s Cross-Border Energy Lease Investments

Between 1994 and 2002, PCI, a subsidiary of PHI, entered into eight cross-border energy lease investments involving public utility assets (primarily consisting of hydroelectric generation and coal-fired electric generation facilities and natural gas distribution networks) located outside of the United States. Each of these investments is comprised of multiple leases and the investment is structured as a sale and leaseback transaction commonly referred to by the IRS as a sale-in/lease-out or SILO transaction. PHI had previously received annual tax benefits from these eight cross-border energy lease investments of approximately $56 million, which as of March 31, 2011, had an aggregate book value of approximately $1.4 billion.

As more fully discussed in Note (7), “Leasing Activities,” PHI in the second quarter entered into early termination agreements with two lessees with respect to a number of leases in the cross-border energy lease portfolio. The lease terminations involved all of the leases comprising one of the eight cross-border energy lease investments and a small portion of the leases comprising a second cross-border energy lease investment. The early terminations of the leases were negotiated at the request of the lessees and were completed in June 2011. PHI received net cash proceeds of $161 million (net of a termination payment of $423 million used to retire the non-recourse debt associated with the terminated leases) and recorded a pre-tax gain of $39 million, representing the excess of the net cash proceeds over the carrying value of the lease investments. Going forward, PHI will receive annual tax benefits of approximately $52 million. As of June 30, 2011, the book value of PHI’s investment in its cross-border energy lease investments was approximately $1.3 billion. After taking into consideration the $74 million paid with the 2001-2002 audit (as discussed below), the net federal and state tax benefits received for the remaining leases from January 1, 2001, the earliest year that remains open to audit, to June 30, 2011, has been approximately $486 million.

In 2005, the Treasury Department and IRS issued Notice 2005-13 identifying sale-leaseback transactions with certain attributes entered into with tax-indifferent parties as tax avoidance transactions, and the IRS announced its intention to disallow the associated tax benefits claimed by the investors in these transactions. PHI’s cross-border energy lease investments, each of which is with a tax-indifferent party, have been under examination by the IRS as part of the normal PHI federal income tax audits. In the final IRS revenue agent’s reports issued in June 2006 and in March 2009 in connection with the audit of PHI’s 2001-2002 and 2003-2005 income tax returns, respectively, the IRS disallowed the depreciation and interest deductions in excess of rental income claimed by PHI with respect to each of its cross-border energy lease investments. In addition, the IRS has sought to recharacterize each of the leases as a loan transaction as to which PHI would be subject to original issue discount income. PHI disagrees with the IRS’ proposed adjustments and filed tax protests in August 2006 and May 2009, respectively, in connection with the audit of the 2001-2002 and the 2003-2005 income tax returns. Both of these protests were forwarded to the IRS Appeals Office. On August 9, 2010, PHI signed an IRS settlement statement with respect to the 2001-2002 income tax returns agreeing to the IRS’s disallowance of depreciation and interest deductions in excess of rental income with respect to the cross-border energy lease investments, but reserving its right to file timely refund claims in which it would contest the disallowances. The Joint Tax Committee approved the settlement on November 10, 2010. In January 2011, PHI paid $74 million of additional tax associated with the disallowed deductions from the cross-border energy lease investments for 2001 and 2002, plus penalties of $1 million. In June 2011, PHI paid $28 million in interest associated with the disallowed deductions. In July 2011, PHI filed a refund claim for the additional taxes and related interest and penalties incurred by reason of the disallowed deductions, which it expects the IRS to deny, and if so, PHI intends to pursue litigation in the U.S. Court of Federal Claims against the IRS to defend its tax position and recover the tax payment, interest, and penalties. Absent a settlement, litigation against the IRS may take several years to resolve. The 2003-2005 income tax return review continues to be in process with the IRS Appeals Office.

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At December 31, 2010 and 2009, PHI modified its tax cash flow assumptions under its cross-border energy lease investments for the periods 2010-2013 and 2010-2012, respectively, to reflect the anticipated timing of potential litigation with the IRS concerning the investments. As a result of the 2009 recalculation, PHI recorded a $2 million after-tax non-cash charge to earnings at December 31 2009, and recorded an additional $3 million in after-tax non-cash earnings during 2010 (as compared to the earnings that it would have recorded absent the 2009 recalculation). As a result of the 2010 recalculation, PHI recorded a $1 million after-tax non-cash charge to earnings at December 31, 2010.

In the event that the IRS were to be successful in disallowing 100% of the tax benefits associated with these leases and recharacterizing these leases as loans, PHI estimates that, as of June 30, 2011, it would be obligated to pay approximately $612 million in additional federal and state taxes and $105 million of interest on the remaining leases. The $612 million in additional federal and state taxes is net of the $74 million tax payment made in January 2011. In addition, the IRS could require PHI to pay a penalty of up to 20% on the amount of additional taxes due.

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 elect to liquidate all or a portion of its seven remaining cross-border energy lease investments, 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 remaining portfolio would generate sufficient cash proceeds to cover the estimated $717 million in federal and state taxes and interest due as of June 30, 2011, in the event of a total disallowance of tax benefits and a recharacterization of the leases 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) 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 June 14, 2011, the Council of the District of Columbia (DC Council) approved the “Fiscal Year 2012 Budget Support Act of 2011” (Budget Support Act). The Budget Support Act includes a provision requiring that corporate taxpayers in the District of Columbia (District) calculate taxable income allocable or apportioned to the District by reference to the income and apportionment factors applicable to commonly controlled organizations organized within the United States that are engaged in a unitary business. This new reporting method will be effective for tax years beginning on or after December 31, 2010, if the Budget Support Act becomes law.

If it becomes law, the Budget Support Act will require a remeasurement of PHI’s consolidated District of Columbia deferred tax balances as the Budget Support Act will result in the imposition of income taxes on income not previously taxable in the District. However, the Budget Support Act also provides a tax deduction for any increase in taxable temporary differences causing an increase in deferred tax liabilities; consequently any increase in deferred tax liabilities will be offset by the recording of deferred tax assets of an equal amount. Accordingly, the remeasurement of deferred taxes required by the Budget Support Act will have no income statement impact.

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The Budget Support Act was signed by the Mayor on July 22, 2011, and must be submitted to Congress for review. Congress must act to disapprove the Budget Support Act within 30 days of its submission (counting only those days when either the House or Senate is in session); absent congressional disapproval, it will become law following the review period.

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

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

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

As of June 30, 2011, Pepco Holdings and its subsidiaries were parties to a variety of agreements pursuant to which they were guarantors for standby letters of credit, performance residual value, and other commitments and obligations. The commitments and obligations, in millions of dollars, were as follows:

	Guarantor
	PHI		DPL		ACE		Pepco		Total
Energy procurement obligations of Pepco Energy Services (a)	$	194	$	—	$	—	$	—	$	194
Guarantees associated with disposal of Conectiv Energy assets (b)		50		—		—		—		50
Guaranteed lease residual values (c)		2		5		3		3		13
Total	$	246	$	5	$	3	$	3	$	257

(a) Pepco Holdings has contractual commitments for performance and related payments of Pepco Energy Services to counterparties under routine energy sales and procurement obligations.

(b) Represents guarantees by PHI in connection with transfers of Conectiv Energy tolling agreements and derivatives portfolio. The tolling agreement guarantees cover the payment by the entity to which the tolling agreement was assigned. The guaranteed amounts on the transferred tolling agreements totaled $25 million at June 30, 2011, which decline until the termination of the guarantees. The derivative portfolio guarantee is currently $25 million and covers Conectiv Energy’s performance prior to the assignment. This guarantee will reduce to approximately $13 million in July 2011 and remain in effect until the end of 2015.

(c) Subsidiaries of Pepco Holdings have guaranteed residual values in excess of fair value of certain equipment and fleet vehicles held through lease agreements. As of June 30, 2011, obligations under the guarantees were approximately $13 million. Assets leased under agreements subject to residual value guarantees are typically for periods ranging from 2 years to 10 years. Historically, payments under the guarantees have not been made by the guarantor as, under normal conditions, the contract runs to full term at which time the residual value is immaterial. As such, Pepco Holdings believes the likelihood of payments being required under the guarantee is remote.

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

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Energy Savings Performance Contracts

Pepco Energy Services has a diverse portfolio of energy savings performance contracts that are associated with the installation of energy savings equipment for federal, state and local government customers. As part of those contracts, Pepco Energy Services typically guarantees that the equipment or systems installed by Pepco Energy Services will generate a specified amount of energy savings on an annual basis over a multi-year period. As of June 30, 2011, Pepco Energy Services’ energy savings guarantees on both completed projects and projects under construction totaled $397 million over the life of the performance contracts with the longest remaining term being 15 years. On an annual basis, Pepco Energy Services undertakes a measurement and verification process to determine the amount of energy savings for the year and whether there is any shortfall in the annual energy savings compared to the guaranteed amount. Pepco Energy Services recognizes a liability for the value of the estimated energy savings shortfall when it is probable that the guaranteed energy savings will not be achieved and the amount is reasonably estimable. After giving effect to a $1 million guarantee payout on one contract that was terminated during the three months ended June 30, 2011, Pepco Energy Services as of June 30, 2011, did not have an accrued liability for energy savings performance contracts. There was no significant change in the type of contracts issued for the three and six months ended June 30, 2011. Based on its historical experience, Pepco Energy Services believes the probability of incurring a material loss under its energy savings performance contracts is remote.

Dividends

On July 28, 2011, Pepco Holdings’ Board of Directors declared a dividend on common stock of 27 cents per share payable September 30, 2011, to shareholders of record on September 12, 2011.

(16)DISCONTINUED OPERATIONS

In 2010, PHI disposed of Conectiv Energy. The disposition included the sale of the wholesale power generation business to Calpine, which was completed on July 1, 2010, and the liquidation of the remaining Conectiv Energy assets and businesses, which has been substantially completed.

PHI is 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.

The remaining net assets of Conectiv Energy are $2 million at June 30, 2011 and primarily include miscellaneous receivables and payables. Net assets at December 31, 2010 of $45 million included accounts receivable of $81 million, inventory of $20 million, net derivative liabilities of $18 million and other miscellaneous receivables and payables. At June 30, 2011, there were no derivative assets and liabilities or financial assets and liabilities that would be accounted for at fair value on a recurring basis. At December 31, 2010, Conectiv Energy had $7 million of financial assets (with $4 million and $3 million categorized within levels 2 and 3 of the fair value hierarchy, respectively) and $90 million of financial liabilities accounted for at fair value on a recurring basis (with $10 million and $80 million categorized within levels 1 and 2 of the fair value hierarchy, respectively).

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Operating Results

The operating results of Conectiv Energy are as follows:

	Three Months Ended June  30,						Six Months Ended June  30,
	2011			2010			2011		2010
	(millions of dollars)
(Loss) income from operations of discontinued operations, net of income taxes	$	(2	)	$	2		$	1	$	8
Net gains (losses) from dispositions of assets and businesses of discontinued operations, net of income taxes		1			(132	)		—		(130	)
(Loss) income from discontinued operations, net of income taxes	$	(1	)	$	(130	)	$	1	$	(122	)

(Loss) income from operations of discontinued operations, net of income taxes, for the three and six months ended June 30, 2011, includes adjustments of $4 million to certain remaining miscellaneous assets and liabilities. In addition, adjustments were made to certain accrued expenses for obligations associated with the sale of the wholesale power generation business to Calpine to reflect the actual amounts paid to Calpine during the six months ended June 30, 2011. For the three and six months ended June 30, 2010, (loss) income from operations of discontinued operations, net of income taxes, includes after-tax expenses for employee severance and retention benefits of $9 million and after-tax accrued expenses for certain obligations associated with the sale of the wholesale power generation business to Calpine of $13 million, each recorded in the second quarter of 2010.

Net gains (losses) from dispositions of assets and businesses of discontinued operations, net of income taxes for the three months ended June 30, 2011 include after-tax income of $1 million related to the sale of a tolling agreement in May 2011. Net gains (losses) from dispositions of assets and businesses of discontinued operations, net of income taxes, for the six months ended June 30, 2011 includes the income from the sale of the tolling agreement noted above, which is offset by an expense of approximately $1 million (after-tax) which was incurred in connection with a financial transaction entered into with a third party on January 6, 2011, under which Conectiv Energy transferred to the third party its remaining portfolio of derivatives, including financially settled natural gas and electric power transactions, for all remaining periods from February 1, 2011 forward. In connection with the closing of the transaction, Conectiv paid the third party $82 million, primarily representing the fair value of the derivatives at February 1, 2011, and an after-tax administrative fee of $1 million. Substantially all of the mark-to-market gains and losses associated with these derivatives were recorded in earnings through December 31, 2010 and accordingly no additional material gain or loss was recognized as a result of this transaction in 2011.

Net losses from dispositions of assets and businesses of discontinued operations, net of income taxes, of $132 million and $130 million for the three and six months ended June 30, 2010, respectively, include (i) the after-tax loss on the sale of the wholesale power generation business to Calpine of $67 million, (ii) after-tax net losses on sales of assets and businesses not sold to Calpine of $51 million and $49 million, respectively (inclusive of the recognition of after-tax unrealized losses on derivative contracts considered no longer probable to occur of $50 million recorded in the second quarter of 2010), and (iii) tax charges aggregating $14 million for the establishment of valuation allowances against certain deferred tax assets primarily associated with state net operating losses, the remeasurement of deferred taxes for expected changes in state income tax apportionment factors, and the write-off of certain tax credit carryforwards no longer expected to be realized.

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PEPCO HOLDINGS

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 included forward contracts, futures, swaps, and exchange-traded and over-the-counter options. The two primary risk management objectives were: (i) to manage the spread between the cost of fuel used to operate electric generation facilities and the revenue received from the sale of the power produced by those facilities, and (ii) to manage the spread between wholesale sale commitments and the cost of supply used to service those commitments to ensure stable cash flows and lock in favorable prices and margins when they became available.

As of June 30, 2011, Conectiv Energy had disposed of all energy commodity contracts and all cash collateral associated with these contracts had been returned.

Through June 30, 2010, Conectiv Energy purchased energy commodity contracts in the form of futures, swaps, options and forward contracts to hedge price risk in connection with the purchase of physical natural gas, oil and coal to fuel its generation assets for sale to customers. Conectiv Energy also purchased energy commodity contracts in the form of electricity swaps, options and forward contracts to hedge price risk in connection with the purchase of electricity for distribution to requirements-load customers. Through June 30, 2010, Conectiv Energy sold electricity swaps, options and forward contracts to hedge price risk in connection with electric output from its generating facilities. Conectiv Energy accounted for most of its futures, swaps and certain forward contracts as cash flow hedges of forecasted transactions, and accordingly, the effective portion of the gains or losses on these derivatives were reflected as a component of AOCL which were reclassified into income in the same period or periods during which the hedged transactions affect income. Gains and losses on the derivatives representing hedge ineffectiveness or hedge components excluded from the assessment of effectiveness were recognized in current income.

The amounts of pre-tax loss on commodity derivatives included in other comprehensive loss for Conectiv Energy for the three and six months ended June 30, 2011 and 2010 is provided in the table below:

	Three Months Ended June  30,				Six Months Ended June  30,
	2011		2010		2011		2010
	(millions of dollars)
Amount of net pre-tax gain (loss) arising during the period included in accumulated other comprehensive loss	$	—	$	44	$	—	$	(74	)
Amount of net pre-tax loss reclassified into income:
Effective portion:
Loss from discontinued operations, net of income taxes		—		61		—		106
Ineffective portion:
Loss from discontinued operations, net of income taxes (a)(b)		—		84		—		87
Total net pre-tax loss reclassified into income		—		145		—		193
Net pre-tax gain on commodity derivatives included in accumulated other comprehensive loss	$	—	$	189	$	—	$	119

(a) For the three months ended June 30, 2011 and 2010, amounts of zero and $87 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, 2011 and 2010, amounts of zero and $88 million, respectively, were reclassified from AOCL to income because the forecasted transactions were deemed probable not to occur.

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To the extent that Conectiv Energy held certain derivatives that did not qualify as hedges, these derivatives were recorded at fair value on the balance sheet with changes in fair value recognized in income. The amounts of realized and unrealized derivative gains (losses) for Conectiv Energy included in (Loss) income from discontinued operations, net of income taxes, for the three and six months ended June 30, 2011 and 2010, is provided in the table below:

	Three Months Ended June  30,					Six Months Ended June  30,
	2011		2010			2011		2010
	(millions of dollars)
Realized mark-to-market gains	$	—	$	23		$	—	$	26
Unrealized mark-to-market losses		—		(23	)		—		(24	)
Total net mark-to-market gains (losses)	$	—	$	—		$	—	$	2

(17)RESTRUCTURING CHARGE

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

In connection with the restructuring plan, PHI recorded a pre-tax restructuring charge of $30 million in 2010 related to severance, pension, and health and welfare benefits for employee terminations. The severance, pension, and health and welfare benefits were estimated based on the years of service and compensation levels of the employees associated with the 164 eliminated positions. The restructuring charge was allocated to PHI’s operating segments and was reflected as a separate line item in the Consolidated Statement of Income for the year ended December 31, 2010.

A reconciliation of PHI’s accrued restructuring charges for the three and six months ended June 30, 2011 is as follows:

	Three Months Ended June 30, 2011
	(millions of dollars)
	Power Delivery			Corporate and Other		PHI Consolidated
Beginning balance as of April 1, 2011	$	8		$	—	$	8
Restructuring charge		—			—		—
Cash payments		(2	)		—		(2	)
Ending balance as of June 30, 2011	$	6		$	—	$	6

	Six Months Ended June 30, 2011
	(millions of dollars)
	Power Delivery			Corporate and Other			PHI Consolidated
Beginning balance as of January 1, 2011	$	28		$	1		$	29
Restructuring charge		—			—			—
Cash payments		(22	)		(1	)		(23	)
Ending balance as of June 30, 2011	$	6		$	—		$	6

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POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(millions of dollars)
Operating Revenue	$	506		$	539		$	1,040		$	1,091
Operating Expenses
Purchased energy		218			261			473			576
Other operation and maintenance		100			73			202			161
Depreciation and amortization		42			40			84			78
Other taxes		94			88			186			163
Total Operating Expenses		454			462			945			978
Operating Income		52			77			95			113
Other Income (Expenses)
Interest and dividend income		—			1			—			1
Interest expense		(22	)		(25	)		(46	)		(50	)
Other income		4			2			10			5
Total Other Expenses		(18	)		(22	)		(36	)		(44	)
Income Before Income Tax Expense		34			55			59			69
Income Tax Expense		2			23			9			29
Net Income		32			32			50			40
Retained Earnings at Beginning of Period		741			713			723			730
Dividends paid to Parent		—			(25	)		—			(50	)
Retained Earnings at End of Period	$	773		$	720		$	773		$	720

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

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POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

(Unaudited)

	June 30, 2011			December 31, 2010
	(millions of dollars)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	58		$	88
Accounts receivable, less allowance for uncollectible accounts of $19 million and $20 million, respectively		378			373
Inventories		51			44
Prepayments of income taxes		27			95
Income taxes receivable		35			37
Prepaid expenses and other		51			34
Total Current Assets		600			671
INVESTMENTS AND OTHER ASSETS
Regulatory assets		223			191
Prepaid pension expense		305			274
Investment in trust		29			25
Income taxes receivable		25			34
Other		57			57
Total Investments and Other Assets		639			581
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		6,353			6,185
Accumulated depreciation		(2,666	)		(2,609	)
Net Property, Plant and Equipment		3,687			3,576
TOTAL ASSETS	$	4,926		$	4,828

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

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POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

(Unaudited)

	June 30, 2011		December 31, 2010
	(millions of dollars, except shares)
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities	$	207	$	194
Accounts payable due to associated companies		64		75
Capital lease obligations due within one year		8		8
Taxes accrued		64		62
Interest accrued		17		18
Other		106		119
Total Current Liabilities		466		476
DEFERRED CREDITS
Regulatory liabilities		161		147
Deferred income taxes, net		1,006		958
Investment tax credits		6		7
Other postretirement benefit obligations		68		67
Income taxes payable		—		3
Liabilities and accrued interest related to uncertain tax positions		54		52
Other		65		64
Total Deferred Credits		1,360		1,298
LONG-TERM LIABILITIES
Long-term debt		1,540		1,540
Capital lease obligations		82		86
Total Long-Term Liabilities		1,622		1,626
COMMITMENTS AND CONTINGENCIES (NOTE 10)
EQUITY
Common stock, $.01 par value, 200,000,000 shares authorized, 100 shares outstanding		—		—
Premium on stock and other capital contributions		705		705
Retained earnings		773		723
Total Equity		1,478		1,428
TOTAL LIABILITIES AND EQUITY	$	4,926	$	4,828

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,
	2011			2010
	(millions of dollars)
OPERATING ACTIVITIES
Net income	$	50		$	40
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		84			78
Deferred income taxes		17			23
Changes in:
Accounts receivable		(9	)		(47	)
Regulatory assets and liabilities, net		(1	)		(15	)
Accounts payable and accrued liabilities		(8	)		18
Pension contribution		(40	)		—
Taxes accrued		62			37
Other assets and liabilities		17			20
Net Cash From Operating Activities		172			154
INVESTING ACTIVITIES
Investment in property, plant and equipment		(205	)		(136	)
Department of Energy capital reimbursement awards received		14			—
Changes in restricted cash equivalents		—			1
Net other investing activities		(6	)		1
Net Cash Used By Investing Activities		(197	)		(134	)
FINANCING ACTIVITIES
Dividends paid to Parent		—			(50	)
Reacquisition of long-term debt		—			(16	)
Net other financing activities		(5	)		(10	)
Net Cash Used by Financing Activities		(5	)		(76	)
Net Decrease in Cash and Cash Equivalents		(30	)		(56	)
Cash and Cash Equivalents at Beginning of Period		88			213
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	58		$	157
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash received for income taxes (includes payments from PHI for federal income taxes)	$	71		$	16

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

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NOTES TO FINANCIAL STATEMENTS

POTOMAC ELECTRIC POWER COMPANY

(1) ORGANIZATION

Potomac Electric Power Company (Pepco) is engaged in the transmission and distribution of electricity in the District of Columbia and major portions of Prince George’s County and Montgomery County in suburban Maryland. Pepco also provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its service territories who do not elect to purchase electricity from a competitive energy supplier. Default Electricity Supply is known as Standard Offer Service in both the District of Columbia and Maryland. Pepco is a wholly owned subsidiary of Pepco Holdings, Inc. (Pepco Holdings or PHI).

(2) SIGNIFICANT ACCOUNTING POLICIES

Financial Statement Presentation

Pepco’s unaudited financial statements are prepared in conformity with accounting principles generally accepted in the United States of America (GAAP). Pursuant to the rules and regulations of the Securities and Exchange Commission, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been omitted. Therefore, these financial statements should be read along with the annual financial statements included in Pepco’s Annual Report on Form 10-K for the year ended December 31, 2010. In the opinion of Pepco’s management, the financial statements contain all adjustments (which all are of a normal recurring nature) necessary to present fairly Pepco’s financial condition as of June 30, 2011, in accordance with GAAP. The year-end December 31, 2010 Balance Sheet was derived from audited financial statements, but does not include all disclosures required by GAAP. Interim results for the three and six months ended June 30, 2011 may not be indicative of results that will be realized for the full year ending December 31, 2011 since the sales of electric energy are seasonal.

Use of Estimates

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

Significant matters that involve the use of estimates include the assessment of contingencies, the calculation of future cash flows and fair value amounts for use in asset impairment evaluations, pension and other postretirement benefits assumptions, unbilled revenue calculations, the assessment of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of restructuring charges, recognition of changes in network service transmission rates for prior service year costs, accrual of self-insurance reserves for general and auto liability claims and income tax provisions and reserves. Additionally, Pepco is subject to legal, regulatory, and other proceedings and claims that arise in the ordinary course of its business. Pepco records an estimated liability for these proceedings and claims when it is probable that a loss has been incurred and the loss is reasonably estimable.

Network Service Transmission Rates

In May 2011, Pepco filed its network service transmission rates with the Federal Energy Regulatory Commission (FERC) to be effective for the service year beginning June 1, 2011. The new rates include an adjustment for costs incurred in the service year ended May 31, 2011 that were not reflected in the rates charged to customers for that service year. In the second quarter of 2011, Pepco recorded a $2 million decrease in transmission revenues as a change to the estimates recorded in previous periods primarily due to a decrease in actual rate base versus estimated rate base.

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General and Auto Liability

During the second quarter of 2011, Pepco reduced its self-insurance reserves for general and auto liability claims by approximately $1 million, based on obtaining an actuarial estimate of the unpaid loss attributable to general and auto liability claims for Pepco at June 30, 2011.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in Pepco’s gross revenues were $85 million and $79 million for the three months ended June 30, 2011 and 2010, respectively, and $171 million and $143 million for the six months ended June 30, 2011 and 2010, respectively.

Reclassifications and Adjustments

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

Income Tax Adjustments

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

(3)NEWLY ADOPTED ACCOUNTING STANDARDS

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

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

(4)RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Fair Value Measurements and Disclosures (ASC 820)

In May 2011, the FASB issued new guidance on fair value measurement and disclosures that will be effective beginning with Pepco’s March 31, 2012 financial statements. The new guidance would change how fair value is measured in specific instances and expand disclosures about fair value measurements. Pepco is evaluating the impact of this new 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.

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(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, 2011 and 2010, before intercompany allocations from the PHI Service Company, were $19 million and $31 million, respectively. Pepco’s allocated share was $7 million and $13 million, respectively, for the three months ended June 30, 2011 and 2010. PHI’s pension and other postretirement net periodic benefit cost for the six months ended June 30, 2011 and 2010, before intercompany allocations from the PHI Service Company, were $46 million and $60 million, respectively. Pepco’s allocated share was $17 million and $20 million, respectively, for the six months ended June 30, 2011 and 2010.

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

(7) DEBT

Credit Facility

The principal credit source for PHI and its utility subsidiaries is an unsecured $1.5 billion syndicated credit facility, which can be used to borrow funds, obtain letters of credit and support the issuance of commercial paper. As of June 30, 2011, PHI’s credit limit under the facility was $875 million and the credit limit for each of Pepco, Delmarva Power & Light Company (DPL) and Atlantic City Electric Company (ACE) was the lesser of $500 million and the maximum amount of debt each company was permitted to have outstanding by its regulatory authorities, except that the aggregate amount of credit used by Pepco, DPL and ACE collectively, at any given time, could not exceed $625 million. On August 1, 2011, PHI, Pepco, DPL and ACE entered into an amendment and restatement of the credit agreement with respect to the facility, which among other changes extends the expiration date of the facility from May 2, 2012, to August 1, 2016. The facility, as amended and restated is more fully described below under the heading “Financing Activities Subsequent to June 30, 2011.” PHI also has two bi-lateral 364 day unsecured credit agreements totaling $200 million. Under each of the credit agreements, PHI has access to revolving and floating rate loans over the terms of the agreements. Neither agreement provides for the issuance of letters of credit. Both agreements expire on October 26, 2011.

At June 30, 2011 and December 31, 2010, the aggregate amount of cash plus unused borrowing capacity under the $1.5 billion credit facility available to meet the future liquidity needs of PHI’s utility subsidiaries was $595 million and $462 million, respectively.

Financing Activities Subsequent to June 30, 2011

On August 1, 2011, PHI, Pepco, DPL and ACE entered into an amendment and restatement of their $1.5 billion credit facility to extend the expiration date to August 1, 2016, and to make various other changes. As amended and restated, all or any portion of the facility may be used to obtain revolving loans and up to $500 million may be used to obtain letters of credit. PHI’s credit sublimit under the facility is $750 million and the sublimit of each of Pepco, DPL and ACE is $250 million. The borrowers may increase or decrease their respective sublimits during the term of the facility, except that (i) the sum of all of the borrower sublimits following any such increase or decrease must equal the total amount of the facility and (ii) the aggregate amount of credit used at any given time by (a) PHI may not exceed $1.25 billion and (b) each of Pepco, DPL or ACE may not exceed the lesser of $500 million and the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of sublimit reallocations cannot exceed eight per fiscal year during the term of the agreement.

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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, the federal funds effective rate plus 0.5% and one month LIBOR plus 1.0%, 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 10% of the total amount of the facility. Any swingline loan must be repaid by the borrower within fourteen days of receipt thereof. All indebtedness incurred under the facility is unsecured.

(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,
	2011					2010					2011								2010
	(millions of dollars)
Income tax at federal statutory rate	$	12		35.0	%	$	19		35.0	%	$	21		35.0	%	$	24			35.0	%
Increases (decreases) resulting from:
Depreciation		—		—			2		2.9			—		—			3			3.6
Change in estimates and interest related to uncertain and effectively settled tax positions		(4	)	(12.1	)		1		2.2			(4	)	(6.6	)		2			3.2
State income taxes, net of federal effect		2		4.7			3		5.4			3		4.6			4			5.5
Permanent differences related to deferred compensation funding		—		(1.2	)		—		(0.6	)		(2	)	(2.5	)		(1	)		(0.7	)
State tax benefit related to prior years’ asset dispositions		(4	)	(12.4	)		—		—			(4	)	(7.1	)		—			—
Asset removal costs		(2	)	(4.4	)		(1	)	(1.1	)		(3	)	(4.2	)		(1	)		(1.6	)
Other, net		(2	)	(3.8	)		(1	)	(2.0	)		(2	)	(3.9	)		(2	)		(3.0	)
Income tax expense	$	2		5.8	%	$	23		41.8	%	$	9		15.3	%	$	29			42.0	%

Pepco’s effective tax rates for the three months ended June 30, 2011 and 2010 were 5.8% and 41.8%, respectively. The decrease in the effective tax rate primarily resulted from changes in estimates and interest related to uncertain and effectively settled tax positions and refunds received on amended state tax returns.

During the second quarter of 2011, PHI reached a settlement with the Internal Revenue Service (IRS) with respect to interest due on its federal tax liabilities related to the November 2010 audit settlement for years 1996 through 2002. In connection with this agreement, PHI reallocated certain amounts that have been on deposit with the IRS since 2006 among liabilities in the settlement years and subsequent years. Primarily related to the settlement and reallocations, Pepco has recorded an additional tax benefit in the amount of $5 million (after-tax). This additional interest income was recorded in the second quarter of 2011.

In May 2011, Pepco received refunds of approximately $5 million and recorded tax benefits of approximately $4 million (after-tax) related to the filing of amended state tax returns. These amended returns reduced state taxable income due to an increase in tax basis on certain prior years’ asset dispositions.

Pepco’s effective tax rates for the six months ended June 30, 2011 and 2010 were 15.3% and 42.0%, respectively. The decrease in the effective tax rate primarily resulted from changes in estimates and interest related to uncertain and effectively settled tax positions, refunds received on amended state tax returns and permanent differences related to deferred compensation funding.

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In the second quarter of 2011, Pepco recorded a $5 million interest benefit from the reallocation of its deposits and the state refunds received of $4 million discussed above.

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

(9) FAIR VALUE DISCLOSURES

Financial Instruments Measured at Fair Value on a Recurring Basis

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

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

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

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

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

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

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The following tables set forth, by level within the fair value hierarchy, Pepco’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2011 and December 31, 2010. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Pepco’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Fair Value Measurements at June 30, 2011
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)(a)		Significant Other Observable Inputs (Level 2)(a)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Executive deferred compensation plan assets
Money Market Funds	$	13	$	13	$	—	$	—
Life Insurance Contracts		57		—		39		18
	$	70	$	13	$	39	$	18
LIABILITIES
Executive deferred compensation plan liabilities
Life Insurance Contracts	$	11	$	—	$	11	$	—
	$	11	$	—	$	11	$	—

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

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

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

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Reconciliations of the beginning and ending balances of Pepco’s fair value measurements using significant unobservable inputs (level 3) for the six months ended June 30, 2011 and 2010 are shown below:

	Life Insurance Contracts
	Six Months Ended June 30,
	2011			2010
	(millions of dollars)
Beginning balance as of January 1	$	18		$	18
Total gains or (losses) (realized and unrealized)
Included in income		5			2
Included in accumulated other comprehensive loss		—			—
Purchases		—			—
Issuances		(1	)		(1	)
Settlements		(4	)		—
Transfers in (out) of level 3		—			—
Ending balance as of June 30	$	18		$	19

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

	Six Months Ended June  30,
	2011		2010
	(millions of dollars)
Total gains included in income for the period	$	5	$	2
Change in unrealized gains relating to assets still held at reporting date	$	2	$	2

Other Financial Instruments

The estimated fair values of Pepco’s issued debt instruments at June 30, 2011 and December 31, 2010 are shown below:

	June 30, 2011				December 31, 2010
	(millions of dollars)
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	1,540	$	1,765	$	1,540	$	1,722

The fair value of long-term debt issued by Pepco was based on actual trade prices as of June 30, 2011 and December 31, 2010. Where trade prices were not available, Pepco used a discounted cash flow model to estimate fair value.

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

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(10)COMMITMENTS AND CONTINGENCIES

Regulatory and Other Matters

District of Columbia Divestiture Case

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

In May 2010, the DCPSC issued an order addressing all of the remaining issues related to the sharing of the proceeds of Pepco’s divestiture of its generating assets. In the order, the DCPSC ruled that Pepco is not required to share EDIT and ADITC with customers. However, the order also disallowed certain items that Pepco had included in the costs deducted from the proceeds of the sale of the generation assets. The disallowance of these costs, together with interest on the disallowed amount, increased the aggregate amount Pepco was required to distribute to customers, pursuant to the sharing formula, by approximately $11 million, which PHI recognized as an expense in 2010 and refunded the amounts to its customers. In June 2010, Pepco filed an application for reconsideration of the DCPSC’s order, contesting (i) approximately $5 million of the total of $6 million in disallowances and (ii) approximately $4 million of the $5 million in interest to be credited to customers (reflecting a difference in the period of time over which interest was calculated as well as the balance to which interest would be applied). In July 2010, the DCPSC denied Pepco’s application for reconsideration. In September 2010, Pepco filed an appeal of the DCPSC’s decision with the District of Columbia Court of Appeals. On April 12, 2011, the Court of Appeals affirmed the DCPSC order. Pepco does not intend to appeal this decision.

Maryland Public Service Commission Reliability Investigation

In August 2010, following the major storm events that occurred in July and August 2010, the Maryland Public Service Commission (MPSC) initiated a proceeding for the purpose of investigating the reliability of the Pepco distribution system and the quality of distribution service Pepco is providing its customers. On February 10, 2011, the MPSC issued a notice expanding the scope of issues on which it requested testimony to include suggested remedies for the MPSC to consider imposing if the MPSC finds that Pepco has failed to meet its public service obligations. The possible remedies identified in the notice were the imposition of civil penalties, changes in the manner of Pepco’s operations, modification of Pepco’s service territory and revocation of Pepco’s authority to exercise its public utility franchise. On March 2, 2011, an independent consultant retained by the MPSC to review and make recommendations regarding the reliability of Pepco’s distribution system and the quality of its service filed its report with the MPSC. Pepco and the other parties submitted written testimony and the MPSC held four days of hearings in mid-June 2011. The parties filed their initial briefs on July 20, 2011. Pepco’s position in this proceeding is that while it is implementing a comprehensive program that will improve the reliability of its distribution system and its planning for, and response to, adverse weather events, there is no evidentiary support to impose sanctions for past performance. The other parties, including the staff of the MPSC, the Maryland Office of People’s Counsel, the Maryland Energy Administration, and Montgomery County, Maryland, contend that Pepco’s service reliability has not met an acceptable level. The other parties have recommended a variety of sanctions, including, but not limited to, the imposition of significant fines, the denial of rate recovery for reliability improvement costs, a reduction in Pepco’s return on equity (ROE), restrictions on dividends to PHI in order to fund reliability improvement costs, compliance with enhanced reliability requirements within a specified period and various reporting

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requirements. While Pepco is committed to improving the reliability of its electric service, it is vigorously opposing the imposition of the sanctions requested by the other parties, which Pepco believes are unsupported by the record in this case. Pepco is unable to predict the outcome of this proceeding at this time.

Rate Proceedings

Over the last several years, Pepco has proposed in each of its service territories the adoption of a mechanism to decouple retail distribution revenue from the amount of power delivered to retail customers. A bill stabilization adjustment (BSA) has been approved and implemented for electric service in Maryland and the District of Columbia. The MPSC has initiated a proceeding to review how the BSA operates in Maryland to recover revenues lost as a result of major storm outages (as discussed below). Under the BSA, customer distribution rates are subject to adjustment (through a credit or surcharge mechanism), depending on whether actual distribution revenue per customer exceeds or falls short of the revenue-per-customer amount approved by the applicable public service commission. The BSA increases rates if actual distribution revenues fall below the approved level and decreases rates if actual distribution revenues are above the approved level. The result is that, over time, Pepco collects its authorized revenues for distribution service. As a consequence, a BSA “decouples” distribution revenue from unit sales consumption and ties the growth in distribution revenues to the growth in the number of customers. Some advantages of the BSA are that it (i) eliminates revenue fluctuations due to weather and changes in customer usage patterns and, therefore, provides for more predictable distribution revenues that are better aligned with costs, (ii) provides for more reliable fixed-cost recovery, (iii) tends to stabilize customers’ delivery bills, and (iv) removes any disincentives for Pepco to promote energy efficiency programs for its customers, because it breaks the link between overall sales volumes and distribution revenues.

On February 1, 2011, the MPSC initiated proceedings involving Pepco and its subsidiary DPL, as well as unaffiliated utilities including Baltimore Gas & Electric Company and Southern Maryland Electric Cooperative, for the purpose of reviewing how the BSA operates to recover revenues lost as a result of major storm outages. In its orders initiating the proceedings, the MPSC expressed concern that the utilities’ respective BSAs may be allowing them to recover revenues lost during extended outages, therefore unintentionally eliminating an incentive to restore service quickly. The MPSC will consider whether the BSA, as currently in effect, is appropriate, whether the calculations or determinant factors for calculating the BSA should be modified, and if so, what modifications should be made. On July 22, 2011, the MPSC held a legislative-style hearing on this matter. The potential financial impact of any modification to the BSA cannot be assessed until the details of the modification are known. A provision that excludes revenues lost as a result of major storm outages from the calculation of future BSA adjustments is already included in the BSA for Pepco in the District of Columbia as approved by the DCPSC. If the MPSC were to implement a change similar to the provision in effect in the District of Columbia, the financial impact of service interruptions due to a major storm would generally depend on the scope and duration of the outages.

District of Columbia

On July 8, 2011, Pepco filed an application with the DCPSC to increase its electric distribution base rates by approximately $42 million annually, based on an ROE of 10.75%. A decision by the DCPSC is expected in the second quarter of 2012.

Maryland

In December 2009, Pepco filed an electric distribution base rate case in Maryland. The filing sought approval of an annual rate increase of approximately $40 million, based on a requested ROE of 10.75%. During the course of the proceeding, Pepco reduced its request to approximately $28.2 million. In August 2010, the MPSC issued an order approving a rate increase of approximately $7.8 million, based on an ROE of 9.83% Pepco implemented the new rates on August 19, 2010, effective for services rendered on and after July 29,

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2011. In September 2010, Pepco filed with the MPSC a motion for reconsideration of the following issues, which, if approved, in the aggregate would have increased annual revenue by approximately $8.5 million: (i) denial of inclusion in rate base of certain reliability plant investments, which occurred subsequent to the test period but before the rate effective period; (ii) denial of Pepco’s request to increase depreciation rates to reflect a corrected formula relating to the cost of removal expenses; and (iii) imposition of imputed cost savings to partially offset the costs of Pepco’s enhanced vegetation management program. On June 8, 2011, the MPSC denied the motion for reconsideration, thus bringing the matter to a conclusion.

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, 2011, there are approximately 180 cases still pending against Pepco in the State Courts of Maryland, of which approximately 90 cases were filed after December 19, 2000, and were tendered to Mirant Corporation (Mirant) for defense and indemnification in connection with the sale by Pepco of its generation assets to Mirant in 2000.

While the aggregate amount of monetary damages sought in the remaining suits (excluding those tendered to Mirant) is approximately $360 million, Pepco believes the amounts claimed by the remaining plaintiffs are greatly exaggerated. The amount of total liability, if any, and any related insurance recovery cannot be determined at this time; however, based on information and relevant circumstances known at this time, Pepco does not believe these suits will have a material adverse effect on its financial 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 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 it would be included in its cost of service for ratemaking purposes.

Peck Iron and Metal Site. The U.S. Environmental Protection Agency (EPA) informed Pepco in a May 2009 letter that Pepco may be a potentially responsible party (PRP) under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA) with respect to the cleanup of the Peck Iron and Metal site in Portsmouth, Virginia, for costs EPA has incurred in cleaning up the site. The EPA letter states that Peck Iron and Metal purchased, processed, stored and shipped metal scrap from military bases,

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governmental agencies and businesses and that Peck’s metal scrap operations resulted in the improper storage and disposal of hazardous substances. EPA bases its allegation that Pepco arranged for disposal or treatment of hazardous substances sent to the site on information provided by Peck Iron and Metal personnel, who informed EPA that Pepco was a customer at the site. Pepco has advised EPA by letter that its records show no evidence of any sale of scrap metal by Pepco to the site. Even if EPA has such records and such sales did occur, Pepco believes that any such scrap metal sales are entitled to the recyclable material exemption from CERCLA liability. In a Federal Register notice published on November 4, 2009, EPA placed the Peck Iron and Metal site on the National Priorities List (NPL). The NPL, among other things, serves as a guide to EPA in determining which sites warrant further investigation to assess the nature and extent of the human health and environmental risks associated with a site. In a July 12, 2011 letter, EPA invited Pepco to enter into discussions with the agency to conduct a remedial investigation/feasibility study (RI/FS) at the site. Pepco is evaluating EPA’s invitation, but can not at this time predict the costs of the RI/FS, the cost of performing a remedy at the site or the amount of such costs that EPA might impose on Pepco. Based on current information, Pepco does not believe this matter will have a material adverse effect on its financial condition, results of operations or cash flows.

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

Benning Road Site. In September 2010, PHI received a letter from EPA stating that EPA and the District of Columbia Department of the Environment (DDOE) have identified the Benning Road location, consisting of a transmission and distribution facility operated by Pepco and a generation facility operated by Pepco Energy Services, as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. The letter stated that the principal contaminants of concern are polychlorinated biphenyls (PCBs) and polycyclic aromatic hydrocarbons, that EPA is monitoring the efforts of DDOE and that EPA intends to use federal authority to address the Benning Road site if an agreement for a comprehensive study to evaluate (and, if necessary, to clean up) the facility is not reached. In an October 2010 letter, the Office of the Attorney General of the District of Columbia notified PHI of the District’s intent to sue Pepco Energy Services and Pepco under the Resource Conservation and Recovery Act for abatement of conditions related to their historical activities, including the discharge of PCBs at the Benning Road site, and under CERCLA for reimbursement of response costs incurred by the District. The District’s letter stated that EPA will list the Benning Road site on the NPL if contamination at the facility is not addressed in a timely manner.

In January 2011, in response to these EPA and District of Columbia letters, Pepco and Pepco Energy Services entered into a proposed consent decree with DDOE that requires Pepco and Pepco Energy Services to conduct a RI/FS for the Benning Road site and an approximately 10-15 acre portion of the adjacent Anacostia River. The RI/FS will form the basis for DDOE’s selection of a remedial action for the Benning Road site and for the Anacostia River sediment associated with the site. In February 2011, the District filed a complaint against Pepco and Pepco Energy Services in the United States District Court for the District of Columbia for the purpose of obtaining judicial approval of the consent decree. At the time of the filing, it was not expected that the filing of this complaint would lead to active litigation. Rather, after receiving public comment on the proposed consent decree, DDOE planned to file a motion requesting the District Court to enter the consent decree. However, in April 2011, Anacostia Riverkeeper, Inc., the Anacostia Watershed Society and the Natural Resources Defense Council (collectively, the Environmental Organizations) filed a motion to intervene as plaintiffs in the District Court action. Pepco and Pepco Energy Services and DDOE have filed

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briefs opposing their intervention. If the District Court allows the Environmental Organizations to intervene and become parties to the litigation, the settlement of the litigation by means of the consent decree will require their agreement, which could require changes to the terms of the proposed consent decree. DDOE, Pepco and Pepco Energy Services have agreed to certain revisions to the consent decree to address some of the comments from the Environmental Organizations. DDOE intends to file the amended consent decree with the District Court in the near future, and to request that the court approve and enter the consent decree. Whether the court agrees to enter the consent decree likely will depend on whether it decides to grant the Environmental Organizations’ intervention motion. Work on the RI/FS is not expected to begin until this matter is resolved.

At the present time, in light of the efforts by DDOE, Pepco and Pepco Energy Services to address the site through the proposed consent decree, Pepco and Pepco Energy Services anticipate that EPA will continue to refrain from listing the Benning Road facility on the NPL. The current estimate of the costs for performing the RI/FS is approximately $1 million. The remediation costs cannot be determined until the RI/FS is completed and the nature and scope of any remedial action are defined. However, the remediation costs are preliminarily projected to be approximately $13 million. As of June 30, 2011, PHI had an accrued liability of approximately $14 million with respect to this matter.

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

The release falls within the regulatory jurisdiction of multiple federal and state agencies, each of which has responded to the release in some way. Beginning in March 2011, DDOE issued a series of compliance directives that require Pepco to prepare an incident report, provide certain records, and prepare and implement plans for sampling surface water and river sediments and assessing ecological risks and natural resources damages. Pepco is complying with DDOE’s compliance directives.

On March 16, 2011, the Virginia Department of Environmental Quality (VADEQ) requested documentation regarding the release and the preparation of an emergency response report, which Pepco submitted to the agency on April 20, 2011. On March 25, 2011, Pepco received a notice of violation from VADEQ, which advised Pepco of information on which VADEQ may rely to institute an administrative or judicial enforcement action and stated that Pepco may be asked to enter into a consent order to formalize a corrective action plan and schedule.

In March 2011, EPA conducted an inspection of the Potomac River substation to review compliance with federal regulations regarding Spill Prevention, Control, and Countermeasure (SPCC) plans for facilities using oil-containing equipment in proximity to surface waters. Following the inspection, EPA advised Pepco that it had identified several potential violations of the SPCC regulations relating to SPCC plan content, recordkeeping, and secondary containment. Pepco responded to EPA’s allegations and expects to engage in further discussions that may lead to an EPA demand for noncompliance penalties. In addition, as a result of the oil release, Pepco is reevaluating certain physical changes to existing containment systems and revising its SPCC plan.

The U.S. Coast Guard has assessed a $5,000 penalty for the release of oil into the waters of the United States.

The amount of penalties, if any, that may be imposed by DDOE, VADEQ and/or EPA and the costs associated with possible changes to the containment system cannot be predicted at this time; however, based on current information, Pepco does not believe this matter will have a material adverse effect on its financial condition, results of operations or cash flows.

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District of Columbia Tax Legislation

On June 14, 2011, the Council of the District of Columbia (DC Council) approved the “Fiscal Year 2012 Budget Support Act of 2011” (Budget Support Act). The Budget Support Act includes a provision requiring that corporate taxpayers in the District of Columbia (District) calculate taxable income allocable or apportioned to the District by reference to the income and apportionment factors applicable to commonly controlled organizations organized within the United States that are engaged in a unitary business. This new reporting method will be effective for tax years beginning on or after December 31, 2010, if the Budget Support Act becomes law.

If it becomes law, the Budget Support Act will require a remeasurement of PHI’s consolidated District of Columbia deferred tax balances as the Budget Support Act will result in the imposition of income taxes on income not previously taxable in the District. However, the Budget Support Act also provides a tax deduction for any increase in taxable temporary differences causing an increase in deferred tax liabilities; consequently any increase in deferred tax liabilities will be offset by the recording of deferred tax assets of an equal amount. Accordingly, the remeasurement of deferred taxes required by the Budget Support Act will have no income statement impact.

The Budget Support Act was signed by the Mayor on July 22, 2011, and must be submitted to Congress for review. Congress must act to disapprove the Budget Support Act within 30 days of its submission (counting only those days when either the House or Senate is in session); absent congressional disapproval, it will become law following the review period.

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

(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, 2011 and 2010 were approximately $43 million and $41 million, respectively. PHI Service Company costs directly charged or allocated to Pepco for the six months ended June 30, 2011 and 2010 were approximately $86 million and $85 million, respectively.

Certain subsidiaries of Pepco Energy Services perform utility maintenance services, including services that are treated as capital costs, for Pepco. Amounts charged to Pepco by these companies for the three months ended June 30, 2011 and 2010 were approximately $4 million and $2 million, respectively. Amounts charged to Pepco by these companies for the six months ended June 30, 2011 and 2010 were approximately $8 million and $3 million, respectively.

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As of June 30, 2011 and December 31, 2010, Pepco had the following balances on its Balance Sheets due to related parties:

	June 30, 2011			December 31, 2010
Asset (Liability)	(millions of dollars)
Payable to Related Party (current) (a)
PHI Service Company	$	(20	)	$	(27	)
Pepco Energy Services (b)		(44	)		(48	)
Total	$	(64	)	$	(75	)
Money Pool Balance with Pepco Holdings (included in Cash and cash equivalents)	$	50		$	82

(a) These amounts are included in Accounts payable due to associated companies on the Balance Sheet.

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

(12)RESTRUCTURING CHARGE

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

In connection with the restructuring plan, Pepco recorded a pre-tax restructuring charge of $15 million in 2010 related to its allocation of severance, pension, and health and welfare benefits for the termination of corporate services employees at PHI. The severance, pension, and health and welfare benefits were estimated based on the years of service and compensation levels of the employees associated with the 164 eliminated positions at PHI. The restructuring charge was reflected as a separate line item in the Statement of Income for the year ended December 31, 2010.

A reconciliation of Pepco’s accrued restructuring charges for the three and six months ended June 30, 2011 is as follows:

	Three Months Ended June 30, 2011
	(millions of dollars)
Beginning balance as of April 1, 2011	$	4
Restructuring charge		—
Cash payments		(1	)
Ending balance as of June 30, 2011	$	3

	Six Months Ended June 30, 2011
	(millions of dollars)
Beginning balance as of January 1, 2011	$	15
Restructuring charge		—
Cash payments		(12	)
Ending balance as of June 30, 2011	$	3

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DELMARVA POWER & LIGHT COMPANY

STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(millions of dollars)
Operating Revenue
Electric	$	245		$	260		$	543		$	559
Natural Gas		39			36			141			131
Total Operating Revenue		284			296			684			690
Operating Expenses
Purchased energy		145			159			327			360
Gas purchased		25			25			96			91
Other operation and maintenance		47			65			112			126
Depreciation and amortization		22			20			44			40
Other taxes		9			8			20			18
Total Operating Expenses		248			277			599			635
Operating Income		36			19			85			55
Other Income (Expenses)
Interest expense		(11	)		(12	)		(22	)		(22	)
Other income		2			2			4			3
Total Other Expenses		(9	)		(10	)		(18	)		(19	)
Income Before Income Tax Expense		27			9			67			36
Income Tax Expense		5			3			22			16
Net Income		22			6			45			20
Retained Earnings at Beginning of Period		517			486			494			472
Dividends paid to Parent		—			(23	)		—			(23	)
Retained Earnings at End of Period	$	539		$	469		$	539		$	469

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

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DELMARVA POWER & LIGHT COMPANY

BALANCE SHEETS

(Unaudited)

	June 30, 2011			December 31, 2010
	(millions of dollars)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	50		$	69
Accounts receivable, less allowance for uncollectible accounts of $15 million and $13 million, respectively		184			212
Inventories		39			41
Prepayments of income taxes		34			62
Prepaid expenses and other		24			22
Total Current Assets		331			406
INVESTMENTS AND OTHER ASSETS
Goodwill		8			8
Regulatory assets		217			242
Prepaid pension expense		171			139
Other		22			21
Total Investments and Other Assets		418			410
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		3,079			3,000
Accumulated depreciation		(915	)		(901	)
Net Property, Plant and Equipment		2,164			2,099
TOTAL ASSETS	$	2,913		$	2,915

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

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DELMARVA POWER & LIGHT COMPANY

BALANCE SHEETS

(Unaudited)

	June 30, 2011		December 31, 2010
	(millions of dollars, except shares)
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Short-term debt	$	105	$	105
Current portion of long-term debt		66		35
Accounts payable and accrued liabilities		90		98
Accounts payable due to associated companies		16		34
Taxes accrued		12		6
Interest accrued		6		7
Derivative liabilities		12		15
Other		61		73
Total Current Liabilities		368		373
DEFERRED CREDITS
Regulatory liabilities		304		310
Deferred income taxes, net		562		561
Investment tax credits		6		7
Other postretirement benefit obligations		26		22
Liabilities and accrued interest related to uncertain tax positions		22		24
Derivative liabilities		5		8
Other		35		39
Total Deferred Credits		960		971
LONG-TERM LIABILITIES
Long-term debt		699		730
COMMITMENTS AND CONTINGENCIES (NOTE 12)
EQUITY
Common stock, $2.25 par value, 1,000 shares authorized, 1,000 shares outstanding		—		—
Premium on stock and other capital contributions		347		347
Retained earnings		539		494
Total Equity		886		841
TOTAL LIABILITIES AND EQUITY	$	2,913	$	2,915

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,
	2011			2010
	(millions of dollars)
OPERATING ACTIVITIES
Net income	$	45		$	20
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		44			40
Deferred income taxes		40			3
Changes in:
Accounts receivable		28			17
Inventories		1			2
Regulatory assets and liabilities, net		(5	)		(6	)
Accounts payable and accrued liabilities		(24	)		7
Pension contribution		(40	)		—
Taxes accrued		(25	)		15
Other assets and liabilities		17			29
Net Cash From Operating Activities		81			127
INVESTING ACTIVITIES
Investment in property, plant and equipment		(99	)		(133	)
Net other investing activities		(1	)		(1	)
Net Cash Used By Investing Activities		(100	)		(134	)
FINANCING ACTIVITIES
Dividends paid to Parent		—			(23	)
Issuances of long-term debt		35			78
Reacquisitions of long-term debt		(35	)		—
Net other financing activities		—			(5	)
Net Cash From Financing Activities		—			50
Net (Decrease) Increase in Cash and Cash Equivalents		(19	)		43
Cash and Cash Equivalents at Beginning of Period		69			26
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	50		$	69
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash (paid) received for income taxes (includes payments (to) from PHI for federal income taxes)	$	(8	)	$	3

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

(2)SIGNIFICANT ACCOUNTING POLICIES

Financial Statement Presentation

DPL’s unaudited financial statements are prepared in conformity with accounting principles generally accepted in the United States of America (GAAP). Pursuant to the rules and regulations of the Securities and Exchange Commission, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been omitted. Therefore, these financial statements should be read along with the annual financial statements included in DPL’s Annual Report on Form 10-K for the year ended December 31, 2010. In the opinion of DPL’s management, the financial statements contain all adjustments (which all are of a normal recurring nature) necessary to present fairly DPL’s financial condition as of June 30, 2011, in accordance with GAAP. The year-end December 31, 2010 Balance Sheet was derived from audited financial statements, but does not include all disclosures required by GAAP. Interim results for the three and six months ended June 30, 2011 may not be indicative of results that will be realized for the full year ending December 31, 2011 since the sales of electric energy and natural gas are seasonal.

Use of Estimates

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

Significant matters that involve the use of estimates include the assessment of contingencies, the calculation of future cash flows and fair value amounts for use in asset impairment evaluations, fair value calculations (based on estimated market pricing) associated with derivative instruments, pension and other postretirement benefits assumptions, unbilled revenue calculations, the assessment of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of restructuring charges, recognition of changes in network service transmission rates for prior service year costs, accrual of self-insurance reserves for general and auto liability claims and income tax provisions and reserves. Additionally, DPL is subject to legal, regulatory, and other proceedings and claims that arise in the ordinary course of its business. DPL records an estimated liability for these proceedings and claims when it is probable that a loss has been incurred and the loss is reasonably estimable.

Network Service Transmission Rates

In May 2011, DPL filed its network service transmission rates with the Federal Energy Regulatory Commission to be effective for the service year beginning June 1, 2011. The new rates include an adjustment for costs incurred in the service year ended May 31, 2011 that were not reflected in the rates charged to customers for that service year. In the second quarter of 2011, DPL recorded a $2 million decrease in transmission revenues as a change to the estimates recorded in previous periods due to a decrease in actual rate base versus estimated rate base.

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General and Auto Liability

During the second quarter of 2011, DPL reduced its self-insurance reserves for general and auto liability claims by approximately $3 million, based on obtaining an actuarial estimate of the unpaid loss attributed to general and auto liability claims for DPL at June 30, 2011.

Consolidation of Variable Interest Entities - DPL Renewable Energy Transactions

DPL has entered into three land-based wind power purchase agreements (PPAs) and one offshore wind PPA in the aggregate amount of 350 megawatts as of June 30, 2011 and one solar PPA with a 10 megawatt facility. As the wind facilities become operational, DPL is obligated to purchase energy and renewable energy credits (RECs) in amounts generated and delivered by the facilities at rates that are primarily fixed under these agreements. Under one of the PPAs, DPL is also obligated to purchase the capacity associated with the facility at rates that are generally fixed. If a wind facility does not become operational by a specified date, DPL has the right to terminate that PPA.

One of the land-based facilities is operational and DPL is obligated to purchase energy and RECs from this facility through 2024 in amounts not to exceed 50.25 megawatts. The other two land-based wind agreements each have a 20-year term and are currently expected to become operational during 2011. DPL’s purchases under the operational wind PPAs totaled $4 million and $3 million for the three months ended June 30, 2011 and 2010, respectively, and $9 million and $6 million for the six months ended June 30, 2011 and 2010, respectively. In July 2011, the Delaware Public Service Commission (DPSC) approved amendments to one of the land-based wind PPAs to change the location of the facility and to reduce the maximum generation capacity from 60 megawatts to 38 megawatts.

The offshore wind PPA is expected to become operational during 2016. If the offshore wind facility developer is unable to obtain all necessary permits and financing commitments, this could result in delays in the construction schedule and the operational start date of the offshore wind facility.

The term of the agreement with the solar facility is 20 years and DPL is obligated to purchase RECs in an amount up to 70% of the energy output at a fixed price once the facility is operational, which is expected to be in the third quarter of 2011.

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

Goodwill

Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired at the acquisition date. All of DPL’s goodwill was generated by DPL’s acquisition of Conowingo Power Company in 1995. DPL tests its goodwill for impairment annually and whenever an event occurs or circumstances change in the interim that would more likely than not reduce the fair value of DPL below its carrying amount. DPL performs its annual impairment test on November 1. Factors that may result in an interim impairment test include, but are not limited to: a change in the identified reporting units; an adverse change in business conditions; an adverse regulatory action; or an impairment of DPL’s long-lived assets. As described in Note (6), “Goodwill,” DPL concluded that an interim impairment test was not required during the three and six months ended June 30, 2011.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in DPL’s gross revenues were $4 million for each of the three months ended June 30, 2011 and 2010 and $9 million for each of the six months ended June 30, 2011 and 2010.

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Reclassifications and adjustments

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

Default Electricity Supply Revenue and Costs Adjustments

During the second quarter of 2011, DPL recorded adjustments to correct certain errors associated with the accounting for Default Electricity Supply revenue and costs. These adjustments primarily arose from the under-recognition of allowed returns on the cost of working capital and resulted in a pre-tax decrease in “Other operation and maintenance” expense of $8 million.

(3)NEWLY ADOPTED ACCOUNTING STANDARDS

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

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

Goodwill (ASC 350)

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

(4)RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Fair Value Measurements and Disclosures (ASC 820)

In May 2011, the FASB issued new guidance on fair value measurement and disclosures that will be effective beginning with DPL’s March 31, 2012 financial statements. The new guidance would change how fair value is measured in specific instances and expand disclosures about fair value measurements. DPL is evaluating the impact of this new 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 months ended June 30, 2011. All of DPL’s goodwill was generated by its acquisition of Conowingo Power Company in 1995.

DPL’s annual impairment test as of November 1, 2010 indicated that goodwill was not impaired. As of June 30, 2011, DPL concluded that there were no events requiring it to perform an interim goodwill impairment test. DPL will continue to monitor for indicators of goodwill impairment.

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(7)PENSION AND OTHER POSTRETIREMENT BENEFITS

DPL accounts for its participation in the Pepco Holdings benefit plans as participation in a multi-employer plan. PHI’s pension and other postretirement net periodic benefit cost for the three months ended June 30, 2011 and 2010, before intercompany allocations from the PHI Service Company, were $19 million and $31 million, respectively. DPL’s allocated share was $5 million and $10 million, respectively, for the three months ended June 30, 2011 and 2010. PHI’s pension and other postretirement net periodic benefit cost for the six months ended June 30, 2011 and 2010, before intercompany allocations from the PHI Service Company, were $46 million and $60 million, respectively. DPL’s allocated share was $12 million and $14 million, respectively, for the six months ended June 30, 2011 and 2010.

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

(8)DEBT

Credit Facility

The principal credit source for PHI and its utility subsidiaries is an unsecured $1.5 billion syndicated credit facility, which can be used to borrow funds, obtain letters of credit and support the issuance of commercial paper. As of June 30, 2011, PHI’s credit limit under the facility was $875 million and the credit limit for each of Potomac Electric Power Company (Pepco), DPL and Atlantic City Electric Company (ACE) was the lesser of $500 million and the maximum amount of debt each company was permitted to have outstanding by its regulatory authorities, except that the aggregate amount of credit used by Pepco, DPL and ACE collectively, at any given time, could not exceed $625 million. On August 1, 2011, PHI, Pepco, DPL and ACE entered into an amendment and restatement of the credit agreement with respect to the facility, which among other changes extends the expiration date of the facility from May 2, 2012, to August 1, 2016. The facility, as amended and restated is more fully described below under the heading “Financing Activities Subsequent to June 30, 2011.” PHI also has two bi-lateral 364 day unsecured credit agreements totaling $200 million. Under each of the credit agreements, PHI has access to revolving and floating rate loans over the terms of the agreements. Neither agreement provides for the issuance of letters of credit. Both agreements expire on October 26, 2011.

At June 30, 2011 and December 31, 2010, the aggregate amount of cash plus unused borrowing capacity under the $1.5 billion credit facility available to meet the future liquidity needs of PHI’s utility subsidiaries was $595 million and $462 million, respectively.

Financing Activities

On June 1, 2011, DPL resold approximately $35 million of 0.75% Delaware Economic Development Authority tax-exempt bonds due May 1, 2026. The bonds were originally issued for the benefit of DPL in 2001 and were purchased by DPL on May 2, 2011 pursuant to a mandatory repurchase obligation triggered by the expiration of the original interest period for the bonds. The bonds are subject to mandatory purchase by DPL on June 1, 2012.

Financing Activities Subsequent to June 30, 2011

On August 1, 2011, PHI, Pepco, DPL and ACE entered into an amendment and restatement of their $1.5 billion credit facility to extend the expiration date to August 1, 2016, and to make various other changes. As amended and restated, all or any portion of the facility may be used to obtain revolving loans and up to $500 million may be used to obtain letters of credit. PHI’s credit sublimit under the facility is $750 million and the sublimit of each of Pepco, DPL and ACE is $250 million. The borrowers may increase or decrease their respective sublimits during the term of the facility, except that (i) the sum of all of the borrower sublimits following any such increase or decrease must equal the total amount of the facility and (ii) the aggregate

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amount of credit used at any given time by (a) PHI may not exceed $1.25 billion and (b) each of Pepco, DPL or ACE may not exceed the lesser of $500 million and the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of sublimit reallocations cannot exceed eight per fiscal year during the term of the agreement.

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, the federal funds effective rate plus 0.5% and one month LIBOR plus 1.0%, 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 10% of the total amount of the facility. Any swingline loan must be repaid by the borrower within fourteen days of receipt thereof. All indebtedness incurred under the facility is unsecured.

(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,
	2011					2010					2011					2010
	(millions of dollars)
Income tax at federal statutory rate	$	10		35.0	%	$	3		35.0	%	$	24		35.0	%	$	13		35.0	%
Increases (decreases) resulting from:
State income taxes, net of federal effect		1		5.2			1		5.6			4		6.0			1		5.0
Depreciation		1		3.7			1		6.7			1		1.5			2		2.2
Tax credits		—		(0.6	)		—		(2.2	)		—		(0.5	)		—		(1.1	)
Change in estimates and interest related to uncertain and effectively settled tax positions		(5	)	(18.5	)		(1	)	(7.8	)		(5	)	(7.5	)		1		3.6
Deferred tax adjustment		(1	)	(3.7	)		—		—			(1	)	(1.5	)		—		—
Other, net		(1	)	(2.6	)		(1	)	(4.0	)		(1	)	(0.2	)		(1	)	(0.3	)
Income tax expense	$	5		18.5	%	$	3		33.3	%	$	22		32.8	%	$	16		44.4	%

DPL’s effective tax rates for the three months ended June 30, 2011 and 2010 were 18.5% and 33.3%, respectively. The decrease in the effective tax rate primarily resulted from changes in estimates and interest related to uncertain and effectively settled tax positions.

During the second quarter of 2011, PHI reached a settlement with the Internal Revenue Service (IRS) with respect to interest due on its federal tax liabilities related to the November 2010 audit settlement for years 1996 through 2002. In connection with this agreement, PHI reallocated certain amounts that have been on deposit with the IRS since 2006 among liabilities in the settlement years and subsequent years. Primarily related to the settlement and reallocations, DPL has recorded an additional $4 million (after-tax) interest benefit. This additional interest income was recorded in the second quarter of 2011. Also during the second quarter of 2011, DPL completed a reconciliation of its deferred taxes on certain regulatory assets and, as a result, recorded a $1 million decrease to income tax expense as shown in the “Deferred tax adjustment” line above.

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DPL’s effective tax rates for the six months ended June 30, 2011 and 2010 were 32.8% and 44.4%, respectively. The decrease in the effective tax rate resulted from 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 as well as the additional $4 million interest benefit from the reallocation of deposits discussed above.

(10)DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

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

The tables below identify the balance sheet location and fair values of derivative instruments as of June 30, 2011 and December 31, 2010:

	As of June 30, 2011
Balance Sheet Caption	Derivatives Designated as Hedging Instruments			Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting		Net Derivative Instruments
	(millions of dollars)
Derivative Assets (current assets)	$	—		$	—		$	—		$	—	$	—
Derivative Assets (non-current assets)		—			—			—			—		—
Total Derivative Assets		—			—			—			—		—
Derivative Liabilities (current liabilities)		(3	)		(12	)		(15	)		3		(12	)
Derivative Liabilities (non-current liabilities)		—			(5	)		(5	)		—		(5	)
Total Derivative Liabilities		(3	)		(17	)		(20	)		3		(17	)
Net Derivative (Liability) Asset	$	(3	)	$	(17	)	$	(20	)	$	3	$	(17	)

	As of December 31, 2010
Balance Sheet Caption	Derivatives Designated as Hedging Instruments			Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting		Net Derivative Instruments
	(millions of dollars)
Derivative Assets (current assets)	$	—		$	—		$	—		$	—	$	—
Derivative Assets (non-current assets)		—			—			—			—		—
Total Derivative Assets		—			—			—			—		—
Derivative Liabilities (current liabilities)		(6	)		(15	)		(21	)		6		(15	)
Derivative Liabilities (non-current liabilities)		—			(8	)		(8	)		—		(8	)
Total Derivative Liabilities		(6	)		(23	)		(29	)		6		(23	)
Net Derivative (Liability) Asset	$	(6	)	$	(23	)	$	(29	)	$	6	$	(23	)

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

	June 30, 2011		December 31, 2010
	(millions of dollars)
Cash collateral pledged to counterparties with the right to reclaim	$	3	$	6

As of June 30, 2011 and December 31, 2010, all DPL cash collateral pledged related to derivative instruments accounted for at fair value was entitled to be offset under master netting agreements.

Derivatives Designated as Hedging Instruments

Cash Flow Hedges

All premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all of DPL’s gains and losses related to hedging activities, are deferred under FASB guidance on regulated operations until recovered from customers through a fuel adjustment clause approved by the DPSC. The following table indicates the amounts of the net unrealized derivative gain (loss) deferred as a regulatory liability (regulatory asset) and the realized loss recognized in the Statements of Income for the three and six months ended June 30, 2011 and 2010:

	Three Months Ended June  30,						Six Months Ended June  30,
	2011			2010			2011			2010
	(millions of dollars)
Net Unrealized Gain (Loss) Deferred as a Regulatory Liability (Asset)	$	2		$	5		$	3		$	—
Net Realized Loss Recognized in Purchased Energy or Gas Purchased		(1	)		(3	)		(3	)		(5	)

As of June 30, 2011 and December 31, 2010, DPL had the following outstanding commodity forward contracts that were entered into to hedge forecasted transactions:

	Quantities
Commodity	June 30, 2011		December 31, 2010
Forecasted Purchases Hedges
Natural Gas (One Million British Thermal Units (MMBtu))		765,000		1,670,000

Other Derivative Activity

DPL holds certain derivatives that are not in hedge accounting relationships nor are they designated as normal purchases or normal sales. These derivatives are recorded at fair value on the Balance Sheets with changes in the fair value recorded in income. In accordance with FASB guidance on regulated operations, offsetting regulatory liabilities or regulatory assets are recorded on the Balance Sheets and the recognition of the derivative gain or loss is deferred because of the DPSC-approved fuel adjustment clause. For the three and six months ended June 30, 2011 and 2010, the net amount of the unrealized derivative gain (loss) deferred as a regulatory liability (regulatory asset) and the net realized loss recognized in the Statements of Income is provided in the table below:

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	Three Months Ended June  30,						Six Months Ended June  30,
	2011			2010			2011			2010
	(millions of dollars)
Net Unrealized Gain (Loss) Deferred as a Regulatory Liability (Asset)	$	2		$	7		$	9		$	1
Net Realized Loss Recognized in Purchased Energy or Gas Purchased		(4	)		(6	)		(11	)		(13	)

As of June 30, 2011 and December 31, 2010, DPL had the following net outstanding natural gas commodity forward contracts that did not qualify for hedge accounting:

	June 30, 2011				December 31, 2010
Commodity	Quantity		Net Position		Quantity		Net Position
Natural Gas (MMBtu)		5,892,432		Long		7,827,635		Long

Contingent Credit Risk Features

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

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

The gross fair value of DPL’s derivative liabilities, excluding the impact of offsetting transactions or collateral under master netting agreements, with credit-risk-related contingent features on June 30, 2011 and December 31, 2010, was $17 million and $23 million, respectively, before giving effect to the impact of a credit rating downgrade that would increase this amount or offsetting transactions that are encompassed within master netting agreements that would alter these amounts. As of those dates, DPL had not posted any cash collateral against the gross derivative liability. DPL’s net settlement amount in the event of a downgrade of DPL’s senior unsecured debt rating to below “investment grade” as of June 30, 2011 and December 31, 2010, would have been approximately $16 million and $31 million, respectively, after taking into account the master netting agreements.

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DPL’s primary source for posting cash collateral or letters of credit are PHI’s credit facilities. At June 30, 2011 and December 31, 2010, the aggregate amount of cash plus borrowing capacity under the PHI credit facilities available to meet the liquidity needs of PHI’s utility subsidiaries was $595 million and $462 million, respectively.

(11) FAIR VALUE DISCLOSURES

Financial Instruments Measured at Fair Value on a Recurring Basis

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

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

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

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

Derivative instruments categorized as Level 3 include natural gas options purchased by DPL as part of a natural gas hedging program approved by the DPSC. The valuation of the options is based, in part, on internal volatility assumptions extracted from historical NYMEX prices over a certain period of time.

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

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The following tables set forth, by level within the fair value hierarchy, DPL’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2011 and December 31, 2010. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. DPL’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Fair Value Measurements at June 30, 2011
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)(a)		Significant Other Observable Inputs (Level 2)(a)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Executive deferred compensation plan assets
Money Market Funds	$	2	$	2	$	—	$	—
Life Insurance Contracts		1		—		—		1
	$	3	$	2	$	—	$	1
LIABILITIES
Derivative instruments (b)
Natural Gas	$	20	$	3	$	—	$	17
	$	20	$	3	$	—	$	17

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

(b) The fair value of derivative liabilities reflects netting by counterparty before the impact of collateral.

	Fair Value Measurements at December 31, 2010
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)(a)		Significant Other Observable Inputs (Level 2)(a)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Executive deferred compensation plan assets
Money Market Funds	$	2	$	2	$	—	$	—
Life Insurance Contracts		1		—		—		1
	$	3	$	2	$	—	$	1
LIABILITIES
Derivative instruments (b)
Natural Gas	$	29	$	6	$	—	$	23
	$	29	$	6	$	—	$	23

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

(b) The fair value of derivative liabilities reflects netting by counterparty before the impact of collateral.

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Reconciliations of the beginning and ending balances of DPL’s fair value measurements using significant unobservable inputs (level 3) for the six months ended June 30, 2011 and 2010 are shown below:

	Six Months Ended June 30, 2011
	Natural Gas			Life Insurance Contracts
	(millions of dollars)
Beginning balance as of January 1	$	(23	)	$	1
Total gains or (losses) (realized and unrealized):
Included in income		—			—
Included in accumulated other comprehensive loss		—			—
Included in regulatory liabilities		(2	)		—
Purchases		—			—
Issuances		—			—
Settlements		8			—
Transfers in (out) of level 3		—			—
Ending balance as of June 30	$	(17	)	$	1

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

Other Financial Instruments

The estimated fair values of DPL’s issued debt instruments as of June 30, 2011 and December 31, 2010 are shown below:

	June 30, 2011				December 31, 2010
	(millions of dollars)
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	765	$	827	$	765	$	822

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The fair value of long-term debt issued by DPL was based on actual trade prices as of June 30, 2011 and December 31, 2010. Where trade prices were not available, DPL used a discounted cash flow model to estimate fair value.

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

(12)COMMITMENTS AND CONTINGENCIES

Regulatory and Other Matters

Rate Proceedings

Over the last several years, DPL has proposed in each of its service territories the adoption of a mechanism to decouple retail distribution revenue from the amount of power delivered to retail customers. To date:

• A bill stabilization adjustment (BSA) has been approved and implemented for electric service in Maryland. The Maryland Public Service Commission (MPSC) has initiated a proceeding to review how the BSA operates in Maryland to recover revenues lost as a result of major storm outages (as discussed below).

• A modified fixed variable rate design (MFVRD) has been approved in concept for DPL electric service in Delaware, but the implementation has been deferred by the DPSC pending the development of an implementation plan and a customer education plan. DPL anticipates that the MFVRD will be in place for electric service by early in 2012.

• A MFVRD has been approved in concept for DPL natural gas service in Delaware, but implementation likewise has been deferred until development of an implementation plan and a customer education plan.

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

On February 1, 2011, the MPSC initiated proceedings involving DPL and its affiliate Pepco, as well as unaffiliated utilities including Baltimore Gas & Electric Company and Southern Maryland Electric Cooperative, for the purpose of reviewing how the BSA operates to recover revenues lost as a result of major storm outages. In its orders initiating the proceedings, the MPSC expressed concern that the utilities’ respective BSAs may be allowing them to recover revenues lost during extended outages, therefore unintentionally eliminating an incentive to restore service quickly. The MPSC will consider whether the BSA, as currently in effect, is appropriate, whether the calculations or determinant factors for calculating the BSA

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should be modified, and if so, what modifications should be made. On July 22, 2011, the MPSC held a legislative-style hearing on this matter. The potential financial impact of any modification to the BSA cannot be assessed until the details of the modification are known. If the MPSC were to implement a change similar to the provision in effect in the District of Columbia, the financial impact of service interruptions due to a major storm would generally depend on the scope and duration of the outages.

Delaware

DPL makes an annual Gas Cost Rate (GCR) filing with the DPSC for the purpose of allowing DPL to recover gas procurement costs through customer rates. In August 2010, DPL made its 2010 GCR filing, which proposes rates that would allow DPL to recover an amount equal to a two-year amortization of currently under-recovered gas costs. In October 2010, the DPSC issued an order allowing DPL to place the new rates into effect on November 1, 2010, subject to refund and pending final DPSC approval. The effect of the proposed two-year amortization upon rates is an increase of 0.1% in the level of GCR. The parties in the proceeding submitted a proposed settlement to the hearing examiner on June 3, 2011, which includes DPL’s two-year amortization but provides that DPL will forego the interest associated with that amortization. The proposed settlement is subject to review of the hearing examiner and final review and approval by the DPSC.

In July 2010, DPL submitted an application with the DPSC to increase its natural gas distribution base rates. As subsequently amended in September 2010 (to replace test year data for the twelve months ended June 2010 with the actual data) and in October 2010 (based on an update to DPL’s natural gas advanced metering infrastructure implementation schedule), the filing sought approval of an annual rate increase of approximately $10.2 million, assuming the implementation of the MFVRD, based on a requested return on equity (ROE) of 11.00%. As permitted by Delaware law, DPL placed an annual increase of approximately $2.5 million annually into effect, on a temporary basis, on August 31, 2010, and the remainder of approximately $7.7 million of the requested increase was placed into effect on February 2, 2011, in each case subject to refund and pending final DPSC approval. On February 9, 2011, DPL, DPSC staff, and the Attorney General of Delaware entered into a proposed settlement agreement, which provides for an annual rate increase of approximately $5.8 million, based on an ROE of 10%. In the settlement agreement, the parties agreed to defer the implementation of the MFVRD until an implementation plan and a customer education plan are developed. On June 21, 2011, the DPSC approved the proposed settlement agreement, effective for service rendered on and after July 1, 2011. The excess amount collected will be refunded to customers through a bill credit.

Maryland

On December 21, 2010, DPL filed an application with the MPSC to increase its electric distribution base rates by $17.8 million annually, based on an ROE of 10.75%. On May 25, 2011, DPL and the other parties to the proceeding filed a unanimous stipulation and settlement providing for a rate increase of approximately $12.2 million and proposing a Phase II proceeding to explore methods to address the issue of regulatory lag (which is the delay experienced by DPL in recovering increased costs in its distribution rate base). Although no ROE was specified in the proposed settlement, it did provide that the ROE for purposes of calculating the allowance for funds used during construction and regulatory asset carrying costs would remain unchanged. The current ROE for those items is 10%. On July 8, 2011, the MPSC approved the proposed settlement.

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

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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 it would be included in its cost of service for ratemaking purposes.

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

Indian River Oil Release. In 2001, DPL entered into a consent agreement with the Delaware Department of Natural Resources and Environmental Control for remediation, site restoration, natural resource damage compensatory projects and other costs associated with environmental contamination resulting from an oil release at the Indian River generating facility, which was sold in June 2001. As of June 30, 2011, DPL’s accrual for expected future costs to fulfill its obligations under the consent agreement was approximately $5 million, of which approximately $1 million is expected to be incurred during the remainder of 2011.

(13) RELATED PARTY TRANSACTIONS

PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries, including DPL. The cost of these services is allocated in accordance with cost allocation methodologies set forth in the service agreement using a variety of factors, including the subsidiaries’ share of employees, operating expenses, assets, and other cost causal methods. These intercompany transactions are eliminated by PHI in consolidation and no profit results from these transactions at PHI. PHI Service Company costs directly charged or allocated to DPL for the three months ended June 30, 2011 and 2010 were approximately $31 million for each reporting period. PHI Service Company costs directly charged or allocated to DPL for the six months ended June 30, 2011 and 2010 were approximately $62 million and $65 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:

	Three Months Ended June  30,					Six Months Ended June  30,
Income (Expenses)	2011		2010			2011		2010
	(millions of dollars)
Purchased power under Default Electricity Supply contracts with Conectiv Energy Supply, Inc. (CESI) (a)(b)	$	—	$	(20	)	$	1	$	(39	)
Intercompany lease transactions (c)		1		2			2		4

(a) Included in purchased energy expense.

(b) During 2010, PHI disposed of its Conectiv Energy segment and a third party assumed CESI’s responsibilities under these contracts.

(c) Included in electric revenue.

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As of June 30, 2011 and December 31, 2010, DPL had the following balances on its Balance Sheets due (to) from related parties:

(Liability) Asset	June 30, 2011			December 31, 2010
	(millions of dollars)
(Payable to) Receivable from Related Party (a)
PHI Service Company	$	(14	)	$	(19	)
Conectiv Energy Supply, Inc.		—			(13	)
Pepco Energy Services, Inc. and its subsidiaries (Pepco Energy Services) (b)		(2	)		(2	)
Other		—			—
Total	$	(16	)	$	(34	)
Money Pool Balance with Pepco Holdings (included in cash and cash equivalents)	$	46		$	63

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

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

(14)RESTRUCTURING CHARGE

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

In connection with the restructuring plan, DPL recorded a pre-tax restructuring charge of $8 million in 2010 related to its allocation of severance, pension, and health and welfare benefits for the termination of corporate services employees at PHI. The severance, pension, and health and welfare benefits were estimated based on the years of service and compensation levels of the employees associated with the 164 eliminated positions at PHI. The restructuring charge was reflected as a separate line item in the Statement of Income for the year ended December 31, 2010.

A reconciliation of DPL’s accrued restructuring charges for the three and six months ended June 30, 2011 is as follows:

	Three Months Ended June 30, 2011
	(millions of dollars)
Beginning balance as of April 1, 2011	$	2
Restructuring charge		—
Cash payments		—
Ending balance as of June 30, 2011	$	2

	Six Months Ended June 30, 2011
	(millions of dollars)
Beginning balance as of January 1, 2011	$	7
Restructuring charge		—
Cash payments		(5	)
Ending balance as of June 30, 2011	$	2

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ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended June  30,						Six Months Ended June  30,
	2011			2010			2011			2010
	(millions of dollars)
Operating Revenue	$	304		$	315		$	619		$	632
Operating Expenses
Purchased energy		196			243			394			478
Other operation and maintenance		51			47			106			97
Depreciation and amortization		33			25			66			49
Other taxes		5			6			11			12
Deferred electric service costs		(29	)		(63	)		(32	)		(82	)
Total Operating Expenses		256			258			545			554
Operating Income		48			57			74			78
Other Income (Expenses)
Interest expense		(18	)		(16	)		(33	)		(32	)
Other income		2			1			2			1
Total Other Expenses		(16	)		(15	)		(31	)		(31	)
Income Before Income Tax Expense		32			42			43			47
Income Tax Expense		14			16			19			23
Net Income		18			26			24			24
Retained Earnings at Beginning of Period		167			141			161			143
Retained Earnings at End of Period	$	185		$	167		$	185		$	167

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

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CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30, 2011			December 31, 2010
	(millions of dollars)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	4		$	4
Restricted cash equivalents		11			11
Accounts receivable, less allowance for uncollectible accounts of $11 million and $11 million, respectively		211			212
Inventories		18			17
Prepayments of income taxes		51			55
Income taxes receivable		11			25
Prepaid expenses and other		65			9
Total Current Assets		371			333
INVESTMENTS AND OTHER ASSETS
Regulatory assets		654			667
Prepaid pension expense		76			51
Income taxes receivable		64			59
Restricted cash equivalents		9			5
Assets and accrued interest related to uncertain tax positions		39			38
Other		12			11
Total Investments and Other Assets		854			831
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		2,486			2,443
Accumulated depreciation		(747	)		(729	)
Net Property, Plant and Equipment		1,739			1,714
TOTAL ASSETS	$	2,964		$	2,878

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

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CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30, 2011		December 31, 2010
	(millions of dollars, except shares)
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Short-term debt	$	48	$	181
Current portion of long-term debt		36		35
Accounts payable and accrued liabilities		132		120
Accounts payable due to associated companies		11		29
Taxes accrued		12		7
Interest accrued		15		13
Other		42		41
Total Current Liabilities		296		426
DEFERRED CREDITS
Regulatory liabilities		60		71
Deferred income taxes, net		681		659
Investment tax credits		8		8
Other postretirement benefit obligations		29		27
Other		16		13
Total Deferred Credits		794		778
LONG-TERM LIABILITIES
Long-term debt		833		633
Transition Bonds issued by ACE Funding		314		332
Total Long-Term Liabilities		1,147		965
COMMITMENTS AND CONTINGENCIES (NOTE 11)
REDEEMABLE SERIAL PREFERRED STOCK		—		6
EQUITY
Common stock, $3.00 par value, 25,000,000 shares authorized, 8,546,017 shares outstanding		26		26
Premium on stock and other capital contributions		516		516
Retained earnings		185		161
Total Equity		727		703
TOTAL LIABILITIES AND EQUITY	$	2,964	$	2,878

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

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CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended June 30,
	2011			2010
	(millions of dollars)
OPERATING ACTIVITIES
Net income	$	24		$	24
Adjustments to reconcile net income to net cash from (used by) operating activities:
Depreciation and amortization		66			49
Deferred income taxes		30			7
Changes in:
Accounts receivable		—			(19	)
Regulatory assets and liabilities, net		(34	)		(84	)
Accounts payable and accrued liabilities		(5	)		(24	)
Pension contribution		(30	)		—
Prepaid New Jersey sales and excise tax		(56	)		(52	)
Taxes accrued		13			22
Other assets and liabilities		11			8
Net Cash From (Used By) Operating Activities		19			(69	)
INVESTING ACTIVITIES
Investment in property, plant and equipment		(60	)		(76	)
Department of Energy capital reimbursement awards received		2			—
Net other investing activities		(3	)		2
Net Cash Used By Investing Activities		(61	)		(74	)
FINANCING ACTIVITIES
Capital contribution from Parent		—			23
Redemption of preferred stock		(6	)		—
Issuances of long-term debt		200			23
Reacquisitions of long-term debt		(17	)		(16	)
(Repayments) issuances of short-term debt, net		(133	)		110
Net other financing activities		(2	)		—
Net Cash From Financing Activities		42			140
Net Decrease in Cash and Cash Equivalents		—			(3	)
Cash and Cash Equivalents at Beginning of Period		4			7
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	4		$	4
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash received (paid) for income taxes (includes payments (to) from PHI for federal income taxes)	$	18		$	(1	)

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ATLANTIC CITY ELECTRIC COMPANY

(1)ORGANIZATION

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

(2) SIGNIFICANT ACCOUNTING POLICIES

Financial Statement Presentation

ACE’s unaudited Consolidated Financial Statements are prepared in conformity with accounting principles generally accepted in the United States of America (GAAP). Pursuant to the rules and regulations of the Securities and Exchange Commission, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been omitted. Therefore, these financial statements should be read along with the annual financial statements included in ACE’s Annual Report on Form 10-K for the year ended December 31, 2010. In the opinion of ACE’s management, the Consolidated Financial Statements contain all adjustments (which all are of a normal recurring nature) necessary to present fairly ACE’s financial condition as of June 30, 2011, in accordance with GAAP. The year-end December 31, 2010 Consolidated Balance Sheet was derived from audited financial statements, but does not include all disclosures required by GAAP. Interim results for the three and six months ended June 30, 2011 may not be indicative of results that will be realized for the full year ending December 31, 2011 since the sales of electric energy are seasonal.

Use of Estimates

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

Significant matters that involve the use of estimates include the assessment of contingencies, the calculation of future cash flows and fair value amounts for use in asset impairment evaluations, pension and other postretirement benefits assumptions, unbilled revenue calculations, the assessment of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of restructuring charges, recognition of changes in network service transmission rates for prior service year costs, accrual of self-insurance reserves for general and auto liability claims and income tax provisions and reserves. Additionally, ACE is subject to legal, regulatory, and other proceedings and claims that arise in the ordinary course of its business. ACE records an estimated liability for these proceedings and claims when it is probable that a loss has been incurred and the loss is reasonably estimable.

Network Service Transmission Rates

In May 2011, ACE filed its network service transmission rates with the Federal Energy Regulatory Commission to be effective for the service year beginning June 1, 2011. The new rates include an adjustment for costs incurred in the service year ended May 31, 2011 that were not reflected in the rates charged to customers for that service year. In the second quarter of 2011, ACE recorded a $1 million increase in transmission revenues as a change to the estimates recorded in previous periods primarily due to an increase in actual rate base versus estimated rate base.

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General and Auto Liability

During the second quarter of 2011, ACE reduced its self-insurance reserves for general and auto liability claims by approximately $1 million, based on obtaining an actuarial estimate of the unpaid loss attributed to general and auto liability claims for ACE at June 30, 2011.

Consolidation of Variable Interest Entities

ACE Power Purchase Agreements (PPAs)

ACE is a party to three PPAs with unaffiliated, non-utility generators (NUGs). ACE was unable to obtain sufficient information to determine whether these three entities were variable interest entities or if ACE was the primary beneficiary and as a result has applied the scope exemption from the consolidation guidance for enterprises that have not been able to obtain such information.

Net purchase activities with the NUGs for the three months ended June 30, 2011 and 2010 were approximately $55 million and $67 million, respectively, of which approximately $51 million and $62 million, respectively, consisted of power purchases under the PPAs. Net purchase activities with the NUGs for the six months ended June 30, 2011 and 2010 were approximately $112 million and $140 million, respectively, of which approximately $104 million and $129 million, respectively, consisted of power purchases under the PPAs. The power purchase costs are recoverable from ACE’s customers through regulated rates.

Atlantic City Electric Transitional Funding LLC

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

ACE Standard Offer Capacity Agreements

On April 28, 2011, ACE entered into three Standard Offer Capacity Agreements (SOCAs) by order of the NJBPU, each with a different generation company. The SOCAs were established under a New Jersey law enacted to promote the construction of qualified electric generation facilities in New Jersey. The SOCAs are 15-year, financially settled transactions approved by the NJBPU that allow generators to receive payments from, or make payments to, ACE based on the difference between the fixed price in the SOCAs and the price for capacity that clears PJM Interconnection, LLC (PJM). Each of the other electricity distribution companies (EDCs) in New Jersey has entered into SOCAs having the same terms with the same generation companies. The annual share of payments or receipts for ACE and the other EDCs is based upon each company’s annual proportion of the total New Jersey load attributable to all EDCs. ACE and the other EDCs entered the

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SOCAs under protest based on concerns about the potential cost to distribution customers. On May 16, 2011, the NJBPU denied a joint motion for reconsideration of its order requiring each of the EDCs to enter into the SOCAs. On June 24, 2011, ACE and the other EDCs filed appeals from the NJBPU orders with the Appellate Division of the New Jersey Superior Court.

The SOCAs are associated with the construction of three distinct combined cycle, natural gas generation facilities with an aggregate capacity of 1,949 megawatts, of which ACE’s share would be approximately 15 percent, or 292 megawatts. The obligation to make payments is conditioned upon the clearance of capacity from a generation facility through PJM, and the earliest capacity auction would be in May 2012 based upon the estimated June 1, 2015 operational date for two of the facilities followed by a capacity auction in May 2013 for the third facility that has an estimated June 1, 2016 operational date. Payments would begin after a facility is operational. The NJBPU has approved full recovery from distribution customers of payments made by ACE and the other EDCs, and distribution customers would be entitled to any payments received by ACE and the other EDCs.

Currently, PHI believes that Financial Accounting Standards Board (FASB) guidance on derivative accounting and the accounting for regulated operations would apply to a SOCA once capacity has cleared a PJM auction. Once cleared, the gain (loss) associated with the fair value of a derivative would be offset by the establishment of a regulatory liability (asset).

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in ACE’s gross revenues were $5 million for each of the three months ended June 30, 2011 and 2010, and $10 million for each of the six months ended June 30, 2011 and 2010.

Reclassifications and Adjustments

Certain prior period amounts have been reclassified in order to conform to the 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 2011, ACE completed a reconciliation of its deferred taxes associated with certain regulatory assets and recorded adjustments which resulted in an increase to income tax expense of $1 million.

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

(3)NEWLY ADOPTED ACCOUNTING STANDARDS

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

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

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(4)RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Fair Value Measurements and Disclosures (ASC 820)

In May 2011, the FASB issued new guidance on fair value measurement and disclosures that will be effective beginning with ACE’s March 31, 2012 financial statements. The new guidance would change how fair value is measured in specific instances and expand disclosures about fair value measurements. ACE is evaluating the impact of this new 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, 2011 and 2010, before intercompany allocations from the PHI Service Company, were $19 million and $31 million, respectively. ACE’s allocated share was $4 million and $7 million, respectively, for the three months ended June 30, 2011 and 2010. PHI’s pension and other postretirement net periodic benefit cost for the six months ended June 30, 2011 and 2010, before intercompany allocations from the PHI Service Company, were $46 million and $60 million, respectively. ACE’s allocated share was $10 million and $11 million, respectively, for the six months ended June 30, 2011 and 2010.

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

(7) DEBT

Credit Facility

The principal credit source for PHI and its utility subsidiaries is an unsecured $1.5 billion syndicated credit facility, which can be used to borrow funds, obtain letters of credit and support the issuance of commercial paper. As of June 30, 2011, PHI’s credit limit under the facility was $875 million and the credit limit for each of Potomac Electric Power Company (Pepco), Delmarva Power & Light Company (DPL) and ACE was the lesser of $500 million and the maximum amount of debt each company was permitted to have outstanding by its regulatory authorities, except that the aggregate amount of credit used by Pepco, DPL and ACE collectively, at any given time, could not exceed $625 million. On August 1, 2011, PHI, Pepco, DPL and ACE entered into an amendment and restatement of the credit agreement with respect to the facility, which among other changes extends the expiration date of the facility from May 2, 2012, to August 1, 2016. The facility, as amended and restated is more fully described below under the heading “Financing Activities Subsequent to June 30, 2011.” PHI also has two bi-lateral 364 day unsecured credit agreements totaling $200 million. Under each of the credit agreements, PHI has access to revolving and floating rate loans over the terms of the agreements. Neither agreement provides for the issuance of letters of credit. Both agreements expire on October 26, 2011.

At June 30, 2011 and December 31, 2010, the aggregate amount of cash plus unused borrowing capacity under the $1.5 billion credit facility available to meet the future liquidity needs of PHI’s utility subsidiaries was $595 million and $462 million, respectively.

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ACE

Financing Activities

In April 2011, ACE Funding made principal payments of $6 million on its Series 2002-1 Bonds, Class A-2 and A-3, and $2 million on its Series 2003-1 Bonds, Class A-2.

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

Financing Activities Subsequent to June 30, 2011

In July 2011, ACE Funding made principal payments of $6 million on its Series 2002-1 Bonds, Class A-3, and $2 million on its Series 2003-1 Bonds, Class A-2.

On August 1, 2011, PHI, Pepco, DPL and ACE entered into an amendment and restatement of their $1.5 billion credit facility to extend the expiration date to August 1, 2016, and to make various other changes. As amended and restated, all or any portion of the facility may be used to obtain revolving loans and up to $500 million may be used to obtain letters of credit. PHI’s credit sublimit under the facility is $750 million and the sublimit of each of Pepco, DPL and ACE is $250 million. The borrowers may increase or decrease their respective sublimits during the term of the facility, except that (i) the sum of all of the borrower sublimits following any such increase or decrease must equal the total amount of the facility and (ii) the aggregate amount of credit used at any given time by (a) PHI may not exceed $1.25 billion and (b) each of Pepco, DPL or ACE may not exceed the lesser of $500 million and the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of sublimit reallocations cannot exceed eight per fiscal year during the term of the agreement.

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, the federal funds effective rate plus 0.5% and one month LIBOR plus 1.0%, 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 10% of the total amount of the facility. Any swingline loan must be repaid by the borrower within fourteen days of receipt thereof. All indebtedness incurred under the facility is unsecured.

(8) INCOME TAXES

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

	Three Months Ended June 30,									Six Months Ended June 30,
	2011				2010					2011					2010
Income tax at federal statutory rate	$	11	35.0	%	$	15		35.0	%	$	15		35.0	%	$	16		35.0	%
Increases (decreases) resulting from:																	��
State income taxes, net of federal effect		2	6.6			2		6.4			3		7.0			3		6.8
Depreciation		—	(0.3	)		—		(0.2	)		—		(0.5	)		—		(0.4	)
Tax credits		—	(0.6	)		—		(0.5	)		(1	)	(1.2	)		—		(1.1	)
Change in estimates and interest related to uncertain and effectively settled tax positions		—	1.3			(1	)	(2.1	)		1		1.4			4		8.9
Deferred tax adjustment		1	3.1			—		—			1		2.3			—		—
Other, net		—	(1.3	)		—		(0.5	)		—		0.2			—		(0.3	)
Consolidated income tax expense	$	14	43.8	%	$	16		38.1	%	$	19		44.2	%	$	23		48.9	%

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ACE

ACE’s consolidated effective tax rates for the three months ended June 30, 2011 and 2010 were 43.8% and 38.1%, respectively. The increase in the effective tax rate primarily resulted from changes in estimates and interest related to uncertain and effectively settled tax positions.

During the second quarter of 2011, PHI reached a settlement with the Internal Revenue Service (IRS) with respect to interest due on its federal tax liabilities related to the November 2010 audit settlement for years 1996 through 2002. In connection with this agreement, PHI reallocated certain amounts that have been on deposit with the IRS since 2006 among liabilities in the settlement years and subsequent years. Primarily related to the settlement and reallocations, ACE has recorded an additional $1 million (after-tax) of interest due to the IRS. This additional interest expense was recorded in the second quarter of 2011. Also during the second quarter of 2011, ACE completed a reconciliation of its deferred taxes on certain regulatory assets and, as a result, recorded a $1 million increase to income tax expense as shown in the “Deferred Tax Adjustment” line above.

ACE’s consolidated effective tax rates for the six months ended June 30, 2011 and 2010 were 44.2% and 48.9%, respectively. The decrease in the effective tax rate primarily resulted from the reversal of $6 million of accrued interest income on uncertain and effectively settled state income tax positions in 2010.

(9)PREFERRED STOCK

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

(10) FAIR VALUE DISCLOSURES

Financial Instruments Measured at Fair Value on a Recurring Basis

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

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

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

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

	Fair Value Measurements at June 30, 2011
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)(a)		Significant Other Observable Inputs (Level 2)(a)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Cash equivalents
Treasury Fund	$	20	$	20	$	—	$	—
	$	20	$	20	$	—	$	—
LIABILITIES
Executive deferred compensation plan liabilities
Life Insurance Contracts	$	1	$	—	$	1	$	—
	$	1	$	—	$	1	$	—

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

	Fair Value Measurements at December 31, 2010
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)(a)		Significant Other Observable Inputs (Level 2)(a)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Cash equivalents
Treasury Fund	$	17	$	17	$	—	$	—
	$	17	$	17	$	—	$	—
LIABILITIES
Executive deferred compensation plan liabilities
Life Insurance Contracts	$	1	$	—	$	1	$	—
	$	1	$	—	$	1	$	—

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

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ACE

Other Financial Instruments

The estimated fair values of ACE’s issued debt and equity instruments at June 30, 2011 and December 31, 2010 are shown below:

	June 30, 2011				December 31, 2010
	(millions of dollars)
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	833	$	921	$	633	$	710
Transition Bonds issued by ACE Funding		350		390		367		406
Redeemable Serial Preferred Stock		—		—		6		5

The fair value of long-term debt issued by ACE was based on actual trade prices as of June 30, 2011 and December 31, 2010. Where trade prices were not available, ACE used a discounted cash flow model to estimate fair value. The fair value of Transition Bonds issued by ACE Funding, including amounts due within one year, were derived based on bid prices obtained from brokers and validated by ACE because actual trade prices were not available.

The fair value of the Redeemable Serial Preferred Stock was derived based on quoted market prices.

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

(11) COMMITMENTS AND CONTINGENCIES

Regulatory and Other Matters

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 it would be included in its cost of service for ratemaking purposes.

Franklin Slag Pile Site. In November 2008, ACE received a general notice letter from the U.S. Environmental Protection Agency (EPA) concerning the Franklin Slag Pile site in Philadelphia, Pennsylvania, asserting that ACE is a potentially responsible party (PRP) that may have liability with respect to the site. If liable, ACE would be responsible for reimbursing EPA for clean-up costs incurred and to be incurred by the agency and for the costs of implementing an EPA-mandated remedy. EPA’s claims are based on ACE’s sale of boiler slag from the B.L. England generating facility, then owned by ACE, to MDC Industries, Inc. (MDC) during the period June 1978 to May 1983. EPA claims that the boiler slag ACE sold to MDC contained copper and lead, which are hazardous substances under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA), and that the sales transactions may have constituted an arrangement for the disposal or treatment of hazardous substances at the site, which could be a basis for liability under CERCLA. The EPA letter also states that, as of the date of the letter, EPA’s expenditures for response measures at the site have exceeded $6 million. EPA estimates the cost for future response measures will be approximately $6 million. ACE understands that EPA sent similar general notice letters to three other companies and various individuals.

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ACE

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

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

Price’s Pit Site. ACE owns a transmission and distribution right-of-way that traverses the Price’s Pit superfund site in Egg Harbor Township, New Jersey. EPA placed Price’s Pit on the NPL in 1983 and the New Jersey Department of Environmental Protection (NJDEP) undertook an environmental investigation to identify and implement remedial action at the site. NJDEP’s investigation revealed that landfill waste had been disposed on ACE’s right-of-way and NJDEP determined that ACE was a responsible party as the owner of a facility on which a hazardous substance has been deposited. ACE, EPA and NJDEP entered into a settlement agreement to resolve ACE’s alleged liability (which was fully executed as of June 21, 2011, but will not be effective until after a public notice period, which will close on August 5, 2011, and receipt by ACE of notice of effectiveness from EPA). The settlement agreement requires ACE to make a payment of approximately $1 million to the EPA Hazardous Substance Superfund and donate a four-acre parcel of land adjacent to the site to NJDEP.

Appeal of New Jersey Flood Hazard Regulations. In November 2007, NJDEP adopted amendments to the agency’s regulations under the Flood Hazard Area Control Act (FHACA) to minimize damage to life and property from flooding caused by development in flood plains. The amended regulations impose a new regulatory program to mitigate flooding and related environmental impacts from a broad range of construction and development activities, including electric utility transmission and distribution construction, which were previously unregulated under the FHACA. These regulations impose restrictions on construction of new electric transmission and distribution facilities and increase the time and personnel resources required to obtain permits and conduct maintenance activities. In November 2008, ACE filed an appeal of these regulations with the Appellate Division of the Superior Court of New Jersey. The grounds for ACE’s appeal include the lack of administrative record justification for the FHACA regulations and conflict between the FHACA regulations and other state and federal regulations and standards for maintenance of electric power transmission and distribution facilities. The Appellate Division’s decision upholding the amended FHACA regulations was issued on July 22, 2011. ACE currently is evaluating that ruling, including the financial impact related compliance with the amended regulations. Based on current information, PHI and ACE do not believe these regulations will have a material adverse effect on their respective financial conditions, results of operations or cash flows.

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ACE

(12)RELATED PARTY TRANSACTIONS

PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries, including ACE. The cost of these services is allocated in accordance with cost allocation methodologies set forth in the service agreement using a variety of factors, including the subsidiaries’ share of employees, operating expenses, assets, and other cost causal methods. These intercompany transactions are eliminated by PHI in consolidation and no profit results from these transactions at PHI. PHI Service Company costs directly charged or allocated to ACE for the three months ended June 30, 2011 and 2010 were approximately $24 million and $19 million, respectively. PHI Service Company costs directly charged or allocated to ACE for the six months ended June 30, 2011 and 2010 were approximately $48 million and $45 million, respectively.

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

	Three Months Ended June  30,						Six Months Ended June  30,
Income (Expense)	2011			2010			2011			2010
	(millions of dollars)
Purchased power under Default Electricity Supply contracts with Conectiv Energy Supply, Inc. (CESI) (a) (b)	$	—		$	(41	)	$	—		$	(80	)
Meter reading services provided by Millennium Account Services LLC (c)		(1	)		(1	)		(2	)		(2	)

(a) Included in purchased energy expense.

(b) During 2010, PHI disposed of its Conectiv Energy segment and a third party assumed CESI’s responsibilities under these contracts.

(c) Included in other operation and maintenance expense.

As of June 30, 2011 and December 31, 2010, ACE had the following balances on its Consolidated Balance Sheets due to related parties:

Liability	June 30, 2011			December 31, 2010
	(millions of dollars)
Payable to Related Party (current) (a)
PHI Service Company	$	(10	)	$	(13	)
Conectiv Energy Supply, Inc.		—			(14	)
Other		(1	)		(2	)
Total	$	(11	)	$	(29	)

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

(13)RESTRUCTURING CHARGE

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

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ACE

In connection with the restructuring plan, ACE recorded a pre-tax restructuring charge of $6 million in 2010 related to its allocation of severance, pension, and health and welfare benefits for the termination of corporate services employees at PHI. The severance, pension, and health and welfare benefits were estimated based on the years of service and compensation levels of the employees associated with the 164 eliminated positions at PHI. The restructuring charge was reflected as a separate line item in the Consolidated Statement of Income for the year ended December 31, 2010.

A reconciliation of ACE’s accrued restructuring charges for the three and six months ended June 30, 2011 is as follows:

	Three Months Ended June 30, 2011
	(millions of dollars)
Beginning balance as of April 1, 2011	$	2
Restructuring charge		—
Cash payments		(1	)
Ending balance as of June 30, 2011	$	1

	Six Months Ended June 30, 2011
	(millions of dollars)
Beginning balance as of January 1, 2011	$	6
Restructuring charge		—
Cash payments		(5	)
Ending balance as of June 30, 2011	$	1

102

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		104
Pepco		140
DPL		149
ACE		158

103

PEPCO HOLDINGS

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

Pepco Holdings, Inc.

General Overview

Pepco Holdings, Inc. (PHI or Pepco Holdings), a Delaware corporation incorporated in 2001, is a holding company that is engaged primarily in the transmission, distribution and default supply of electricity and the distribution and supply of natural gas through its regulated public utility subsidiaries (Power Delivery). Through Pepco Energy Services, Inc. and its subsidiaries (collectively, Pepco Energy Services), PHI provides energy efficiency services primarily to government and institutional customers and is in the process of winding down its competitive electricity and natural gas retail supply business. Each of Power Delivery and Pepco Energy Services constitutes a separate segment for financial reporting purposes. A third segment, Other Non-Regulated, owns a portfolio of seven cross-border energy lease investments.

The following table sets forth the percentage contributions to consolidated operating revenue and consolidated operating income from continuing operations attributable to the Power Delivery, Pepco Energy Services and Other Non-Regulated segments. Power Delivery Electric consists primarily of the transmission, distribution and default supply of electricity, and Power Delivery Gas consists of the delivery and supply of natural gas.

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Percentage of Consolidated Operating Revenue
Power Delivery		78	%		70	%		77	%		70	%
Pepco Energy Services		22	%		29	%		22	%		30	%
Other Non-Regulated		—			1	%		1	%		—
Percentage of Consolidated Operating Income
Power Delivery		67	%		79	%		72	%		76	%
Pepco Energy Services		6	%		12	%		8	%		15	%
Other Non-Regulated		27	%		9	%		20	%		9	%
Percentage of Power Delivery Operating Revenue
Power Delivery Electric		96	%		97	%		94	%		95	%
Power Delivery Gas		4	%		3	%		6	%		5	%

Power Delivery

The Power Delivery business is conducted by PHI’s three regulated public utility subsidiaries: Potomac Electric Power Company (Pepco), Delmarva Power & Light Company (DPL), and Atlantic City Electric Company (ACE). Each utility is regulated in the jurisdictions that comprise its service territory. Each utility is responsible for the distribution of electricity and, in the case of DPL, natural gas in its service territory, for which it is paid tariff rates established by the applicable local public service commission. Each utility 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 HOLDINGS

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

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

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

Reliability Enhancement Plans

During 2010, Pepco announced Comprehensive Reliability Enhancement Plans for Maryland and the District of Columbia. Each plan advances work on existing programs and initiates new activities for customers in the respective jurisdictions. These programs include enhanced vegetation management, identification and upgrading of underperforming feeder lines, addition of new facilities to support load growth, installation of distribution automation systems, replacement of underground residential cables, improvements to substation supply lines and selective undergrounding of existing above-ground service lines. By focusing on these areas, Pepco plans to increase the reliability of the distribution system by reducing both the frequency and the duration of power outages. Pepco’s progress on this plan includes increasing tree-trimming personnel (including contractors) from 80 to 350, trimming trees along more than 2,200 miles of power lines, and replacing or upgrading over 150 miles of underground cable.

The incremental cost of the reliability improvements over the next five years associated with Pepco’s Comprehensive Reliability Enhancement Plans for Maryland and the District of Columbia, a substantial portion of which would be capitalized, is estimated to be $100 million in the Maryland service territory and $90 million in the District of Columbia service territory. The total amount of the expenditures may change when anticipated regulations imposing reliability standards are promulgated in Maryland and upon the completion of Pepco’s analysis of the recently adopted modifications to the reliability standards in the District of Columbia.

Pepco Energy Services

Pepco Energy Services is engaged in the Energy Services business, which is comprised of providing energy efficiency services principally to federal, state and local government customers, and designing, constructing and operating combined heat and power and central energy plants and providing high voltage electric construction and maintenance services to customers throughout the United States and low voltage electric construction and maintenance services and streetlight construction and asset management services to utilities, municipalities and other customers in the Washington, D.C. metropolitan area.

105

PEPCO HOLDINGS

Pepco Energy Services also owns and operates two oil-fired generation facilities that are scheduled for deactivation in May 2012.

In December 2009, PHI announced the wind down of the retail energy supply component of the Pepco Energy Services business. Pepco Energy Services is implementing this wind down by not entering into any new supply contracts, while continuing to perform under its existing supply contracts through their expiration dates. The retail energy supply business has historically generated a substantial portion of the operating revenues and net income of the Pepco Energy Services segment. Operating revenues related to the retail energy supply business for the three months ended June 30, 2011 and 2010 were $231 million and $401 million, respectively, while operating income for the same periods was $4 million and $10 million, respectively. Operating revenues related to the retail energy supply business for the six months ended June 30, 2011 and 2010 were $536 million and $898 million, respectively, while operating income for the same periods was $16 million and $31 million, respectively.

In connection with the operation of the retail energy supply business, Pepco Energy Services provided letters of credit of $62 million and posted net cash collateral of $76 million as of June 30, 2011. These collateral requirements, which are based on existing wholesale energy purchase and sale contracts and current market prices, will decrease as the contracts expire, with the collateral expected to be fully released by June 1, 2014. The Energy Services business will not be affected by the wind down of the retail energy supply business.

PHI expects the retail energy supply business to remain profitable through December 31, 2012, based on its existing contract backlog and its corresponding portfolio of wholesale hedges, and PHI expects to record only immaterial losses beyond that date. Substantially all of Pepco Energy Services’ retail customer obligations will be fully performed by June 1, 2014.

Other Non-Regulated

Through its subsidiary Potomac Capital Investment Corporation, PHI maintains a portfolio of cross-border energy lease investments with a book value at June 30, 2011 of approximately $1.3 billion. In June 2011, PCI completed the early termination of all of the leases comprising one lease investment and a small portion of the leases comprising another lease investment. PCI received $161 million in net cash proceeds and recorded an after-tax gain of $3 million from these early terminations. For a discussion of PHI’s cross-border energy lease investments, see Note (7), “Leasing Activities” and Note (15), “Commitments and Contingencies—Regulatory and Other Matters – PHI’s Cross-Border Energy Lease Investments,” to the Consolidated Financial Statements of PHI set forth in Part I, Item 1 of this Form 10-Q.

Discontinued Operations

In April 2010, the Board of Directors of PHI approved a plan for the disposition of Conectiv Energy, which was comprised of Conectiv Energy Holding Company and its subsidiaries. On July 1, 2010, PHI completed the sale of Conectiv Energy’s wholesale power generation business to Calpine Corporation (Calpine) for $1.64 billion. The disposition of all of Conectiv Energy’s remaining assets and businesses not included in the Calpine sale, including its load service supply contracts, energy hedging portfolio and certain tolling agreements, has been substantially completed. The operations of Conectiv Energy, which previously comprised a separate segment for financial reporting purposes, have been classified as a discontinued operation in PHI’s Consolidated Statements of Income for each of the three and six months ended June 30, 2011 and 2010. Accordingly, in this Management’s Discussion and Analysis of Financial Condition and Results of Operations, all references to continuing operations exclude the operations of the former Conectiv Energy segment.

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Earnings Overview

Three Months Ended June 30, 2011 Compared to Three Months Ended June 30, 2010

PHI’s net income from continuing operations for the three months ended June 30, 2011 was $95 million, or $0.42 per share, compared to $76 million, or $0.34 per share, for the three months ended June 30, 2010.

PHI’s net loss from discontinued operations for the three months ended June 30, 2011 was $1 million, or less than one cent per share, compared to a net loss of $130 million, or $0.58 per share, for the three months ended June 30, 2010.

PHI’s net income (loss) for the three months ended June 30, 2011 and 2010, by operating segment, is set forth in the table below

(in millions of dollars):

	2011			2010			Change
Power Delivery	$	72		$	65		$	7
Pepco Energy Services		8			10			(2	)
Other Non-Regulated		19			6			13
Corporate and Other		(4	)		(5	)		1
Net Income from Continuing Operations		95			76			19
Discontinued Operations		(1	)		(130	)		129
Total PHI Net Income (Loss)	$	94		$	(54	)	$	148

Discussion of Operating Segment Net Income Variances:

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

• $13 million increase primarily due to an audit settlement with the Internal Revenue Service (IRS) for tax years 1996 through 2002, and a reallocation of deposits with the IRS with respect to tax liabilities in the settlement years and subsequent years.

• $8 million increase associated with higher Default Electricity Supply margins, primarily resulting from an approval by the District of Columbia Public Service Commission (DCPSC) of an increase in Pepco’s cost recovery rate for providing Standard Offer Service (SOS) in the District of Columbia, and an adjustment to DPL’s operating and maintenance expense for providing SOS in Delaware.

• $5 million increase from higher distribution revenue primarily due to distribution rate increases (Pepco in Maryland effective July 2010; DPL in Delaware effective February 2011; and ACE in New Jersey effective June 2010).

• $14 million decrease due to higher operating and maintenance expenses primarily from increased system preventive maintenance and reliability activity.

• $5 million decrease associated with ACE Basic Generation Service primarily attributable to a decrease in unbilled revenue.

Pepco Energy Services’ $2 million decrease in earnings is primarily due to lower capacity revenues from the generating facilities and mark-to-market losses on derivative contracts, partially offset by higher revenues from energy services and high-voltage construction activities, and lower credit related costs.

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Other Non-Regulated’s $13 million increase in earnings is primarily due to favorable income tax adjustments and the gain on the early termination of certain cross-border energy leases.

Corporate and Other’s $1 million decrease in net loss is primarily due to lower interest expense as the result of the reduction in outstanding debt due to the retirement of debt with the Conectiv Energy sale proceeds, offset by favorable income tax adjustments in 2010 from the release of certain deferred tax valuation allowances related to state net operating losses.

The $129 million decrease in the net loss from discontinued operations for the three months ended June 30, 2011 as compared to June 30, 2010 was primarily due to the 2010 write-down associated with the anticipated sale of the wholesale power generation business to Calpine and unrealized losses on derivative instruments no longer qualifying for cash flow hedge accounting, partially offset by gains in the 2010 period from sales of load service supply contracts.

Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010

PHI’s net income from continuing operations for the six months ended June 30, 2011 was $157 million, or $0.69 per share, compared to $104 million, or $0.47 per share, for the six months ended June 30, 2010.

PHI’s net income from discontinued operations for the six months ended June 30, 2011 was $1 million, or $0.01 per share, compared to a net loss of $122 million, or $0.55 per share, for the six months ended June 30, 2010.

PHI’s net income (loss) for the six months ended June 30, 2011 and 2010, by operating segment, is set forth in the table below (in millions of dollars):

	2011			2010			Change
Power Delivery	$	119		$	85		$	34
Pepco Energy Services		18			23			(5	)
Other Non-Regulated		25			10			15
Corporate and Other		(5	)		(14	)		9
Net Income from Continuing Operations		157			104			53
Discontinued Operations		1			(122	)		123
Total PHI Net Income (Loss)	$	158		$	(18	)	$	176

Discussion of Operating Segment Net Income Variances:

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

• $21 million increase primarily due to an audit settlement with the IRS for tax years 1996 through 2002 and a reallocation of deposits with the IRS with respect to tax liabilities in the settlement years and subsequent years, and unfavorable income tax adjustments in 2010 related to interest on uncertain and effectively settled tax positions.

• $19 million increase from higher distribution revenue primarily due to distribution rate increases (Pepco in the District of Columbia effective March 2010 and in Maryland effective July 2010; DPL in Delaware effective April 2010 and February 2011; and ACE in New Jersey effective June 2010).

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

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• $11 million increase associated with higher Default Electricity Supply margins, primarily resulting from an approval by the DCPSC of an increase in Pepco’s cost recovery rate for providing SOS in the District of Columbia, and an adjustment to DPL’s operating and maintenance expense for providing SOS in Delaware.

• $26 million decrease due to higher operating and maintenance expenses primarily from increased system preventive maintenance and reliability activity.

Pepco Energy Services’ $5 million decrease in earnings is primarily due to lower capacity revenues from the generating facilities and mark-to-market losses on derivative contracts, partially offset by higher revenues from energy services and high-voltage construction activities, and lower credit related costs.

Other Non-Regulated’s $15 million increase in earnings is primarily due to favorable income tax adjustments and the gain on the early termination of certain cross-border energy leases.

Corporate and Other’s $9 million decrease in net loss is primarily due to lower interest expense as the result of the reduction in outstanding debt due to the retirement of debt with the Conectiv Energy sale proceeds, partially offset by favorable income tax adjustments in 2010 from the release of certain deferred tax valuation allowances related to state net operating losses.

The $123 million decrease in the net loss from discontinued operations for the six months ended June 30, 2011 as compared to June 30, 2010 was primarily due to the 2010 write-down associated with the anticipated sale of the wholesale power generation business to Calpine and unrealized losses on derivative instruments no longer qualifying for cash flow hedge accounting, partially offset by gains in the 2010 period from sales of load service supply contracts.

Consolidated Results of Operations

The following results of operations discussion is for the three months ended June 30, 2011, compared to the three months ended June 30, 2010. All amounts in the tables (except sales and customers) are in millions of dollars.

Continuing Operations

Operating Revenue

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

	2011			2010			Change
Power Delivery	$	1,093		$	1,149		$	(56	)
Pepco Energy Services		308			476			(168	)
Other Non-Regulated		14			13			1
Corporate and Other		(6	)		(2	)		(4	)
Total Operating Revenue	$	1,409		$	1,636		$	(227	)

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Power Delivery Business

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

	2011		2010		Change
Regulated T&D Electric Revenue	$	455	$	449	$	6
Default Electricity Supply Revenue		582		646		(64	)
Other Electric Revenue		17		18		(1	)
Total Electric Operating Revenue		1,054		1,113		(59	)
Regulated Gas Revenue		26		24		2
Other Gas Revenue		13		12		1
Total Gas Operating Revenue		39		36		3
Total Power Delivery Operating Revenue	$	1,093	$	1,149	$	(56	)

Regulated Transmission and Distribution (T&D) Electric Revenue includes revenue from the distribution of electricity, including the distribution of Default Electricity Supply, by PHI’s utility subsidiaries to customers within their service territories at regulated rates. Regulated T&D Electric Revenue also includes transmission service revenue that PHI’s utility subsidiaries receive as transmission owners from PJM Interconnection, LLC (PJM) at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.

Default Electricity Supply Revenue is the revenue received from the supply of electricity by PHI’s utility subsidiaries at regulated rates to retail customers who do not elect to purchase electricity from a competitive energy supplier. Depending on the jurisdiction, Default Electricity Supply is also known as Standard Offer Service or Basic Generation Service (BGS). The costs related to Default Electricity Supply are included in “Fuel and Purchased Energy.” Default Electricity Supply Revenue also includes revenue from Transition Bond Charges that ACE receives, and pays to Atlantic City Electric Transitional Funding LLC (ACE Funding), to fund the principal and interest payments on Transition Bonds issued by ACE Funding and revenue in the form of transmission enhancement credits that PHI utility subsidiaries receive as transmission owners from PJM for approved regional transmission expansion plan costs (Transmission Enhancement Credits).

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

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.

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Regulated T&D Electric

	2011		2010		Change
Regulated T&D Electric Revenue
Residential	$	154	$	149	$	5
Commercial and industrial		223		224		(1	)
Other		78		76		2
Total Regulated T&D Electric Revenue	$	455	$	449	$	6

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

	2011		2010		Change
Regulated T&D Electric Sales (Gigawatt hours (GWh))
Residential		3,855		3,773		82
Commercial and industrial		7,913		8,227		(314	)
Other		55		56		(1	)
Total Regulated T&D Electric Sales		11,823		12,056		(233	)

	2011		2010		Change
Regulated T&D Electric Customers (in thousands)
Residential		1,635		1,628		7
Commercial and industrial		198		198		—
Other		2		2		—
Total Regulated T&D Electric Customers		1,835		1,828		7

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 $6 million primarily due to:

• An increase of $7 million due to distribution rate increases (Pepco in the District of Columbia effective March 2010 and July 2010, and in Maryland effective July 2010; and ACE in New Jersey effective June 2010).

• An increase of $5 million due to higher pass-through revenue (which is substantially offset by a corresponding increase in Other Taxes) primarily the result of rate increases in Montgomery County, Maryland utility taxes that are collected by Pepco on behalf of the county.

• An increase of $2 million due to Pepco customer growth of 1% in 2011, primarily in the residential class.

• An increase of $1 million in non-weather related average customer usage.

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The aggregate amount of these increases was partially offset by:

• A decrease of $7 million due to an ACE New Jersey Societal Benefit Charge rate decrease that became effective in January 2011 (which is offset in Deferred Electric Service Costs).

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

Default Electricity Supply

	2011		2010		Change
Default Electricity Supply Revenue
Residential	$	376	$	418	$	(42	)
Commercial and industrial		165		188		(23	)
Other		41		40		1
Total Default Electricity Supply Revenue	$	582	$	646	$	(64	)

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

	2011		2010		Change
Default Electricity Supply Sales (GWh)
Residential		3,401		3,586		(185	)
Commercial and industrial		1,495		1,749		(254	)
Other		18		23		(5	)
Total Default Electricity Supply Sales		4,914		5,358		(444	)

	2011		2010		Change
Default Electricity Supply Customers (in thousands)
Residential		1,475		1,568		(93	)
Commercial and industrial		141		155		(14	)
Other		1		1		—
Total Default Electricity Supply Customers		1,617		1,724		(107	)

Default Electricity Supply Revenue decreased by $64 million primarily due to:

• A decrease of $47 million due to lower sales, primarily as a result of commercial and residential customer migration to competitive suppliers.

• A decrease of $30 million due to lower sales as a result of cooler weather during the 2011 spring months as compared to 2010.

• A net decrease of $20 million as a result of lower Pepco and DPL Default Electricity Supply rates, partially offset by higher ACE rates.

The aggregate amount of these decreases was partially offset by:

• An increase of $30 million due to higher non-weather related average customer usage.

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The decrease in total Default Electricity Supply Revenue includes a decrease of $10 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, 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, 2011, BGS unbilled revenue decreased by $10 million as compared to the three months ended June 30, 2010, which resulted in a $6 million decrease in PHI’s net income. The decrease was primarily due to lower customer usage and increased customer migration during the unbilled revenue period at the end of the three months ended June 30, 2011, as compared to the corresponding period in 2010.

Regulated Gas

	2011		2010		Change
Regulated Gas Revenue
Residential	$	16	$	14	$	2
Commercial and industrial		8		8		—
Transportation and other		2		2		—
Total Regulated Gas Revenue	$	26	$	24	$	2

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

	2011		2010		Change
Regulated Gas Customers (in thousands)
Residential		114		113		1
Commercial and industrial		9		9		—
Transportation and other		—		—		—
Total Regulated Gas Customers		123		122		1

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

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

• Industrial activity in the region includes chemical and pharmaceutical.

Regulated Gas Revenue increased by $2 million primarily due to:

• An increase of $2 million due to higher sales as a result of colder weather during the 2011 spring months as compared to 2010.

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

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The aggregate amount of these increases was partially offset by:

• A decrease of $1 million due to lower non-weather related average customer usage.

Pepco Energy Services

Pepco Energy Services’ operating revenue decreased by $168 million primarily due to:

• A decrease of $168 million due to lower retail supply sales volume primarily attributable to the ongoing wind down of the retail energy supply business.

• A decrease of $27 million due to lower capacity revenues at the generating facilities due to lower Reliability Pricing Model (RPM) clearing prices in the PJM auction.

The decrease is partially offset by:

• An increase of $26 million due to increased energy services and high voltage construction activities.

Operating Expenses

Fuel and Purchased Energy and Other Services Cost of Sales

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

	2011			2010			Change
Power Delivery	$	584		$	688		$	(104	)
Pepco Energy Services		269			427			(158	)
Corporate and Other		(1	)		(3	)		2
Total	$	852		$	1,112		$	(260	)

Power Delivery Business

Power Delivery’s Fuel and Purchased Energy consists of the cost of electricity and natural gas purchased by its utility subsidiaries to fulfill their respective Default Electricity Supply and Regulated Gas obligations and, as such, is recoverable from customers in accordance with the terms of public service commission orders. It also includes the cost of natural gas purchased for off-system sales. Fuel and Purchased Energy expense decreased by $104 million primarily due to:

• A decrease of $64 million due to lower average electricity costs under Default Electricity Supply contracts.

• A decrease of $29 million primarily due to customer migration to competitive suppliers.

• A decrease of $26 million due to lower electricity sales primarily as a result of cooler weather during the 2011 spring months as compared to 2010.

The aggregate amount of these decreases was partially offset by:

• An increase of $13 million in deferred electricity expense primarily due to lower average electricity costs under Default Electricity Supply contracts, which resulted in a higher rate of recovery of Default Electricity Supply costs.

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Pepco Energy Services

Pepco Energy Services’ Fuel and Purchased Energy and Other Services Cost of Sales decreased $158 million primarily due to:

• A decrease of $127 million due to lower volumes of electricity purchased to serve decreased retail electricity sales volume as a result of the ongoing wind down of the retail energy supply business.

• A decrease of $37 million due to lower volumes of natural gas purchased to serve decreased retail natural gas volumes as a result of the ongoing wind down of the retail energy supply business.

• A decrease of $15 million due to decreased purchases of installed capacity and decreased fuel usage associated with the generating facilities.

The aggregate amount of these decreases was partially offset by:

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

Other Operation and Maintenance

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

	2011			2010			Change
Power Delivery	$	197		$	184		$	13
Pepco Energy Services		21			21			—
Corporate and Other		(9	)		(9	)		—
Total	$	209		$	196		$	13

Other Operation and Maintenance expense for Power Delivery increased by $13 million; however, excluding an increase of $1 million primarily related to New Jersey Societal Benefit Program costs that are deferred and recoverable, Other Operation and Maintenance expense increased by $12 million. The $12 million increase was primarily due to:

• An increase of $17 million primarily due to higher tree trimming and preventative maintenance costs.

• An increase of $5 million in customer support and communication costs.

• An increase of $3 million in emergency restoration costs.

• An increase of $3 million primarily due to emergency restoration improvement projects and reliability compliance costs.

The aggregate amount of these increases was partially offset by:

• A decrease of $8 million associated with certain adjustments recorded by PHI in the second quarter of 2011 to correct certain errors associated with the accounting for DPL Default Electricity Supply. These adjustments were primarily due to the under-recognition of allowed returns on the cost of working capital.

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

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

Depreciation and Amortization

Depreciation and Amortization expense increased by $12 million to $105 million in 2011 from $93 million in 2010 primarily due to:

• An increase of $6 million in amortization of stranded costs as the result of higher revenue due to rate increases effective October 2010 for the ACE Transition Bond Charge and the Market Transition Charge Tax (partially offset in Default Electricity Supply Revenue).

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

Other Taxes

Other Taxes increased by $4 million to $109 million in 2011 from $105 million in 2010. The increase was primarily due to rate increases in the Montgomery County, Maryland utility taxes that are collected and passed through by Pepco (substantially offset by a corresponding increase in Regulated T&D Electric Revenue).

Gain on Early Termination of Finance Leases Held in Trust

PHI’s operating expenses include a $39 million pre-tax gain for the three months ended June 30, 2011 associated with the early termination of several leases included in its cross-border energy lease portfolio.

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 $34 million, to an expense reduction of $29 million in 2011 as compared to an expense reduction of $63 million in 2010, primarily due to an increase in deferred electricity expense as a result of higher Default Electricity Supply revenue rates and lower electricity supply costs.

Other Income (Expenses)

Other Expenses (which are net of Other Income) decreased by $31 million primarily due to lower interest expense resulting from the reduction in outstanding long-term debt due to the retirement of debt in 2010 with the proceeds from the Conectiv Energy sale.

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Income Tax Expense

PHI’s consolidated effective tax rates from continuing operations for the three months ended June 30, 2011 and 2010 were 36.2% and 30.3%, respectively. The increase in the effective tax rate was primarily due to the impact of the early termination of certain cross border energy leases and the non-recurring tax benefit of the 2010 corporate restructuring. This increase was partially offset by interest benefits associated with the settlement with the Internal Revenue Service (IRS) discussed below (included in changes in estimates and interest related to uncertain and effectively settled tax positions) and a state tax benefit related to prior years’ asset dispositions.

As discussed further in Note (7), “Leasing Activities,” during the second quarter of 2011, PHI terminated early its interest in certain cross-border energy leases. As a result of the early terminations, PHI reversed $22 million of previously recognized income tax benefits associated with those leases which will not be realized due to the early termination.

In the second quarter of 2010, PHI recorded a non-recurring benefit related to the April 1, 2010 corporate restructuring. As a result of the restructuring, PHI recorded an $8 million decrease to its state deferred tax balances resulting from a change in state apportionment factors.

In the second quarter of 2011, PHI reached a settlement with the IRS with respect to interest due on its federal tax liabilities related to the November 2010 audit settlement for years 1996 through 2002. In connection with this agreement, PHI reallocated certain amounts that had been on deposit with the IRS since 2006 among liabilities in the settlement years and subsequent years. Primarily related to the settlement and reallocations, PHI has recorded an additional tax benefit in the amount of $17 million (after-tax). This additional interest income was recorded in the second quarter of 2011.

Also in the second quarter of 2011, PHI received refunds of approximately $5 million and recorded tax benefits of approximately $4 million (after-tax) related to the filing of amended state tax returns. These amended returns reduced state taxable income due to an increase in tax basis reported on certain prior years’ asset dispositions.

Discontinued Operations

For the three months ended June 30, 2011, the $1 million loss from discontinued operations, net of income taxes, includes an after-tax gain of $1 million arising from the sale of a tolling agreement in May 2011.

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.

Net losses from dispositions of assets and businesses of discontinued operations, net of income taxes of $132 million for the three ended June 30, 2010, includes (i) the after-tax loss on the sale of the wholesale power generation business to Calpine of $67 million, (ii) after-tax net losses on sales of assets and businesses not sold to Calpine of $51 million (inclusive of the recognition of after-tax unrealized losses on derivative contracts considered no longer probable to occur of $50 million recorded in the second quarter of 2010), and (iii) tax charges of $14 million for the establishment of valuation allowances against certain deferred tax assets primarily associated with state net operating losses, the remeasurement of deferred taxes for expected changes in state income tax apportionment factors, and the write-off of certain tax credit carryforwards no longer expected to be realized.

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The following results of operations discussion is for the six months ended June 30, 2011, compared to the six months ended June 30, 2010. All amounts in the tables (except sales and customers) are in millions of dollars.

Continuing Operations

Operating Revenue

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

	2011			2010			Change
Power Delivery	$	2,342		$	2,411		$	(69	)
Pepco Energy Services		681			1,023			(342	)
Other Non-Regulated		28			26			2
Corporate and Other		(8	)		(5	)		(3	)
Total Operating Revenue	$	3,043		$	3,455		$	(412	)

Power Delivery Business

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

	2011		2010		Change
Regulated T&D Electric Revenue	$	907	$	846	$	61
Default Electricity Supply Revenue		1,261		1,401		(140	)
Other Electric Revenue		33		33		—
Total Electric Operating Revenue		2,201		2,280		(79	)
Regulated Gas Revenue.		117		111		6
Other Gas Revenue		24		20		4
Total Gas Operating Revenue		141		131		10
Total Power Delivery Operating Revenue	$	2,342	$	2,411	$	(69	)

Regulated T&D Electric

	2011		2010		Change
Regulated T&D Electric Revenue
Residential.	$	322	$	298	$	24
Commercial and industrial		425		407		18
Other		160		141		19
Total Regulated T&D Electric Revenue	$	907	$	846	$	61

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

	2011		2010		Change
Regulated T&D Electric Sales (GWh)
Residential		8,630		8,650		(20	)
Commercial and industrial		15,218		15,428		(210	)
Other		123		124		(1	)
Total Regulated T&D Electric Sales		23,971		24,202		(231	)

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	2011		2010		Change
Regulated T&D Electric Customers (in thousands)
Residential		1,635		1,628		7
Commercial and industrial		198		198		—
Other		2		2		—
Total Regulated T&D Electric Customers		1,835		1,828		7

Regulated T&D Electric Revenue increased by $61 million primarily due to:

• An increase of $28 million due to distribution rate increases (Pepco in the District of Columbia effective March 2010 and July 2010, and in Maryland effective July 2010; DPL in Delaware effective April 2010; and ACE in New Jersey effective June 2010).

• An increase of $24 million due to higher pass-through revenue (which is substantially offset by a corresponding increase in Other Taxes) primarily the result of rate increases in Montgomery County, Maryland utility taxes that are collected by Pepco on behalf of the county.

• An increase of $19 million in transmission revenue primarily attributable to higher rates effective June 1, 2010 related to an increase in transmission plant investment.

• An increase of $3 million due to Pepco customer growth of 1% in 2011, primarily in the residential class.

The aggregate amount of these increases was partially offset by:

• A decrease of $13 million due to an ACE New Jersey Societal Benefit Charge rate decrease that became effective in January 2011 (which is offset in Deferred Electric Service Costs).

Default Electricity Supply

	2011		2010		Change
Default Electricity Supply Revenue
Residential	$	845	$	939	$	(94	)
Commercial and industrial		333		367		(34	)
Other		83		95		(12	)
Total Default Electricity Supply Revenue	$	1,261	$	1,401	$	(140	)

Other Default Electricity Supply Revenue consists primarily of (i) revenue from the resale by ACE in the PJM RTO market of energy and capacity purchased under contracts with unaffiliated NUGs, and (ii) revenue from Transmission Enhancement Credits.

	2011		2010		Change
Default Electricity Supply Sales (GWh)
Residential		7,699		8,266		(567	)
Commercial and industrial		3,053		3,504		(451	)
Other		37		48		(11	)
Total Default Electricity Supply Sales		10,789		11,818		(1,029	)

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		2011		2010		Change
Default Electricity Supply Customers (in thousands)
Residential			1,475		1,568		(93	)
Commercial and industrial			141		155		(14	)
Other			1		1		—
Total Default Electricity Supply Customers	��		1,617		1,724		(107	)

Default Electricity Supply Revenue decreased by $140 million primarily due to:

• A decrease of $99 million due to lower sales, primarily as a result of customer migration to competitive suppliers.

• A decrease of $31 million due to lower sales as a result of cooler weather during the 2011 spring months as compared to 2010.

• A net decrease of $25 million as a result of lower Pepco and DPL Default Electricity Supply rates, partially offset by higher ACE rates.

• A decrease of $7 million in wholesale energy and capacity resale revenues primarily due to the sale of lower volumes of electricity and capacity purchased from NUGs.

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

The aggregate amount of these decreases was partially offset by:

• An increase of $21 million due to higher non-weather related average customer usage.

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

The decrease in total Default Electricity Supply Revenue includes a decrease of $6 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, 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, 2011, BGS unbilled revenue decreased by $6 million as compared to the six months ended June 30, 2010, which resulted in a $4 million decrease in PHI’s net income. The decrease was primarily due to lower customer usage and increased customer migration during the unbilled revenue period at the end of the six months ended June 30, 2011, as compared to the corresponding period in 2010.

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Regulated Gas

	2011		2010		Change
Regulated Gas Revenue
Residential	$	73	$	69	$	4
Commercial and industrial		39		38		1
Transportation and other		5		4		1
Total Regulated Gas Revenue	$	117	$	111	$	6
	2011		2010		Change
Regulated Gas Sales (billion cubic feet)
Residential		5		5		—
Commercial and industrial		3		3		—
Transportation and other		4		3		1
Total Regulated Gas Sales		12		11		1
	2011		2010		Change
Regulated Gas Customers (in thousands)
Residential		114		113		1
Commercial and industrial		9		9		—
Transportation and other		—		—		—
Total Regulated Gas Customers		123		122		1

Regulated Gas Revenue increased by $6 million primarily due to:

• An increase of $16 million due to higher sales as a result of colder weather during the 2011 winter months as compared to 2010.

• An increase of $2 million due to distribution rate increases effective August 2010 and February 2011.

The aggregate amount of these increases was partially offset by:

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

Other Gas Revenue

Other Gas Revenue increased by $4 million primarily due to higher volumes of off-system sales to electric generators and gas marketers.

Pepco Energy Services

Pepco Energy Services’ operating revenue decreased by $342 million primarily due to:

• A decrease of $357 million due to lower retail supply sales volume primarily attributable to the ongoing wind down of the retail energy supply business.

• A decrease of $33 million due to lower capacity revenues at the generating facilities due to lower RPM clearing prices in the PJM auction.

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The aggregate amount of these decreases was partially offset by:

• An increase of $46 million due to increased energy services and high voltage construction activities.

Operating Expenses

Fuel and Purchased Energy and Other Services Cost of Sales

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

	2011		2010			Change
Power Delivery	$	1,290	$	1,505		$	(215	)
Pepco Energy Services		600		923			(323	)
Corporate and Other		—		(4	)		4
Total	$	1,890	$	2,424		$	(534	)

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 natural gas purchased for off-system sales. Fuel and Purchased Energy expense decreased by $215 million primarily due to:

• A decrease of $105 million primarily due to customer migration to competitive suppliers.

• A decrease of $101 million due to lower average electricity costs under Default Electricity Supply contracts.

• A decrease of $27 million due to lower electricity sales primarily as a result of cooler weather during the 2011 spring months as compared to 2010.

• A decrease of $6 million in the cost of gas purchases for on-system sales as a result of lower average gas prices.

• A decrease of $5 million from the settlement of financial hedges entered into as part of DPL’s hedge program for regulated natural gas.

The aggregate amount of these decreases was partially offset by:

• An increase of $14 million in deferred natural gas expense as a result of a higher rate of recovery of natural gas supply costs.

• An increase of $13 million in deferred electricity expense primarily due to lower average electricity costs under Default Electricity Supply contracts, which resulted in a higher rate of recovery of Default Electricity Supply costs.

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Pepco Energy Services

Pepco Energy Services’ Fuel and Purchased Energy and Other Services Cost of Sales decreased $323 million primarily due to:

• A decrease of $249 million due to lower volumes of electricity purchased to serve decreased retail electricity sales volume as a result of the ongoing wind down of the retail energy supply business.

• A decrease of $96 million due to lower volumes of natural gas purchased to serve decreased retail gas volumes as a result of the ongoing wind down of the retail energy supply business.

• A decrease of $17 million due to lower purchase of installed capacity and lower fuel usage associated with the generating facilities.

The aggregate amount of these decreases was partially offset by:

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

Other Operation and Maintenance

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

	2011			2010			Change
Power Delivery	$	419		$	382		$	37
Pepco Energy Services		42			42			—
Other Non-Regulated		2			2			—
Corporate and Other		(20	)		(16	)		(4	)
Total	$	443		$	410		$	33

Other Operation and Maintenance expense for Power Delivery increased by $37 million; however, excluding an increase of $3 million primarily related to New Jersey Societal Benefit Program costs and bad debt expenses that are deferred and recoverable, Other Operation and Maintenance expense increased by $34 million. This $34 million increase was primarily due to:

• An increase of $27 million primarily due to higher tree trimming and preventative maintenance costs.

• An increase of $6 million in customer support and communication costs.

• An increase of $3 million in emergency restoration costs.

• An increase of $3 million primarily due to emergency restoration improvement projects and reliability compliance costs.

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

• An increase of $2 million due to costs related to customer requested work.

The aggregate amount of these increases was partially offset by:

• A decrease of $8 million associated with certain adjustments recorded by PHI in the second quarter of 2011 to correct certain errors associated with the accounting for DPL Default Electricity Supply. These adjustments were primarily due to the under-recognition of allowed returns on the cost of working capital.

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

Depreciation and Amortization

Depreciation and Amortization expenses increased by $28 million to $210 million in 2011 from $182 million in 2010 primarily due to:

• An increase of $13 million in amortization of stranded costs as the result of higher revenue due to rate increases effective October 2010 for the ACE Transition Bond Charge and the Market Transition Charge Tax (partially offset in Default Electricity Supply Revenue).

• An increase of $7 million due to utility plant additions.

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

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

Other Taxes

Other Taxes increased by $23 million to $220 million in 2011 from $197 million in 2010. The increase was primarily due to rate increases in the Montgomery County, Maryland utility taxes that are collected and passed through by Pepco (substantially offset by a corresponding increase in Regulated T&D Electric Revenue).

Gain on Early Termination of Finance Leases Held in Trust

PHI’s operating expenses include a $39 million pre-tax gain for the six months ended June 30, 2011 associated with the early termination of several leases included in its cross-border energy lease portfolio.

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 $50 million, to an expense reduction of $32 million in 2011 as compared to an expense reduction of $82 million in 2010, primarily due to an increase in deferred electricity expense as a result of higher Default Electricity Supply revenue rates and lower electricity supply costs.

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Other Income (Expenses)

Other expenses (which are net of Other Income) decreased by $56 million primarily due to lower interest expense resulting from the reduction in outstanding long-term debt due to the retirement of debt in 2010 with the proceeds from the Conectiv Energy sale.

Income Tax Expense

PHI ’s consolidated effective tax rates from continuing operations for the six months ended June 30, 2011 and 2010 were 35.9% and 35.8%, respectively. While the effective tax rate was substantially unchanged between the two periods, the rate was affected by several offsetting items.

The effective tax rate increased in 2011 as a result of the negative impact of the June 2011 early termination of certain cross-border energy leases of $22 million discussed above, however, this increase was substantially offset by the $17 million benefit PHI recorded during the six months ended June 30, 2011, primarily resulting from the settlement with the IRS on interest due on its 1996 through 2002 audit settlement also discussed above, and the $4 million state tax benefit related to prior years’ asset dispositions.

The 2010 effective tax rate included the non-recurring impact of the April 2010 corporate restructuring. As a result of this restructuring, PHI recorded approximately $16 million of non-recurring tax benefits in 2010 including approximately $8 million resulting from a change in state apportionment factors and the release of $8 million of valuation allowances on deferred tax assets related to state net operating losses.

The effective tax rate in 2010 was also affected by changes in estimates and interest related to uncertain and effectively settled tax positions, primarily consisting of a non-recurring $2 million reversal of accrued interest income on state income tax positions in 2010 that PHI concluded was no longer more likely than not to be realized and the reversal of $6 million of erroneously accrued interest income in 2010 on uncertain and effectively settled state income tax positions, as discussed in Note (2), “Significant Accounting Policies.” The 2010 rate was further affected by the change in taxation of the Medicare Part D subsidy that increased PHI’s effective tax rate for the six months ended June 30, 2010. This change increased PHI’s first quarter 2010 tax expense by $4 million, which was partially offset through a reduction in Operating Expenses resulting in a $2 million decrease to net income.

Discontinued Operations

For the six months ended June 30, 2011, the $1 million income from discontinued operations, net of income taxes, includes after-tax income of $4 million arising from adjustments to certain accrued expenses for obligations associated with the sale of the wholesale power generation business to Calpine. These adjustments were made to reflect the actual amounts paid to Calpine during the first quarter of 2011. Income from discontinued operations, net of income taxes for the six months ended June 30, 2011 also includes a $1 million after-tax gain on the sale of a tolling agreement. Offsetting these amounts was an expense of approximately $1 million (after-tax) which was incurred in connection with the financial transaction entered into with a third party on January 6, 2011, under which Conectiv Energy transferred its remaining portfolio of derivatives, including financially settled natural gas and electric power transactions, for all remaining periods from February 1, 2011 forward. In connection with the closing of the transaction, Conectiv paid the third party $82 million, primarily representing the fair value of the derivatives at February 1, 2011, and an after-tax administrative fee of $1 million. No additional material gain or loss was recognized as a result of this transaction as the derivatives were previously marked to fair value through earnings in 2010.

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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.

Net losses from dispositions of assets and businesses of discontinued operations, net of income taxes of $130 million for the six months ended June 30, 2010, includes (i) the after-tax loss on the sale of the wholesale power generation business to Calpine of $67 million, (ii) after-tax net losses on sales of assets and businesses not sold to Calpine of $49 million (inclusive of the recognition of after-tax unrealized losses on derivative contracts considered no longer probable to occur of $50 million recorded in the second quarter of 2010), and (iii) tax charges of $14 million for the establishment of valuation allowances against certain deferred tax assets primarily associated with state net operating losses, the remeasurement of deferred taxes for expected changes in state income tax apportionment factors, and the write-off of certain tax credit carryforwards no longer expected to be realized.

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, 2011, Pepco Holdings’ current assets on a consolidated basis totaled $1.5 billion and its current consolidated liabilities totaled $1.6 billion, resulting in a working capital deficit of $66 million. PHI expects the working capital deficit at June 30, 2011 to be funded during 2011 through cash flow from operations and anticipated reductions in collateral requirements due to the ongoing wind down of the Pepco Energy Services retail energy supply business. At December 31, 2010, Pepco Holdings’ current assets on a consolidated basis totaled $1.8 billion and its current liabilities totaled $1.8 billion. The approximate $26 million decrease in working capital from December 31, 2010 to June 30, 2011 was due primarily to the decrease in prepayments of income taxes in addition to a decrease in the current portion of Conectiv Energy assets held for sale offset by the repayment of commercial paper with the proceeds from the early termination of several leases included in the cross-border lease portfolio.

At June 30, 2011, Pepco Holdings’ cash and cash equivalents totaled $58 million, which consisted of cash, uncollected funds, and cash equivalent investments of $41 million. Current restricted cash equivalents (cash that is available to be used only for designated purposes) totaled $11 million. At December 31, 2010, Pepco Holdings’ cash and cash equivalents totaled $21 million, of which $1 million is reflected on the Balance Sheet in Conectiv Energy assets held for sale, and its current restricted cash equivalents totaled $11 million.

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

	As of June 30, 2011
	(millions of dollars)
Type	PHI Parent		Pepco		DPL		ACE		ACE Funding		Pepco Energy Services		PHI Consolidated
Variable Rate Demand Bonds	$	—	$	—	$	105	$	23	$	—	$	18	$	146
Commercial Paper		224		—		—		25		—		—		249
Total Short-Term Debt	$	224	$	—	$	105	$	48	$	—	$	18	$	395
Current Maturities of Long-Term Debt and Project Funding	$	—	$	—	$	66	$	—	$	36	$	9	$	111

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	As of December 31, 2010
	(millions of dollars)
Type	PHI Parent		Pepco		DPL		ACE		ACE Funding		Pepco Energy Services		PHI Consolidated
Variable Rate Demand Bonds	$	—	$	—	$	105	$	23	$	—	$	18	$	146
Commercial Paper		230		—		—		158		—		—		388
Total Short-Term Debt	$	230	$	—	$	105	$	181	$	—	$	18	$	534
Current Maturities of Long-Term Debt and Project Funding	$	—	$	—	$	35	$	—	$	35	$	5	$	75

Financing Activity During the Three Months Ended June 30, 2011

In April 2011, ACE Funding made principal payments of $6 million on its Series 2002-1 Bonds, Class A-2 and A-3, and $2 million on its Series 2003-1 Bonds, Class A-2.

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

On June 1, 2011, DPL resold approximately $35 million of 0.75% Delaware Economic Development Authority tax-exempt bonds due May 1, 2026. The bonds were originally issued for the benefit of DPL in 2001 and were purchased by DPL on May 2, 2011 pursuant to a mandatory repurchase obligation triggered by the expiration of the original interest period for the bonds. The bonds are subject to mandatory purchase by DPL on June 1, 2012.

Credit Facilities

PHI, Pepco, DPL and ACE maintain an unsecured syndicated credit facility to provide for their respective liquidity needs, including obtaining letters of credit, and to support its commercial paper program. On August 1, 2011, PHI, Pepco, DPL and ACE entered into an amended and restated credit agreement with respect to the facility, which among other changes, extends the expiration date of the facility to August 1, 2016.

The aggregate borrowing limit under the amended and restated credit facility is $1.5 billion, all or any portion of which may be used to obtain loans and up to $500 million of which may be used to obtain letters of credit. 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 10% of the total amount of the facility. Any swingline loan must be repaid by the borrower within fourteen days of receipt. The credit sublimit for PHI is $750 million and $250 million for each of Pepco, DPL and ACE. The sublimits may be increased or decreased by the individual borrower during the term of the facility, except that (i) the sum of all of the borrower sublimits following any such increase or decrease must equal the total amount of the facility and (ii) the aggregate amount of credit used at any given time by (a) PHI may not exceed $1.25 billion and (b) each of Pepco, DPL or ACE may not exceed the lesser of $500 million and the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the sublimit reallocations may not exceed eight per year during the term of the facility.

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, the federal funds effective rate plus 0.5% and one month LIBOR plus 1.0%, or (ii) the prevailing Eurodollar rate, plus a margin that varies according to the credit rating of the borrower.

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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 financial covenants, including (i) the requirement that each borrowing company maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the credit agreement, which calculation excludes from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) a restriction on sales or other dispositions of assets, other than certain sales and dispositions, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than permitted liens. The amended and restated credit agreement contains certain covenants and other customary agreements and requirements that, if not complied with, could result in an event of default and the acceleration of repayment obligations of one or more of the borrowers thereunder. Each of the borrowers was in compliance with all financial covenants under this facility as of June 30, 2011.

PHI also maintains two bi-lateral 364-day unsecured credit agreements totaling $200 million. Under each of the credit agreements, PHI has access to revolving and floating rate loans over the terms of the agreements. Neither agreement provides for the issuance of letters of credit. Both agreements expire on October 26, 2011. The interest rate payable on funds borrowed is at PHI’s election, based on either (i) the prevailing Eurodollar rate plus 2.0% or (ii) the highest of (a) the prevailing prime rate, (b) the federal funds effective rate plus 0.5% or (c) the one-month Eurodollar rate plus 1.0%, plus a margin of 1.0%. In order to obtain loans under either of the agreements, PHI must be in compliance with the same covenants and conditions that it is required to satisfy for utilization of its existing $1.5 billion credit facility.

The absence of a material adverse change in PHI’s business, property, results of operations or financial condition is not a condition to the availability of credit under the $1.5 billion facility or either credit agreement. Neither the facility nor either of the credit agreements includes any rating triggers.

Financing Activities Subsequent to June 30, 2011

In July 2011, ACE Funding made principal payments of $6 million on its Series 2002-1 Bonds, Class A-3, and $2 million on its Series 2003-1 Bonds, Class A-2.

Cash and Credit Facilities Available as of June 30, 2011

	Consolidated PHI		PHI Parent		Utility Subsidiaries
	(millions of dollars)
Credit Facilities (Total Capacity)	$	1,700	$	1,075	$	625
Less: Letters of Credit issued		70		65		5
Commercial Paper outstanding		249		224		25
Remaining Credit Facilities Available		1,381		786		595
Cash Invested in Money Market Funds (a)		41		41		—
Total Cash and Credit Facilities Available	$	1,422	$	827	$	595

(a) Cash and cash equivalents reported on the PHI Consolidated Balance Sheet total $58 million, of which $41 million was invested in money market funds and the balance was held in cash and uncollected funds.

At June 30, 2011 and December 31, 2010, the aggregate amount of cash plus unused borrowing capacity under the credit facilities available to meet the combined future liquidity needs of Pepco Energy Services totaled $827 million and $728 million, respectively.

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Collateral Requirements of Pepco Energy Services

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

During periods of declining energy prices, Pepco Energy Services has been exposed to the asymmetrical risk of having to post collateral under its wholesale purchase contracts without receiving a corresponding amount of collateral from its retail customers. To partially address these asymmetrical collateral obligations, Pepco Energy Services, in the first quarter of 2009, entered into a credit intermediation arrangement with Morgan Stanley Capital Group, Inc. (MSCG). Under this arrangement, MSCG, in consideration for the payment to MSCG of certain fees, (i) assumed, by novation, the electricity purchase obligations of Pepco Energy Services in years 2009 through 2011 under several wholesale purchase contracts, and (ii) agreed to supply electricity to Pepco Energy Services on the same terms as the novated transactions, but without imposing on Pepco Energy Services any obligation to post collateral based on changes in electricity prices. The upfront fees incurred by Pepco Energy Services in 2009 in the amount of $25 million are being amortized into expense in declining amounts over the life of the arrangement based on the fair value of the underlying contracts at the time of the novation. For the three months ended June 30, 2011 and 2010, Pepco Energy Services recognized less than $1 million and approximately $3 million, respectively, of the fees in “Interest expense.” For the six months ended June 30, 2011 and 2010, Pepco Energy Services recognized less than $1 million and approximately $5 million, respectively, of the fees in “Interest expense.”

As of June 30, 2011, Pepco Energy Services had posted net cash collateral of $76 million and provided letters of credit of $62 million. At December 31, 2010, Pepco Energy Services had posted net cash collateral of $117 million and provided letters of credit of $113 million. Pepco Energy Services’ collateral requirements will continue to decline as its retail energy supply business winds down.

Remaining Collateral Requirements of Conectiv Energy

As of June 30, 2011, all cash collateral related to Conectiv Energy had been returned and there were no outstanding letters of credit. At December 31, 2010, Conectiv Energy had posted net cash collateral of $104 million and there were no outstanding letters of credit.

Pension and Postretirement Benefit Plans

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

Under the Pension Protection Act, if a plan incurs a funding shortfall in the preceding plan year, there can be required minimum quarterly contributions in the current and following plan years. PHI satisfied the minimum required contribution rules in 2010. Although PHI currently has no minimum funding requirement under the Pension Protection Act guidelines, Pepco, ACE and DPL in the first quarter of 2011 made discretionary tax-deductible contributions to the PHI Retirement Plan in the amounts of $40 million, $30 million and $40 million, respectively. The $110 million in contributions brought the PHI Retirement Plan assets to the funding target level for 2011 under the Pension Protection Act. During 2010, PHI Service

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

Based on the results of the 2010 actuarial valuation, PHI’s net periodic pension and other postretirement benefit costs were approximately $116 million in 2010 and the current estimate of benefit cost for 2011 is approximately $93 million. The utility subsidiaries are responsible for substantially all of the total PHI net periodic pension and other postretirement benefit costs. Approximately 30% of the net periodic pension and other postretirement benefit costs are capitalized. PHI estimates that its net periodic pension and other postretirement benefit expense will be approximately $65 million in 2011, as compared to $81 million in 2010.

Cash Flow Activity

PHI’s cash flows for the six months ended June 30, 2011 and 2010 are summarized below:

	Cash (Use) Source
	2011			2010			Change
	(millions of dollars)
Operating Activities	$	334		$	499		$	(165	)
Investing Activities		(220	)		(473	)		253
Financing Activities		(77	)		(36	)		(41	)
Net increase (decrease) in cash and cash equivalents	$	37		$	(10	)	$	47

Operating Activities

Cash flows from operating activities during the six months ended June 30, 2011 and 2010 are summarized below:

	Cash (Use) Source
	2011			2010		Change
	(millions of dollars)
Net income from continuing operations	$	157		$	104	$	53
Non-cash adjustments to net income		172			149		23
Gain on early termination of finance leases held in trust		(39	)		—		(39	)
Pension contributions		(110	)		—		(110	)
Changes in cash collateral related to derivative activities		44			4		40
Changes in other assets and liabilities		68			102		(34	)
Changes in Conectiv Energy net assets held for sale		42			140		(98	)
Net cash from operating activities	$	334		$	499	$	(165	)

Net cash from operating activities decreased $165 million for the six months ended June 30, 2011, compared to the same period in 2010. The decrease was due primarily to discretionary tax-deductible contributions to the PHI Retirement Plan and a reduction in the cash flows associated with Conectiv Energy assets held for sale included in discontinued operations. The gain associated with the early termination of finance leases held in trust was adjusted from cash received from net income and the associated proceeds are included in the investing activities section below. Partially offsetting these decreases in operating cash flows was an increase in cash flows from continuing operations, as well as a decrease in collateral requirements as a result of the on-going wind down of Pepco Energy Services retail energy supply business.

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Investing Activities

Cash flows from investing activities during the six months ended June 30, 2011 and 2010 are summarized below:

	Cash (Use) Source
	2011			2010			Change
	(millions of dollars)
Investment in property, plant and equipment	$	(387	)	$	(364	)	$	(23	)
DOE capital reimbursement awards received		16			—			16
Proceeds from early termination of finance leases held in trust		161			—			161
Changes in restricted cash equivalents		(3	)		3			(6	)
Net other investing activities		(7	)		(1	)		(6	)
Investment in property, plant and equipment associated with Conectiv Energy assets held for sale		—			(111	)		111
Net cash used by investing activities	$	(220	)	$	(473	)	$	253

Net cash used by investing activities decreased $253 million for the six months ended June 30, 2011 compared to the same period in 2010. The decrease was primarily due to the proceeds from the early termination of certain cross-border energy leases and the disposition of the Conectiv Energy business, which in 2010 had a cash use of $111 million for the investment in property, plant and equipment.

Financing Activities

Cash flows from financing activities during the six months ended June 30, 2011 and 2010 are summarized below:

	Cash (Use) Source
	2011			2010			Change
	(millions of dollars)
Dividends paid on common stock	$	(122	)	$	(120	)	$	(2	)
Common stock issued for the Dividend Reinvestment Plan and employee-related compensation		25			25			—
Redemption of preferred stock of subsidiaries		(6	)		—			(6	)
Issuances of long-term debt		235			102			133
Reacquisition of long-term debt		(52	)		(482	)		430
(Redemptions) Issuances of short-term debt, net		(139	)		458			(597	)
Net other financing activities		(18	)		(25	)		7
Net financing activities associated with Conectiv Energy assets held for sale		—			6			(6	)
Net cash used by financing activities	$	(77	)	$	(36	)	$	(41	)

Net cash used by financing activities increased $41 million for the six months ended June 30, 2011, compared to the same period in 2010, primarily due to changes in outstanding long-term and short-term debt.

Redemption of Preferred Stock

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

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Changes in Outstanding Long-Term Debt

Cash flows from the issuance and reacquisitions of long-term debt for the six months ended June 30, 2011 and 2010 are summarized in the charts below:

		2011		2010
Issuances		(millions of dollars)
DPL
	5.4% Tax-exempt bonds due 2031 (a)	$	—	$	78
	0.75% Tax-exempt bonds due 2026 (b)		35		—
ACE
	4.875% Tax-exempt bonds due 2029 (c)		—		23
	4.35% First mortgage bonds due 2021		200		—
Pepco Energy Services			—		1
		$	235	$	102

(a) Consists of Gas Facilities Refunding Revenue Bonds issued by The Delaware Economic Development Authority (DEDA) for the benefit of DPL.

(b) Consists of Pollution Control Refunding Revenue Bonds (DPL Bonds) issued by DEDA for the benefit of DPL that were purchased by DPL in May 2011. See footnote (b) to the Reacquisitions table below. The DPL Bonds were resold to the public in June 2011. While DPL held the DPL Bonds, they remained outstanding as a contractual matter, but were considered extinguished for accounting purposes. In connection with the resale of the DPL Bonds, the interest rate on the bonds was changed from 4.9% to a fixed rate of 0.75%. The DPL Bonds are secured by an outstanding series of collateral first mortgage bonds issued by DPL. 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 DPL Bonds. The payment by DPL of its obligations in respect of the DPL Bonds satisfies the corresponding payment obligations on the collateral first mortgage bonds. The DPL Bonds are subject to mandatory purchase by DPL on June 1, 2012.

(c) 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.

		2011		2010
Reacquisitions		(millions of dollars)
Pepco
	5.75% Tax-exempt bonds due 2010 (a)	$	—	$	16
			—		16
DPL
	4.9% Tax-exempt bonds due 2026 (b)		35		—
			35		—
ACE
	Securitization bonds due 2010-2011		17		16
			17		16
PHI
	4.00% Notes due May 15, 2010		—		200
	Floating Rate Notes due June 1, 2010		—		250
			—		450
		$	52	$	482

(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.

(b) Repurchased by DPL in May 2011 pursuant to a mandatory purchase provision in the indenture for the bonds that was triggered by the expiration of the original interest period for the bonds. The bonds were resold by DPL in June 2011. See footnote (b) to the Issuances table above.

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Changes in Short-Term Debt

Cash flows from the issuance of short-term debt, net of repayments, decreased by $597 million during the six months ended June 30, 2011 as compared to the same period in 2010 as a result of decreased collateral requirements of Pepco Energy Services and Conectiv Energy, and the use of the proceeds from the sale of Conectiv Energy’s wholesale generation business to reduce PHI’s outstanding debt. In April 2011, ACE issued $200 million of 4.35% first mortgage bonds, of which a portion of the proceeds was used to repay short-term debt. In 2010, PHI increased short-term borrowings by entering into a $450 million unsecured bridge facility, 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. PHI repaid all amounts outstanding under this facility in July 2010 with a portion of the proceeds from the sale of the Conectiv Energy wholesale power generation business.

Capital Requirements

Capital Expenditures

Pepco Holdings’ total capital expenditures for the six months ended June 30, 2011 totaled $387 million, of which $205 million was incurred by Pepco, $99 million was incurred by DPL and $60 million was incurred by ACE. The remainder was incurred primarily by the PHI Service Company. The Power Delivery expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission.

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

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

Reliability Enhancement Plans

The incremental cost of the reliability improvements over the next five years associated with Pepco’s Comprehensive Reliability Enhancement Plans for Maryland and the District of Columbia, a substantial portion of which would be capitalized, is estimated to be $100 million in the Maryland service territory and $90 million in the District of Columbia service territory. The total amount of the expenditures may change when anticipated regulations imposing reliability standards are promulgated in Maryland and upon the completion of Pepco’s analysis of the recently adopted modifications to the reliability standards in the District of Columbia.

Blueprint for the Future

Each of PHI’s three utilities are participating in a PHI initiative referred to as “Blueprint for the Future,” which is designed to meet the challenges of rising energy costs, concerns about the environment, improved reliability and government energy reduction goals. The initiative includes the implementation of various programs to help customers better manage their energy use, reduce the total cost of energy and provide other benefits. These programs also allow each utility to better manage and operate its electrical and natural gas distribution systems.

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Significant developments in 2011 include:

• Full-scale implementation of Advanced Metering Infrastructure (AMI) began in the Pepco-Maryland service territory in June 2011.

• On June 15, 2011, Pepco filed a revised tariff in the District of Columbia related to the direct load control programs. This tariff proposes cost recovery through the establishment of a regulatory asset rather than a distribution bill surcharge.

• In March 2011, the Maryland Public Service Commission (MPSC) lifted the suspension on installation of smart thermostats for both DPL and Pepco in their Maryland service territories and accordingly smart thermostat installation has commenced.

During the six months ended June 30, 2011, Pepco and ACE received $15 million and $3 million, respectively, in stimulus funds awarded by the United States Department of Energy (DOE) under the American Recovery and Reinvestment Act of 2009. Through June 30, 2011, Pepco and ACE have received $30 million and $5 million, respectively, of the $149 million and $19 million, respectively, that DOE has awarded the companies to fund AMI, direct load control, distribution automation and communication infrastructure in their respective service territories.

MAPP Project

In October 2007, the PJM Board of Managers approved PHI’s proposal to construct a new 230-mile, 500-kilovolt interstate transmission line referred to as MAPP, as part of PJM’s regional transmission expansion plan to address the reliability objectives of the PJM RTO system. Since that time, there have been various modifications to the proposal that have redefined the length and route of the MAPP project. PJM has approved the use of advanced direct current technology for segments of the project, including the portion of the line that will traverse under the Chesapeake Bay. The direct current portion of the line will be 640 kilovolts and the remainder of the line will be 500 kilovolts. As currently approved by the PJM Board of Managers, MAPP is approximately 152 miles in length originating at the Possum Point substation in Virginia and ending at the Indian River substation in Delaware. The cost of the MAPP project is currently estimated to be $1.2 billion and the planned in-service date is June 1, 2015.

PJM currently is in its annual process of evaluating the region’s overall transmission needs. The evaluation is expected to take into account changes in demand response, generation retirements and additions, as well as a revised load forecast for the PJM region that is lower than the load that was forecasted in prior PJM studies. PJM has stated that it expects to complete this evaluation in August 2011. While the PJM process is not complete, the outcome of the evaluation is expected to result in a delay of the in-service date for the MAPP project of several years beyond the currently planned in-service date of June 1, 2015.

The construction of MAPP requires various permits and approvals, including the approval of the MPSC. On April 27, 2011, Pepco and DPL, applicants in the filing pending before the MPSC seeking approval to build the MAPP project, requested a six-month delay to the procedural schedule to allow for the completion of the ongoing PJM review which was granted on May 10, 2011. The revised schedule calls for direct testimony of the parties to be filed in December 2011 and evidentiary hearings to be held in March 2012. In May 2011, PHI filed applications in Maryland and Delaware to obtain the state environmental permits required for the construction of the portion of the line from Chalk Point substation in Maryland to Indian River substation in Delaware.

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Because the impact of the PJM review on the in-service date for MAPP will not be known until August 2011, PHI anticipates that $90 million to $110 million of the originally projected 2011 MAPP capital expenditures of $163 million will be deferred to later years. PHI also anticipates that non-MAPP transmission capital expenditures of approximately $45 million planned for later years will be incurred in 2011.

MAPP/DOE Loan Program

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

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

For a discussion of PHI’s third party guarantees, indemnifications, obligations and off-balance sheet arrangements, see Note (15), ”Commitments and Contingencies,” to the Consolidated Financial Statements of PHI included as Part I, Item 1, in this Form 10-Q.

Dividends

On July 28, 2011, Pepco Holdings’ Board of Directors declared a dividend on common stock of 27 cents per share payable September 30, 2011 to shareholders of record on September 12, 2011. PHI had approximately $1,095 million and $1,059 million of retained earnings free of restrictions at June 30, 2011 and December 31, 2010, respectively.

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Energy Contract Net Asset Activity

The following table provides detail on changes in the net asset or liability positions of both the Pepco Energy Services segment and the former Conectiv Energy segment with respect to energy commodity contracts for the six months ended June 30, 2011. The balances in the table are pre-tax and the derivative assets and liabilities reflect netting by counterparty before the impact of collateral.

	Energy Commodity Activities (a)
	(millions of dollars)
Total Fair Value of Energy Contract Net Liabilities at December 31, 2010	$	(218	)
Current period unrealized losses		(5	)
Effective portion of changes in fair value – recorded in Accumulated Other Comprehensive Loss		2
Cash flow hedge ineffectiveness – recorded in income		—
Recognition of realized losses on settlement of contracts		46
Derivative activity associated with Conectiv Energy		83
Total Fair Value of Energy Contract Net Liabilities at June 30, 2011	$	(92	)
Detail of Fair Value of Energy Contract Net Liabilities at June 30, 2011 (see above)
Derivative assets (current assets)	$	11
Derivative assets (non-current assets)		—
Total Fair Value of Energy Contract Assets		11
Derivative liabilities (current liabilities)		(100	)
Derivative liabilities (non-current liabilities)		(3	)
Total Fair Value of Energy Contract Liabilities		(103	)
Total Fair Value of Energy Contract Net Liabilities	$	(92	)

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

The $92 million net liability on energy contracts at June 30, 2011 was primarily attributable to losses on power swaps and natural gas futures held by Pepco Energy Services. Effective February 1, 2011, Conectiv Energy transferred its derivatives to an unaffiliated third party, which significantly contributed to the reduction in PHI’s overall losses on derivatives from $218 million at December 31, 2010 to $92 million at June 30, 2011. Pepco Energy Services’ net liability decreased to $92 million at June 30, 2011 from $135 million at December 31, 2010 primarily due to settlements of the derivatives. PHI expects that future revenues from existing customer sales obligations that are accounted for on an accrual basis will largely offset expected realized net losses on Pepco Energy Services’ energy contracts.

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PHI uses its best estimates to determine the fair value of Pepco Energy Services’ commodity derivative contracts. The fair values in each category presented below reflect forward prices and volatility factors as of June 30, 2011 and are subject to change as a result of changes in these factors.

	Fair Value of Contracts at June 30, 2011 Maturities
Source of Fair Value	2011			2012			2013			2014 and Beyond			Total Fair Value
	(millions of dollars)
Energy Commodity Activities, net(a)
Actively Quoted (i.e., exchange-traded) prices	$	(19	)	$	(18	)	$	(6	)	$	(1	)	$	(44	)
Prices provided by other external sources (b)		(17	)		(21	)		(6	)		—			(44	)
Modeled (c)		(3	)		(1	)		—			—			(4	)
Total	$	(39	)	$	(40	)	$	(12	)	$	(1	)	$	(92	)

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

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

(c) Modeled values include significant inputs not readily observable in the market.

Contractual Arrangements with Credit Rating Triggers or Margining Rights

Under certain contractual arrangements entered into by PHI’s subsidiaries, the subsidiary may be required to provide cash collateral or letters of credit as security for its contractual obligations if the credit ratings of PHI or the subsidiary are downgraded. In the event of a downgrade, the amount required to be posted would depend on the amount of the underlying contractual obligation existing at the time of the downgrade. Based on contractual provisions in effect at June 30, 2011, a downgrade in the unsecured debt credit ratings of PHI and each of its rated subsidiaries to below “investment grade” would increase the collateral obligation of PHI and its subsidiaries by up to $254 million, none of which is related to discontinued operations of Conectiv Energy, and $143 million of which is the net settlement amount attributable to derivatives, normal purchase and normal sale contracts, collateral, and other contracts under master netting agreements as described in Note (13), “Derivative Instruments and Hedging Activities” to the Consolidated Financial Statements of PHI set forth in Part I, Item 1 of this Form 10-Q. The remaining $111 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, 2011, Pepco Energy Services provided net cash collateral in the amount of $76 million in connection with these activities.

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Regulatory And Other Matters

DPL Renewable Energy Portfolio Standards

On July 7, 2011, the Governor of the state of Delaware signed legislation that expands DPL’s Renewable Energy Portfolio Standards (RPS) obligations beginning in 2012 from being required to obtain renewable energy credits (RECs) for energy delivered to Standard Offer Service (SOS) customers to energy delivered to all of its distribution customers. In addition, the legislation establishes that the energy output from fuel cells manufactured in Delaware capable of running on renewable fuels is an eligible resource for RECs under the Renewable Portfolio Standards Act. DPL is assessing the impact of the change in its REC requirements obligation as a result of the new legislation. However, DPL’s costs associated with obtaining RECs to fulfill its RPS obligations are recoverable from its distribution customers by law.

Other

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

Critical Accounting Policies

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

New Accounting Standards and Pronouncements

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

Forward-Looking Statements

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

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

• Changes in governmental policies and regulatory actions affecting the energy industry, including allowed rates of return, industry and rate structure, acquisition and disposal of assets and facilities, operation and construction of transmission and distribution facilities and the recovery of purchased power expenses;

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• Weather conditions affecting usage and emergency restoration costs;

• Population growth rates and changes in demographic patterns;

• Changes in customer demand for electricity and natural gas due to conservation measures and the use of more energy-efficient products;

• General economic conditions, including the impact of an economic downturn or recession on electricity and natural gas usage;

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

• Changes in tax rates or policies;

• Changes in rates of inflation;

• Changes in accounting standards or practices;

• Unanticipated changes in operating expenses and capital expenditures;

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

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

• Pace of entry into new markets;

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

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

Any forward-looking statements speak only as to the date of this Quarterly Report on Form 10-Q and Pepco Holdings undertakes no obligation to update any forward-looking statements to reflect events or circumstances after the date on which such statements are made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for Pepco Holdings to predict all such factors, nor can Pepco Holdings assess the impact of any such factor on Pepco Holdings’ business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.

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

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

Potomac Electric Power Company

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

General Overview

Pepco is engaged in the transmission and distribution of electricity in the District of Columbia and major portions of Prince George’s County and Montgomery County in suburban Maryland. Pepco also provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its service territories who do not elect to purchase electricity from a competitive energy supplier. Default Electricity Supply is known as Standard Offer Service (SOS) in both the District of Columbia and Maryland. Pepco’s service territory covers approximately 640 square miles and has a population of approximately 2.2 million. As of June 30, 2011, approximately 57% of delivered electricity sales were to Maryland customers and approximately 43% were to District of Columbia customers.

As a result of the implementation of a bill stabilization adjustment mechanism (BSA) for retail electric customers of Pepco in Maryland in June 2007 and in the District of Columbia in November 2009, 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.

Reliability Enhancement Plans

During 2010, Pepco announced Comprehensive Reliability Enhancement Plans for Maryland and the District of Columbia. Each plan advances work on existing programs and initiates new activities for customers in the respective jurisdictions. These programs include enhanced vegetation management, identification and upgrading of underperforming feeder lines, addition of new facilities to support load growth, installation of distribution automation systems, replacement of underground residential cables, improvements to substation supply lines and selective undergrounding of existing above-ground service lines. By focusing on these areas, Pepco plans to increase the reliability of the distribution system by reducing both the frequency and the duration of power outages. Pepco’s progress on this plan includes increasing tree-trimming personnel (including contractors) from 80 to 350, trimming trees along more than 2,200 miles of power lines, and replacing or upgrading over 150 miles of underground cable.

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, 2011 to the six months ended June 30, 2010. All amounts in the tables (except sales and customers) are in millions of dollars.

Operating Revenue

	2011		2010		Change
Regulated T&D Electric Revenue	$	530	$	482	$	48
Default Electricity Supply Revenue		493		592		(99	)
Other Electric Revenue		17		17		—
Total Operating Revenue	$	1,040	$	1,091	$	(51	)

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

Regulated T&D Electric Revenue includes revenue from the distribution of electricity, including the distribution of Default Electricity Supply, to Pepco’s customers within its service territory at regulated rates. Regulated T&D Electric Revenue also includes transmission service revenue that Pepco receives as a transmission owner from PJM Interconnection, LLC (PJM) at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.

Default Electricity Supply Revenue is the revenue received from the supply of electricity by Pepco at regulated rates to retail customers who do not elect to purchase electricity from a competitive energy supplier, and which is also known as SOS. The costs related to Default Electricity Supply are included in Purchased Energy. Default Electricity Supply Revenue also includes revenue in the form of transmission enhancement credits that Pepco receives as a transmission owner from PJM for approved regional transmission expansion plan costs.

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

Regulated T&D Electric

	2011		2010		Change
Regulated T&D Electric Revenue
Residential	$	155	$	134	$	21
Commercial and industrial		311		289		22
Other		64		59		5
Total Regulated T&D Electric Revenue	$	530	$	482	$	48

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

	2011		2010		Change
Regulated T&D Electric Sales (Gigawatt hours (GWh))
Residential		3,965		4,003		(38	)
Commercial and industrial		9,109		9,277		(168	)
Other		77		77		—
Total Regulated T&D Electric Sales		13,151		13,357		(206	)

	2011		2010		Change
Regulated T&D Electric Customers (in thousands)
Residential		712		707		5
Commercial and industrial		74		74		—
Other		—		—		—
Total Regulated T&D Electric Customers		786		781		5

Regulated T&D Electric Revenue increased by $48 million primarily due to:

• An increase of $24 million due to higher pass-through revenue (which is substantially offset by a corresponding increase in Other Taxes) primarily the result of rate increases in Montgomery County, Maryland utility taxes that are collected by Pepco on behalf of the county.

• An increase of $14 million due to distribution rate increases in the District of Columbia effective March 2010 and July 2010; and in Maryland effective July 2010.

• An increase of $5 million in transmission revenue primarily attributable to higher rates effective June 1, 2010 related to an increase in transmission plant investment.

• An increase of $3 million due to customer growth of 1% in 2011, primarily in the residential class.

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

Default Electricity Supply

	2011		2010		Change
Default Electricity Supply Revenue
Residential	$	355	$	424	$	(69	)
Commercial and industrial		135		162		(27	)
Other		3		6		(3	)
Total Default Electricity Supply Revenue	$	493	$	592	$	(99	)

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PEPCO

	2011		2010		Change
Default Electricity Supply Sales (GWh)
Residential		3,415		3,680		(265	)
Commercial and industrial		1,411		1,566		(155	)
Other		4		5		(1	)
Total Default Electricity Supply Sales		4,830		5,251		(421	)

	2011		2010		Change
Default Electricity Supply Customers (in thousands)
Residential		625		657		(32	)
Commercial and industrial		46		49		(3	)
Other		—		—		—
Total Default Electricity Supply Customers		671		706		(35	)

Default Electricity Supply Revenue decreased by $99 million primarily due to:

• A decrease of $52 million as a result of lower Default Electricity Supply rates.

• A decrease of $37 million due to lower sales, primarily as a result of customer migration to competitive suppliers.

• A decrease of $17 million due to lower sales as a result of cooler weather during the 2011 spring months as compared to 2010.

The aggregate amount of these decreases was partially offset by:

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

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

The following table shows the percentages of Pepco’s total distribution sales by jurisdictions that are derived from customers receiving Default Electricity Supply from Pepco. Amounts are for the six months ended June 30.

	2011			2010
Sales to District of Columbia customers		27	%		29	%
Sales to Maryland customers		44	%		47	%

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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 $103 million to $473 million in 2011 from $576 million in 2010 primarily due to:

• A decrease of $59 million due to lower average electricity costs under Default Electricity Supply contracts.

• A decrease of $41 million primarily due to customer migration to competitive suppliers.

• A decrease of $16 million due to lower electricity sales primarily as a result of cooler weather during the 2011 spring months as compared to 2010.

The aggregate amount of these decreases was partially offset by:

• An increase of $11 million in deferred electricity expense primarily due to lower average electricity costs under Default Electricity Supply contracts, which resulted in a higher rate of recovery of Default Electricity Supply costs.

Other Operation and Maintenance

Other Operation and Maintenance increased by $41 million to $202 million in 2011 from $161 million in 2010 primarily due to:

• An increase of $18 million primarily due to higher tree trimming and preventative maintenance costs.

• An increase of $10 million in emergency restoration costs.

• An increase of $6 million in customer support and communication costs.

• An increase of $3 million primarily due to emergency restoration improvement projects and reliability compliance costs.

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

Depreciation and Amortization

Depreciation and Amortization expense increased by $6 million to $84 million in 2011 from $78 million in 2010 primarily due to:

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

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

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

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Other Taxes

Other Taxes increased by $23 million to $186 million in 2011 from $163 million in 2010. The increase was primarily due to rate increases in the Montgomery County, Maryland utility taxes that are collected and passed through by Pepco (substantially offset by a corresponding increase in Regulated T&D Electric Revenue).

Other Income (Expenses)

Other Expenses (which are net of Other Income) decreased by $8 million to a net expense of $36 million in 2011 from a net expense of $44 million in 2010. The decrease was primarily due to:

• An increase of $5 million in income related to Allowance for Funds Used During Construction that is applied to capital projects.

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

Income Tax Expense

Pepco’s effective tax rates for the six months ended June 30, 2011 and 2010 were 15.3% and 42.0%, respectively. The decrease in the effective tax rate primarily resulted from changes in estimates and interest related to uncertain and effectively settled tax positions, refunds received on amended state tax returns and permanent differences related to deferred compensation funding.

During the second quarter of 2011, PHI reached a settlement with the Internal Revenue Service (IRS) with respect to interest due on its federal tax liabilities related to the November 2010 audit settlement for years 1996 through 2002. In connection with this agreement, PHI reallocated certain amounts that have been on deposit with the IRS since 2006 among liabilities in the settlement years and subsequent years. Primarily related to the settlement and reallocations, Pepco has recorded an additional tax benefit in the amount of $5 million (after-tax). This additional interest income was recorded in the second quarter of 2011.

In May 2011, Pepco received refunds of approximately $5 million, and recorded tax benefits of approximately $4 million (after-tax) related to the filing of amended state tax returns. These amended returns reduced state taxable income due to an increase in tax basis on certain prior years’ asset dispositions.

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

Capital Requirements

Capital Expenditures

Pepco’s capital expenditures for the six months ended June 30, 2011, totaled $205 million. These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission. The expenditures also include an allocation by PHI of hardware and software expenditures that primarily benefit the Power Delivery business and are allocated to Pepco when the assets are placed in service.

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

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

Reliability Enhancement Plans

The incremental cost of the reliability improvements over the next five years associated with Pepco’s Comprehensive Reliability Enhancement Plans for Maryland and the District of Columbia, a substantial portion of which would be capitalized, is estimated to be $100 million in the Maryland service territory and $90 million in the District of Columbia service territory. The total amount of the expenditures may change when anticipated regulations imposing reliability standards are promulgated in Maryland or if modifications to the reliability standards currently imposed in the District of Columbia become effective.

Blueprint for the Future

Pepco is participating in a PHI initiative referred to as “Blueprint for the Future,” which is designed to meet the challenges of rising energy costs, concerns about the environment, improved reliability and government energy reduction goals. The initiative includes the implementation of various programs to help customers better manage their energy use, reduce the total cost of energy and provide other benefits. These programs also allow each utility to better manage and operate its electrical and natural gas distribution systems.

Significant developments in 2011 include:

• Full-scale implementation of Advanced Metering Infrastructure (AMI) began in the Pepco-Maryland service territory in June 2011.

• On June 15, 2011, Pepco filed a revised tariff in the District of Columbia related to the direct load control programs. This tariff proposes cost recovery through the establishment of a regulatory asset rather than a distribution bill surcharge.

• In March 2011, the Maryland Public Service Commission (MPSC) lifted the suspension on installation of smart thermostats for both Delmarva Power & Light Company (DPL) and Pepco in their Maryland service territories and accordingly smart thermostat installation has commenced.

During the six months ended June 30, 2011, Pepco received $15 million in stimulus funds awarded by the United States Department of Energy (DOE) under the American Recovery and Reinvestment Act of 2009. Through June 30, 2011, Pepco received $30 million of the $149 million that DOE has awarded the company to fund AMI, direct load control, distribution automation and communication infrastructure in its service territories.

MAPP Project

In October 2007, the PJM Board of Managers approved PHI’s proposal to construct a new 230-mile, 500-kilovolt interstate transmission line referred to as MAPP, as part of PJM’s regional transmission expansion plan to address the reliability objectives of the PJM Regional Transmission Organization system. Since that time, there have been various modifications to the proposal that have redefined the length and route of the MAPP project. PJM has approved the use of advanced direct current technology for segments of the project, including the portion of the line that will traverse under the Chesapeake Bay. The direct current portion of the line will be 640 kilovolts and the remainder of the line will be 500 kilovolts. As currently approved by the PJM Board of Managers, MAPP is approximately 152 miles in length originating at the Possum Point substation in Virginia and ending at the Indian River substation in Delaware. The cost of the MAPP project is currently estimated to be $1.2 billion and the planned in-service date is June 1, 2015.

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PEPCO

PJM currently is in its annual process of evaluating the region’s overall transmission needs. The evaluation is expected to take into account changes in demand response, generation retirements and additions, as well as a revised load forecast for the PJM region that is lower than the load that was forecasted in prior PJM studies. PJM has stated that it expects to complete this evaluation in August 2011. While the PJM process is not complete, the outcome of the evaluation is expected to result in a delay of the in-service date for the MAPP project of several years beyond the currently planned in-service date of June 1, 2015.

The construction of MAPP requires various permits and approvals, including the approval of the MPSC. On April 27, 2011, Pepco and DPL, applicants in the filing pending before the MPSC seeking approval to build the MAPP project, requested a six-month delay to the procedural schedule to allow for the completion of the ongoing PJM review which was granted on May 10, 2011. The revised schedule calls for direct testimony of the parties to be filed in December 2011 and evidentiary hearings to be held in March 2012.

Because the impact of the PJM review on the in-service date for MAPP will not be known until August 2011, Pepco anticipates that $65 million to $79 million of the originally projected 2011 MAPP capital expenditures of $112 million will be deferred to later years. PHI also anticipates that non-MAPP transmission capital expenditures of approximately $8 million planned for later years will be incurred by Pepco in 2011.

MAPP/DOE Loan Program

To assist in the funding of the MAPP project, PHI has applied for a $684 million loan guarantee from the DOE for a substantial portion of the MAPP project. The application has been made under a federal loan guarantee program for projects that employ innovative energy efficiency, renewable energy and advanced transmission and distribution technologies. If granted, PHI believes the guarantee could allow PHI to acquire financing at a lower cost than it would otherwise be able to obtain in the capital markets. Whether PHI’s application will be granted and, if so, the amount of debt guaranteed is subject to the discretion of the DOE and the negotiation of terms that will satisfy the conditions of the guarantee program. On February 28, 2011, DOE issued a Notice of Intent to prepare an Environmental Impact Statement to assist the DOE in assessing the environmental impact of constructing the portion of the MAPP project to be supported by the loan guarantee. Since February 2011, the DOE has conducted field inspections of the entire route and has held public meetings to obtain input from the communities along the route. In May 2011, PHI filed for the environmental permit in Maryland and Delaware for the construction of the portion of the line from Chalk Point substation in Maryland to Indian River substation in Delaware.

Forward-Looking Statements

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

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PEPCO

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

• Changes in governmental policies and regulatory actions affecting the energy industry, including allowed rates of return, industry and rate structure, acquisition and disposal of assets and facilities, operation and construction of transmission and distribution facilities and the recovery of purchased power expenses;

• Weather conditions affecting usage and emergency restoration costs;

• Population growth rates and changes in demographic patterns;

• Changes in customer demand for electricity due to conservation measures and the use of more energy-efficient products;

• General economic conditions, including the impact of an economic downturn or recession on electricity usage;

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

• Changes in tax rates or policies;

• Changes in rates of inflation;

• Changes in accounting standards or practices;

• Unanticipated changes in operating expenses and capital expenditures;

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

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

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

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

Any forward-looking statements speak only as to the date of this Quarterly Report on Form 10-Q and Pepco undertakes no obligation to update any forward-looking statements to reflect events or circumstances after the date on which such statements are made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for Pepco to predict all such factors, nor can Pepco assess the impact of any such factor on Pepco’s business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.

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

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DPL

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

Delmarva Power & Light Company

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

General Overview

DPL is engaged in the transmission and distribution of electricity in Delaware and portions of Maryland. DPL also provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its service territories who do not elect to purchase electricity from a competitive energy supplier. Default Electricity Supply is known as Standard Offer Service (SOS) in both Delaware and Maryland. DPL’s electricity distribution service territory covers approximately 5,000 square miles and has a population of approximately 1.3 million. As of June 30, 2011, 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.

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

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

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Results of Operations

The following results of operations discussion compares the six months ended June 30, 2011 to the six months ended June 30, 2010. All amounts in the tables (except sales and customers) are in millions of dollars.

Electric Operating Revenue

	2011		2010		Change
Regulated T&D Electric Revenue	$	194	$	176	$	18
Default Electricity Supply Revenue		342		373		(31	)
Other Electric Revenue		7		10		(3	)
Total Electric Operating Revenue	$	543	$	559	$	(16	)

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

Regulated T&D Electric Revenue includes revenue from the distribution of electricity, including the distribution of Default Electricity Supply, to DPL’s customers within its service territory at regulated rates. Regulated T&D Electric Revenue also includes transmission service revenue that DPL receives as a transmission owner from PJM Interconnection, LLC (PJM) at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.

Default Electricity Supply Revenue is the revenue received from the supply of electricity by DPL at regulated rates to retail customers who do not elect to purchase electricity from a competitive energy supplier, and which is also known as SOS. The costs related to Default Electricity Supply are included in Purchased Energy. Default Electricity Supply Revenue also includes transmission enhancement credits that DPL receives as a transmission owner from PJM for approved regional transmission expansion plan costs.

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

Regulated T&D Electric

	2011		2010		Change
Regulated T&D Electric Revenue
Residential	$	92	$	87	$	5
Commercial and industrial		55		53		2
Other		47		36		11
Total Regulated T&D Electric Revenue	$	194	$	176	$	18

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

	2011		2010		Change
Regulated T&D Electric Sales (Gigawatt hours (GWh))
Residential		2,608		2,558		50
Commercial and industrial		3,596		3,550		46
Other		24		25		(1	)
Total Regulated T&D Electric Sales		6,228		6,133		95
	2011		2010		Change
Regulated T&D Electric Customers (in thousands)
Residential		441		439		2
Commercial and industrial		59		59		—
Other		1		1		—
Total Regulated T&D Electric Customers		501		499		2

Regulated T&D Electric Revenue increased by $18 million primarily due to:

• An increase of $11 million in transmission revenue primarily attributable to higher rates effective June 1, 2010 related to an increase in transmission plant investment.

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

• An increase of $2 million due to higher non-weather related average customer usage.

Default Electricity Supply

	2011		2010		Change
Default Electricity Supply Revenue
Residential	$	259	$	278	$	(19	)
Commercial and industrial		77		90		(13	)
Other		6		5		1
Total Default Electricity Supply Revenue	$	342	$	373	$	(31	)
	2011		2010		Change
Default Electricity Supply Sales (GWh)
Residential		2,450		2,499		(49	)
Commercial and industrial		899		929		(30	)
Other		15		21		(6	)
Total Default Electricity Supply Sales		3,364		3,449		(85	)
	2011		2010		Change
Default Electricity Supply Customers (in thousands)
Residential		419		430		(11	)
Commercial and industrial		44		46		(2	)
Other		1		1		—
Total Default Electricity Supply Customers		464		477		(13	)

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DPL

Default Electricity Supply Revenue decreased by $31 million primarily due to:

• A decrease of $23 million as a result of lower Default Electricity Supply rates.

• A decrease of $17 million due to lower sales, primarily as a result of customer migration to competitive suppliers.

• A decrease of $9 million due to lower sales as a result of cooler weather during the 2011 spring months as compared to 2010.

The aggregate amount of these decreases was partially offset by:

• An increase of $16 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:

	2011			2010
Sales to Delaware customers		51	%		52	%
Sales to Maryland customers		60	%		64	%

Natural Gas Operating Revenue

	2011		2010		Change
Regulated Gas Revenue	$	117	$	111	$	6
Other Gas Revenue		24		20		4
Total Natural Gas Operating Revenue	$	141	$	131	$	10

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

Regulated Gas

	2011		2010		Change
Regulated Gas Revenue
Residential	$	73	$	69	$	4
Commercial and industrial		39		38		1
Transportation and other		5		4		1
Total Regulated Gas Revenue	$	117	$	111	$	6

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DPL

	2011		2010		Change
Regulated Gas Sales (billion cubic feet)
Residential		5		5		—
Commercial and industrial		3		3		—
Transportation and other		4		3		1
Total Regulated Gas Sales		12		11		1
	2011		2010		Change
Regulated Gas Customers (in thousands)
Residential		114		113		1
Commercial and industrial		9		9		—
Transportation and other		—		—		—
Total Regulated Gas Customers		123		122		1

Regulated Gas Revenue increased by $6 million primarily due to:

• An increase of $16 million due to higher sales as a result of colder weather during the 2011 winter months as compared to 2010.

• An increase of $2 million due to distribution rate increases effective August 2010 and February 2011.

The aggregate amount of these increases was partially offset by:

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

Other Gas Revenue

Other Gas Revenue increased by $4 million primarily due to higher volumes of off-system sales to electric generators and gas marketers.

Operating Expenses

Purchased Energy

Purchased Energy consists of the cost of electricity purchased by DPL to fulfill its Default Electricity Supply obligation and, as such, is recoverable from customers in accordance with the terms of public service commission orders. Purchased Energy decreased by $33 million to $327 million in 2011 from $360 million in 2010 primarily due to:

• A decrease of $17 million due to lower average electricity costs under Default Electricity Supply contracts.

• A decrease of $9 million primarily due to customer migration to competitive suppliers.

• A decrease of $8 million due to lower electricity sales primarily as a result of cooler weather during the 2011 spring months as compared to 2010.

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DPL

Gas Purchased

Gas Purchased consists of the cost of gas purchased by DPL to fulfill its obligation to regulated gas customers and, as such, is recoverable from customers in accordance with the terms of public service commission orders. It also includes the cost of gas purchased for off-system sales. Total Gas Purchased increased by $5 million to $96 million in 2011 from $91 million in 2010 primarily due to:

• An increase of $14 million in deferred gas expense as a result of a higher rate of recovery of natural gas supply costs.

• An increase of $2 million in the cost of gas purchases for off-system sales as a result of higher volumes purchased.

The aggregate amount of these increases was partially offset by:

• A decrease of $6 million in the cost of gas purchases for on-system sales as a result of lower average gas prices.

• A decrease of $5 million from the settlement of financial hedges entered into as part of DPL’s hedge program for regulated natural gas.

Other Operation and Maintenance

Other Operation and Maintenance decreased by $14 million to $112 million in 2011 from $126 million in 2010 primarily due to:

• A decrease of $8 million associated with certain adjustments recorded by DPL in the second quarter of 2011 to correct certain errors associated with the accounting for DPL Default Electricity Supply. These adjustments were primarily due to the under-recognition of allowed returns on the cost of working capital.

• A decrease of $4 million due to 2010 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.

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

• A decrease of $2 million due to an adjustment of self-insurance reserves for general and auto liability claims.

The aggregate amount of these decreases was partially offset by:

• An increase of $4 million primarily due to higher preventative maintenance and tree trimming costs.

Depreciation and Amortization

Depreciation and Amortization expense increased by $4 million to $44 million in 2011 from $40 million in 2010 primarily due to:

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

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

Income Tax Expense

DPL’s effective tax rates for the six months ended June 30, 2011 and 2010 were 32.8% and 44.4%, respectively. The decrease in the effective tax rate primarily resulted from changes in estimates and interest related to uncertain and effectively settled tax positions.

During the second quarter of 2011, PHI reached a settlement with the Internal Revenue Service (IRS) with respect to interest due on its federal tax liabilities related to the November 2010 audit settlement for years 1996 through 2002. In connection with this agreement, PHI reallocated certain amounts that have been on deposit with the IRS since 2006 among liabilities in the settlement years and subsequent years. Primarily related to the settlement and reallocations, DPL has recorded an additional $4 million (after-tax) interest benefit. This additional interest income was recorded in the second quarter of 2011. Also during the second of quarter 2011, DPL completed a reconciliation of its deferred taxes on certain regulatory assets and, as a result, recorded a $1 million decrease to income tax expenses.

Capital Requirements

Capital Expenditures

DPL’s capital expenditures for the six months ended June 30, 2011, totaled $99 million. These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission. The expenditures also include an allocation by PHI of hardware and software expenditures that primarily benefit the Power Delivery business and are allocated to DPL when the assets are placed in service.

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

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

Blueprint for the Future

DPL is participating in a PHI initiative referred to as “Blueprint for the Future,” which is designed to meet the challenges of rising energy costs, concerns about the environment, improved reliability and government energy reduction goals. The initiative includes the implementation of various programs to help customers better manage their energy use, reduce the total cost of energy and provide other benefits. These programs also allow each utility to better manage and operate its electrical and natural gas distribution systems.

Significant developments in 2011 include:

• In March 2011, the Maryland Public Service Commission (MPSC) lifted the suspension on installation of smart thermostats for both DPL and Potomac Electric Power Company (Pepco) in their Maryland service territories and accordingly smart thermostat installation has commenced.

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MAPP Project

In October 2007, the PJM Board of Managers approved PHI’s proposal to construct a new 230-mile, 500-kilovolt interstate transmission line referred to as MAPP, as part of PJM’s regional transmission expansion plan to address the reliability objectives of the PJM Regional Transmission Organization system. Since that time, there have been various modifications to the proposal that have redefined the length and route of the MAPP project. PJM has approved the use of advanced direct current technology for segments of the project, including the portion of the line that will traverse under the Chesapeake Bay. The direct current portion of the line will be 640 kilovolts and the remainder of the line will be 500 kilovolts. As currently approved by the PJM Board of Managers, MAPP is approximately 152 miles in length originating at the Possum Point substation in Virginia and ending at the Indian River substation in Delaware. The cost of the MAPP project is currently estimated to be $1.2 billion and the planned in-service date is June 1, 2015.

PJM currently is in its annual process of evaluating the region’s overall transmission needs. The evaluation is expected to take into account changes in demand response, generation retirements and additions, as well as a revised load forecast for the PJM region that is lower than the load that was forecasted in prior PJM studies. PJM has stated that it expects to complete this evaluation in August 2011. While the PJM process is not complete, the outcome of the evaluation is expected to result in a delay of the in-service date for the MAPP project of several years beyond the currently planned in-service date of June 1, 2015.

The construction of MAPP requires various permits and approvals, including the approval of the MPSC. On April 27, 2011, Pepco and DPL, applicants in the filing pending before the MPSC seeking approval to build the MAPP project, requested a six-month delay to the procedural schedule to allow for the completion of the ongoing PJM review which was granted on May 10, 2011. The revised schedule calls for direct testimony of the parties to be filed in December 2011 and evidentiary hearings to be held in March 2012.

Because the impact of the PJM review on the in-service date for MAPP will not be known until August 2011, DPL anticipates that $25 million to $31 million of the originally projected 2011 MAPP capital expenditures of $51 million will be deferred to later years. PHI also anticipates that non-MAPP transmission capital expenditures of approximately $28 million planned for later years will be incurred by DPL in 2011.

MAPP/DOE Loan Program

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

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DPL

Forward-Looking Statements

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

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

• Changes in governmental policies and regulatory actions affecting the energy industry, including allowed rates of return, industry and rate structure, acquisition and disposal of assets and facilities, operation and construction of transmission and distribution facilities and the recovery of purchased power expenses;

• Weather conditions affecting usage and emergency restoration costs;

• Population growth rates and changes in demographic patterns;

• Changes in customer demand for electricity and natural gas due to conservation measures and the use of more energy-efficient products;

• General economic conditions, including the impact of an economic downturn or recession on electricity and natural gas usage;

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

• Changes in tax rates or policies;

• Changes in rates of inflation;

• Changes in accounting standards or practices;

• Unanticipated changes in operating expenses and capital expenditures;

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

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

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

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

Any forward-looking statements speak only as to the date of this Quarterly Report on Form 10-Q and DPL undertakes no obligation to update any forward-looking statements to reflect events or circumstances after the date on which such statements are made or to reflect the occurrence of 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.

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ACE

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

Atlantic City Electric Company

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

General Overview

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

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

Results of Operations

The following results of operations discussion compares the six months ended June 30, 2011 to the six months ended June 30, 2010. All amounts in the tables (except sales and customers) are in millions of dollars.

Operating Revenue

	2011		2010		Change
Regulated T&D Electric Revenue	$	183	$	188	$	(5	)
Default Electricity Supply Revenue		426		436		(10	)
Other Electric Revenue		10		8		2
Total Operating Revenue	$	619	$	632	$	(13	)

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

Regulated T&D Electric Revenue includes revenue from the distribution of electricity, including the distribution of Default Electricity Supply, to ACE’s customers within its service territory at regulated rates. Regulated T&D Electric Revenue also includes transmission service revenue that ACE receives as a transmission owner from PJM Interconnection, LLC (PJM) at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.

Default Electricity Supply Revenue is the revenue received from the supply of electricity by ACE at regulated rates to retail customers who do not elect to purchase electricity from a competitive energy supplier, also known as BGS. The costs related to Default Electricity Supply are included in “Purchased energy.” Default Electricity Supply Revenue also includes revenue from Transition Bond Charges that

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ACE receives, and pays to Atlantic City Electric Transitional Funding, LLC (ACE Funding), to fund the principal and interest payments on Transition Bonds issued by ACE Funding and revenue in the form of transmission enhancement credits that ACE receives as a transmission owner from PJM for approved regional transmission expansion plan costs (Transmission Enhancement Credits).

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

Regulated T&D Electric

	2011		2010		Change
Regulated T&D Electric Revenue
Residential	$	75	$	77	$	(2	)
Commercial and industrial		59		65		(6	)
Other		49		46		3
Total Regulated T&D Electric Revenue	$	183	$	188	$	(5	)

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

	2011		2010		Change
Regulated T&D Electric Sales (Gigawatt hours (GWh))
Residential		2,057		2,089		(32	)
Commercial and industrial		2,513		2,601		(88	)
Other		22		22		—
Total Regulated T&D Electric Sales		4,592		4,712		(120	)
	2011		2010		Change
Regulated T&D Electric Customers (in thousands)
Residential		482		482		—
Commercial and industrial		65		65		—
Other		1		1		—
Total Regulated T&D Electric Customers		548		548		—

Regulated T&D Electric Revenue decreased by $5 million primarily due to:

• A decrease of $13 million due to a New Jersey Societal Benefit Charge rate decrease that became effective in January 2011 (which is offset in Deferred Electric Service Costs).

• A decrease of $2 million due to lower sales as a result of cooler weather during the 2011 spring months as compared to 2010.

• A decrease of $2 million due to lower non-weather related average customer usage.

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ACE

The aggregate amount of these decreases was partially offset by:

• An increase of $9 million due to a distribution rate increase that became effective in June 2010.

• An increase of $3 million in transmission revenue primarily attributable to higher rates effective June 1, 2010 related to an increase in transmission plant investment.

Default Electricity Supply

	2011		2010	Change
Default Electricity Supply Revenue
Residential	$	231	$237	$	(6	)
Commercial and industrial		121	115		6
Other		74	84		(10	)
Total Default Electricity Supply Revenue	$	426	$436	$	(10	)

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

	2011		2010		Change
Default Electricity Supply Sales (GWh)
Residential		1,834		2,087		(253	)
Commercial and industrial		743		1,009		(266	)
Other		18		22		(4	)
Total Default Electricity Supply Sales		2,595		3,118		(523	)
	2011		2010		Change
Default Electricity Supply Customers (in thousands)
Residential		431		481		(50	)
Commercial and industrial		51		60		(9	)
Other		—		—		—
Total Default Electricity Supply Customers		482		541		(59	)

Default Electricity Supply Revenue decreased by $10 million primarily due to:

• A decrease of $45 million due to lower sales, primarily as a result of commercial and residential customer migration to competitive suppliers.

• A decrease of $7 million in wholesale energy and capacity resale revenues primarily due to the sale of lower volumes of electricity and capacity purchased from NUGs.

• A decrease of $5 million due to lower sales as a result of cooler weather during the 2011 spring months as compared to 2010.

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

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ACE

The aggregate amount of these decreases was partially offset by:

• An increase of $50 million as a result of higher Default Electricity Supply rates, primarily due to a Non-utility Generation Charge rate increase that became effective in January 2011.

The decrease in total Default Electricity Supply Revenue includes a decrease of $6 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, 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, 2011, BGS unbilled revenue decreased by $6 million as compared to the six months ended June 30, 2010, which resulted in a $4 million decrease in ACE’s net income. The decrease was primarily due to lower customer usage and increased customer migration during the unbilled revenue period at the end of the six months ended June 30, 2011, as compared to the corresponding period in 2010.

For the six months ended June 30, 2011 and 2010, the percentages of ACE’s total distribution sales that are derived from customers receiving Default Electricity Supply are 57% and 66%, 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 $84 million to $394 million in 2011 from $478 million in 2010 primarily due to:

• A decrease of $55 million primarily due to customer migration to competitive suppliers.

• A decrease of $25 million due to lower average electricity costs under Default Electricity Supply contracts.

• A decrease of $4 million due to lower electricity sales primarily as a result of cooler weather during the 2011 spring months as compared to 2010.

Other Operation and Maintenance

Other Operation and Maintenance increased by $9 million to $106 million in 2011 from $97 million in 2010. Excluding an increase of $3 million primarily related to New Jersey Societal Benefit Program costs and bad debt expenses that are deferred and recoverable, Other Operation and Maintenance expense increased by $6 million. The $6 million increase was primarily due to:

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

• An increase of $2 million in costs related to customer requested work.

• An increase of $1 million in employee-related costs, primarily due to higher accrued vacation and worker compensation adjustments.

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ACE

The aggregate amount of these increases was partially offset by:

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

Depreciation and Amortization

Depreciation and Amortization expense increased by $17 million to $66 million in 2011, from $49 million in 2010 primarily due to:

• An increase of $13 million in amortization of stranded costs as the result of higher revenue due to rate increases effective October 2010 for the Transition Bond Charge and Market Transition Charge Tax (partially offset in Default Electricity Supply Revenue).

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

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 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 $50 million, to an expense reduction of $32 million in 2011 as compared to an expense reduction of $82 million in 2010, primarily due to an increase in deferred electricity expense as a result of higher Default Electricity Supply revenue rates and lower electricity supply costs.

Income Tax Expense

ACE’s consolidated effective tax rates for the six months ended June 30, 2011 and 2010 were 44.2% and 48.9%, respectively. The decrease in the effective tax rate primarily resulted from the reversal of $6 million of accrued interest income on uncertain and effectively settled state income tax positions in 2010. In addition, in the second quarter of 2011, ACE completed a reconciliation of its deferred taxes associated with certain regulatory assets and recorded adjustments which resulted in an increase to income tax expense of $1 million.

Capital Requirements

Capital Expenditures

ACE’s capital expenditures for the six months ended June 30, 2011, totaled $60 million. These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission. The expenditures also include an allocation by PHI of hardware and software expenditures that primarily benefit the Power Delivery business and are allocated to ACE when the assets are placed in service.

In its Form 10-K for the year ended December 31, 2010, ACE presented the projected capital expenditures for the five-year period 2011 through 2015. There have been no material changes in ACE’s projected capital expenditures from those presented in the Form 10-K.

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ACE

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

Blueprint for the Future

ACE is participating in a PHI initiative referred to as “Blueprint for the Future,” which is designed to meet the challenges of rising energy costs, concerns about the environment, improved reliability and government energy reduction goals. The initiative includes the implementation of various programs to help customers better manage their energy use, reduce the total cost of energy and provide other benefits. These programs also allow each utility to better manage and operate its electrical and gas distribution systems. The New Jersey Board of Public Utilities is not expected to approve ACE’s proposal for implementation of advanced meters in the near term.

During the six months ended June 30, 2011, ACE received $3 million in stimulus funds awarded by the United States Department of Energy (DOE) under the American Recovery and Reinvestment Act of 2009. Through June 30, 2011, ACE has received $5 million of the $19 million that DOE awarded the company to fund AMI, direct load control, distribution automation and communication infrastructure in its service territories.

Forward-Looking Statements

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

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

• Changes in governmental policies and regulatory actions affecting the energy industry, including allowed rates of return, industry and rate structure, acquisition and disposal of assets and facilities, operation and construction of transmission and distribution facilities and the recovery of purchased power expenses;

• Weather conditions affecting usage and emergency restoration costs;

• Population growth rates and changes in demographic patterns;

• Changes in customer demand for electricity due to conservation measures and the use of more energy-efficient products;

• General economic conditions, including the impact of an economic downturn or recession on electricity usage;

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

• Changes in tax rates or policies;

• Changes in rates of inflation;

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ACE

• Changes in accounting standards or practices;

• Unanticipated changes in operating expenses and capital expenditures;

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

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

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

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

Any forward-looking statements speak only as to the date of this Quarterly Report on Form 10-Q and ACE undertakes no obligation to update any forward-looking statements to reflect events or circumstances after the date on which such statements are made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for ACE to predict all such factors, nor can ACE assess the impact of any such factor on ACE’s business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.

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

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Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Risk management policies for PHI and its subsidiaries are determined by PHI’s Corporate Risk Management Committee, the members of which are PHI’s Chief Risk Officer, Chief Operating Officer, Chief Financial Officer, General Counsel, Chief Information Officer and other senior executives. The Corporate Risk Management Committee monitors interest rate fluctuation, commodity price fluctuation, and credit risk exposure, and sets risk management policies that establish limits on unhedged risk and determine risk reporting requirements. For information about PHI’s derivative activities, other than the information disclosed herein, refer to Note (2), “Significant Accounting Policies – Accounting For Derivatives,” and Note (15), ”Derivative Instruments and Hedging Activities,” of the Consolidated Financial Statements of PHI included in its Annual Report on Form 10-K for the year ended December 31, 2010 and Item 7A “Quantitative and Qualitative Disclosures About Market Risk” of PHI’s Annual Report on Form 10-K for the year ended December 31, 2010.

Pepco Holdings, Inc.

Commodity Price Risk

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

PHI’s risk management policies place oversight at the senior management level through the Corporate Risk Management Committee, which has the responsibility for establishing corporate compliance requirements for energy market participation. PHI collectively refers to these energy market activities, including its commodity risk management activities, as “energy commodity” activities. PHI uses a value-at-risk (VaR) model to assess the market risk of the energy commodity activities of Pepco Energy Services. PHI also uses other measures to limit and monitor risk in its energy commodity activities, including limits on the nominal size of positions and periodic loss limits. VaR represents the potential fair value loss on energy contracts or portfolios due to changes in market prices for a specified time period and confidence level. PHI uses a delta-gamma VaR estimation model. The other parameters include a 95 percent, one-tailed confidence level and a one-day holding period. Since VaR is an estimate, it is not necessarily indicative of actual results that may occur.

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The table below provides the VaR associated with energy contracts of the Pepco Energy Services segment for the six months ended June 30, 2011 in millions of dollars:

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

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

Pepco Energy Services purchases electric and natural gas futures, swaps, options and forward contracts to hedge price risk in connection with the purchase of physical natural gas and electricity for distribution to customers. Pepco Energy Services accounts for its futures and swap contracts as cash flow hedges of forecasted transactions. Its options contracts and certain commodity contracts that do not qualify as cash flow hedges are marked to market through current earnings. Forward contracts that meet the requirements for normal purchase and normal sale accounting under FASB guidance on derivatives and hedging are accounted for using accrual accounting.

Credit and Nonperformance Risk

The following table provides information on the credit exposure on wholesale energy contracts, net of collateral, to wholesale counterparties as of June 30, 2011, in millions of dollars:

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

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

(b) Exposure before credit collateral - includes the marked to market (MTM) energy contract net assets for open/unrealized transactions, the net receivable/payable for realized transactions and net open positions for contracts not subject to MTM. Amounts due from counterparties are offset by liabilities payable to those counterparties to the extent that legally enforceable netting arrangements are in place. Thus, this column presents the net credit exposure to counterparties after reflecting all allowable netting, but before considering collateral held.

(c) Credit collateral - the face amount of cash deposits, letters of credit and performance bonds received from counterparties, not adjusted for probability of default, and, if applicable, property interests (including oil and gas reserves).

(d) Using a percentage of the total exposure.

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For information regarding “Interest Rate Risk,” please refer to Item 7A, “Quantitative and Qualitative Disclosures About Market Risk,” in Pepco Holdings’ Annual Report on Form 10-K for the year ended December 31, 2010.

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

Item 4. CONTROLS AND PROCEDURES

Pepco Holdings, Inc.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

PHI (the Company) maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed in the Company’s reports under the Securities Exchange Act of 1934, as amended (the Exchange Act), is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s (SEC) rules and forms, and that such information is accumulated and communicated to management, including the Company’s Chief Executive Officer (CEO) and Chief Financial Officer (CFO), as appropriate, to allow timely decisions regarding required disclosure. This control system, no matter how well designed and operated, can provide only reasonable assurance that the objectives of the control system are met. Our disclosure controls and procedures were designed to provide reasonable assurance of achieving their stated objectives. Under the supervision, and with the participation of management, including the CEO and the CFO, Pepco Holdings has evaluated the effectiveness of the design and operation of its disclosure controls and procedures as of June 30, 2011, and, based upon this evaluation, the CEO and the CFO of Pepco Holdings have concluded that these disclosure 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 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 CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

During the three months ended June 30, 2011, there was no change in Pepco Holdings’ internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, Pepco Holdings’ internal control over financial reporting.

Potomac Electric Power Company

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Pepco (the Company) maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed in the Company’s reports under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms, and that such information is accumulated and communicated to management, including the CEO and CFO, as appropriate, to allow timely decisions regarding required disclosure. This control system, no matter how well designed and operated, can provide only reasonable assurance that the objectives of the control system are met. Our disclosure controls and procedures were designed to provide reasonable assurance of achieving their stated objectives. Under the supervision, and with the participation of management, including the CEO and the CFO, Pepco has evaluated the effectiveness of the design and operation of its disclosure controls and procedures as of June 30, 2011, and, based upon this evaluation, the CEO and the CFO of Pepco have concluded that these disclosure controls and procedures are effective to provide reasonable assurance that material information relating to Pepco that is required to be disclosed in reports

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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 CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

During the three months ended June 30, 2011, there was no change in Pepco’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, Pepco’s internal control over financial reporting.

Delmarva Power & Light Company

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

DPL (the Company) maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed in the Company’s reports under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms, and that such information is accumulated and communicated to management, including the CEO and CFO, as appropriate, to allow timely decisions regarding required disclosure. This control system, no matter how well designed and operated, can provide only reasonable assurance that the objectives of the control system are met. Our disclosure controls and procedures were designed to provide reasonable assurance of achieving their stated objectives. Under the supervision, and with the participation of management, including the CEO and the CFO, DPL has evaluated the effectiveness of the design and operation of its disclosure controls and procedures as of June 30, 2011, and, based upon this evaluation, the CEO and the CFO of DPL have concluded that these disclosure 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 CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

During the three months ended June 30, 2011, there was no change in DPL’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, DPL’s internal control over financial reporting.

Atlantic City Electric Company

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

ACE (the Company) maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed in the Company’s reports under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms, and that such information is accumulated and communicated to management, including the CEO and CFO, as appropriate, to allow timely decisions regarding required disclosure. This control system, no matter how well designed and operated, can provide only reasonable assurance that the objectives of the control system are met. Our disclosure controls and procedures were designed to provide reasonable assurance of achieving their stated objectives. Under the supervision, and with the participation of management, including the CEO and the CFO, ACE has evaluated the effectiveness of the design and operation of its disclosure controls and procedures as of June 30, 2011, and, based upon this evaluation, the CEO and the CFO of ACE have concluded that these disclosure controls and procedures are effective to provide reasonable assurance that material information relating to ACE and its subsidiary that is required to be disclosed in reports filed with, or submitted to, the SEC under the Exchange Act (i) is recorded, processed, summarized and reported within the time periods specified by the SEC rules and forms and (ii) is accumulated and communicated to management, including its CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.

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Changes in Internal Control Over Financial Reporting

During the three months ended June 30, 2011, there was no change in ACE’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, ACE’s internal control over financial reporting.

Part II OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

Pepco Holdings

Other than ordinary routine litigation incidental to its and its subsidiaries’ business, PHI is not a party to, and its subsidiaries’ property is not subject to, any material pending legal proceedings except as described in Note (15), “Commitments and Contingencies,” to the Consolidated Financial Statements of PHI included herein, which description is incorporated by reference 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,” to the Financial Statements of Pepco included herein, which description is incorporated by reference 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,” to the Financial Statements of DPL included herein, which description is incorporated by reference 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 (11), “Commitments and Contingencies,” to the Consolidated Financial Statements of ACE included herein, which description is incorporated by reference herein.

Item 1A. RISK FACTORS

Pepco Holdings

For a discussion of the risk factors applicable to Pepco Holdings, Pepco, DPL and ACE, please refer to Item 1A “Risk Factors” in Pepco Holdings’ Annual Report on Form 10-K for the year ended December 31, 2010. There have been no material changes to Pepco Holdings’ risk factors as disclosed in the PHI Form 10-K, except that

(1) Each of the following risk factors supersedes the risk factor with the same heading in the Form 10-K. Except as otherwise noted, each risk factor set forth below applies to each of Pepco Holdings, Pepco, DPL and ACE:

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

Utility companies, including PHI’s utility subsidiaries, have been the subject of public criticism focused on the reliability of their distribution services and the speed with which they are able to respond to outages caused by storm damage. Adverse publicity of this nature may render legislatures, regulatory

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authorities and other government officials less likely to view energy companies such as PHI and its subsidiaries in a favorable light, and may cause PHI and its subsidiaries to be susceptible to less favorable legislative and regulatory outcomes. In this regard, in April 2011, Maryland adopted legislation under which electric utilities operating in Maryland, including Pepco and DPL, could be subject to fines for failure to meet minimum service quality and reliability standards to be developed by the Maryland Public Service Commission (MPSC). In July 2011, the DCPSC adopted regulations that raise the minimum service reliability standards applicable to Pepco in the District of Columbia. The regulations establish specific maximum outage frequency and outage duration levels beginning in 2013 and continuing through 2020. The DCPSC has stated that the regulations are intended to require Pepco to achieve a reliability level in the first quartile of all utilities in the nation by 2020. The existing regulations of the DCPSC provide that Pepco would be subject to civil penalties or other sanctions if it does not meet the required performance levels. Pepco supports objective, fair reliability performance requirements, but believes that the regulations in their current form requireinappropriate adjustments to the method employed to track reliability. As a result, Pepco intends to file a motion with the DCPSC seeking reconsideration of certain aspects of the regulations. There can be no assurance that the requested changes will be implemented or the timing related thereto. While Pepco is currently evaluating the cost and operational changes necessary to comply with the new requirements, Pepco currently believes the standards as adopted may not be realistically achievable at an acceptable cost over the longer term. Other jurisdictions in which PHI utilities have operations have reliability and customer service quality standards, the violation of which could also result in the imposition of penalties.

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

Operation of the Pepco, DPL and ACE transmission and distribution facilities and Pepco Energy Services’ generating facilities (scheduled for deactivation in May 2012) involves many risks, including the breakdown or failure of equipment, accidents, labor disputes and performance below expected levels. Older facilities and equipment, even if maintained in accordance with sound engineering practices, may require significant capital expenditures for additions or upgrades to provide reliable operations or to comply with changing environmental requirements. Natural disasters and weather, including tornadoes, hurricanes and snow and ice storms, also can disrupt transmission and distribution systems. Disruption of the operation of transmission or distribution facilities or the operation of generation facilities below expected output levels, can reduce revenues and result in the incurrence of additional expenses that may not be recoverable from customers or through insurance, including deficiency charges imposed by the PJM Interconnection, LLC (PJM) on generating facilities at a rate of up to two times the capacity payment that the generating facility receives. Furthermore, the transmission and generating facilities of the PHI companies are subject to reliability standards imposed by the North American Electric Reliability Corporation. Failure to comply with the standards may result in substantial monetary penalties.

PHI’s Blueprint for the Future program includes the replacement of customers’ existing electric and gas meters with an 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 Energy Services business of Pepco Energy Services is highly competitive. Under its energy savings performance contracts, Pepco Energy Services may be liable for performance guarantees many years after an installation of a project is completed. (PHI only)

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

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

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(2) The following risk factor supersedes, as it relates to PHI, the risk factor in the Form 10-K with the heading having as its introductory sentence, “PHI’s cash flow, ability to pay dividends and ability to satisfy debt obligations depend on the performance of its operating subsidiaries”:

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

PHI is a holding company that conducts its operations entirely through its subsidiaries, and all of PHI’s consolidated operating assets are held by its subsidiaries. Accordingly, PHI’s cash flow, its ability to satisfy its obligations to creditors and its ability to pay dividends on its common stock are dependent upon the earnings of the subsidiaries and the distribution of such earnings to PHI in the form of dividends. The subsidiaries are separate legal entities and have no obligation to pay any amounts due on any debt or equity securities issued by PHI or to make any funds available for such payment. Because the claims of the creditors of PHI’s subsidiaries are superior to PHI’s entitlement to dividends, the unsecured debt and obligations of PHI are effectively subordinated to all existing and future liabilities of its subsidiaries.

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

The following matters are being reported by each of PHI, Pepco, DPL and ACE, as applicable, in this Quarterly Report on Form 10-Q, in lieu of filing a Current Report on Form 8-K with respect thereto.

Amended and Restated Credit Agreement

On August 1, 2011, PHI, Pepco, DPL and ACE entered into a Second Amended and Restated Credit Agreement with respect to their $1.5 billion unsecured credit facility. The other parties to the second amended and restated credit agreement were the lenders party thereto, Wells Fargo Bank, National Association, as agent, issuer and swingline lender, Bank of America, N.A., as syndication agent and issuer, The Royal Bank of Scotland plc and Citicorp USA, Inc., as co-documentation agents, Wells Fargo Securities, LLC and Merrill Lynch, Pierce, Fenner and Smith Incorporated, as active joint lead arrangers and joint book runners, and Citigroup Global Markets Inc. and RBS Securities, Inc. as passive joint lead arrangers and joint book runners. The second amended and restated credit agreement amends, restates and supersedes in its entirety that certain Amended and Restated Credit Agreement, dated as of May 2,

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2007, among PHI, Pepco, DPL, ACE, the lenders party thereto, Wachovia Bank, National Association, as administrative agent and swingline lender, Citicorp USA, Inc., as syndication agent, The Royal Bank of Scotland, plc, The Bank of Nova Scotia and JPMorgan Chase Bank, N.A., as documentation agents, and Wachovia Capital Markets, LLC and Citigroup Global Markets Inc., as joint lead arrangers and joint book runners.

A brief description of the terms and conditions of the second amended and restated credit agreement, and the amended and restated credit agreement being superseded thereby, that are material to PHI, Pepco, DPL and ACE has been provided in Note (9), “Debt,” to the Consolidated Financial Statements of PHI included herein, and in Part I, Item 2 of this Quarterly Report on Form 10-Q under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Pepco Holdings, Inc. – Capital Resources and Liquidity – Credit Facilities,” which description is incorporated by reference in response to this Item 5. This description is qualified in its entirety by reference to the more detailed provisions of the second amended and restated credit agreement, filed as Exhibit 10.1 to this Quarterly Report on Form 10-Q, and the amended and restated credit agreement, filed as Exhibit 10 to PHI’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2007.

Some or all of the parties to these credit agreements, or their affiliates, have in the past provided investment or commercial banking services to PHI, Pepco, PDL and ACE and their affiliates, including as an underwriter of their securities, for which they received customary fees, underwriting discounts and commissions, and they are likely to provide similar services in the future.

Benefit Plan Modifications

On July 28, 2011, PHI’s Board of Directors approved revisions to certain of existing PHI’s benefit programs, including its tax-qualified, defined benefit pension plan, the Pepco Holdings, Inc. Retirement Plan (the “Retirement Plan”). The changes to the Retirement Plan were effected by PHI in order to establish a more unified approach to PHI’s retirement programs and to further align the benefits offered under its retirement programs. The changes to the Retirement Plan will be effective on or after January 1, 2012 and affect the retirement benefits payable to approximately 750 of PHI’s employees. All full time employees of PHI and certain subsidiaries are eligible to participate in the Retirement Plan. Retirement benefits for all other employees remain unchanged.

As part of this process, PHI’s Board of Directors also approved a new, non-tax-qualified Supplemental Executive Retirement Plan (“SERP”) which will replace PHI’s two pre-existing supplemental retirement plans, effective August 1, 2011. Following the effective date of the SERP, pursuant to amendments to such plans, the Conectiv SERP Plan and the PHI Combined SERP Plan will be closed to new participants. The principal purposes of the SERP are to provide competitive retirement benefits, to protect eligible participants against reductions in retirement benefits due to tax law limitations on qualified plans, to encourage the continued employment of and to attract new employees to work for PHI and to establish a more unified approach to its retirement programs. The establishment of the new SERP is consistent with PHI’s efforts to align retirement benefits for PHI and its subsidiaries with current market practices, as recommended by the Compensation/Human Resources Committee’s independent compensation consultant. The SERP is intended to provide a supplemental retirement benefit for participants so as to provide similarly situated participants with retirement benefits that are the same or similar in value as compared to the benefits provided under the existing SERPs. Where the existing SERP arrangements provide a greater benefit than the retirement benefit established under the SERP that greater benefit will continue to apply to participants who previously participated in the existing plan.

Eligibility for participation in the SERP is determined by the Compensation/Human Resources Committee administering the SERP (a “participant”). Since the SERP is a supplemental retirement plan, participation will be limited to certain members of PHI’s management whose benefits may be limited due to restrictions on benefits payable under PHI’s tax-qualified plan. All participants currently participating in PHI’s existing SERP plans will be eligible to participate in the new SERP as of its effective date

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The SERP provides a supplemental retirement benefit to participants based on two factors, which are the same factors used to provide benefits under the existing SERPs. First, the SERP will protect eligible participants from reductions in retirement benefits due to tax law limitations placed on the benefits available under the Retirement Plan. Under provisions of the Internal Revenue Code, the level of a participant’s pension benefit under a tax-qualified pension plan, such as the Retirement Plan, and the amount of compensation that may be taken into account in calculating that benefit are limited (the “Qualified Plan Limitations”). In addition, under the terms of the Retirement Plan, salary deferrals elected by the participant under PHI’s deferred compensation plans (other than the participant’s pre-tax contributions made under the Retirement Savings Plan) are not taken into account as compensation for purposes of calculating a participant’s retirement benefit (the “Deferred Compensation Exclusion”). If applicable, these provisions have the effect of reducing the participant’s retirement benefit under the Retirement Plan relative to what the participant otherwise would be entitled to receive under the plan’s benefit formula. If a participant’s retirement benefits under the Retirement Plan are reduced by either or both of these limitations, PHI, under the SERP, will pay a supplemental retirement benefit to the participant equal to the difference between (i) the participant’s actual benefit under the Retirement Plan and (ii) what the participant would have received under the Retirement Plan (A) were the Qualified Plan Limitations not applicable and (B) had the amount of the Deferred Compensation Exclusion been included in the compensation base. Second, the SERP will pay a supplemental retirement benefit to the participant calculated as if the final average pay included the average of the three highest awards under the executive incentive compensation plan within the five consecutive years immediately preceding retirement.

Vesting will occur under the SERP when a participant is eligible for a retirement annuity (including an annuity which is distributed in the form of an actuarially reduced benefit). Generally, a participant will become vested upon the later of attaining age 65 or being credited with five years of service. Earlier vesting is permitted under the SERP when a participant attains age 55 or older and is credited with at least 10 years of service under the SERP. The benefit payable under the SERP is the excess (if any) of the retirement benefit determined using the formula described below, over the retirement benefit provided to the participant under PHI’s tax qualified pension benefit plan and the retirement benefit provided under PHI’s two pre-existing supplemental executive retirement plans. Generally, the formula used for determining retirement benefits uses years of benefit service and “final average pay” to establish the amount that should be payable as an annual benefit for the participant’s lifetime starting at normal retirement age. For all participants, the formula is 1.45% of final average pay multiplied by the participant’s years of service. This new formula results in benefits that generally target median peer group retirement benefits based upon the research provided by the Compensation/Human Resources Committee’s independent consultant Pearl Meyer and Partners, Inc.

Generally, the only form of benefit intended to be provided under the SERP will be a lifetime annuity. This benefit will be a single life annuity for participants who are not married at the time the benefit starts to be paid, and will be in the form of a 50% joint and survivor annuity for married participants paid in the form of level payments during the life of the participant, and, thereafter, to the participant’s surviving spouse, if any, at a rate of 50% of the rate paid to the participant for the surviving spouse’s lifetime. The only exceptions to this annuity benefit are (1) in the case of any participant in the SERP who also participates in the Conectiv Supplemental Executive Retirement Plan (which itself pays benefits in the form of a lump sum), a lump sum payment of the value of the benefit payable under the SERP will be paid out if the value of the benefit payable under the SERP is considered to be “de minimis” (as explained below), and (2) a lump sum payment of the value of the benefit payable under the SERP will be paid out to any participant in the SERP who does not participate in any other supplemental executive retirement plan, but only if the value of the benefit payable under this Plan is considered to be “de minimis.” Lump sums instead of annuities are also payable in certain limited circumstances following a Change of Control

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(as defined below). A benefit shall be considered to be de minimis if the present value is less than the “applicable amount” as defined in Section 402(g)(1)(B) of the Internal Revenue Code (the limitation on elective contributions to 401(k) plans, which is currently $16,500, and is adjusted annually for inflation).

The benefit payment under the SERP will commence immediately following the participant’s separation from service. Generally, a participant can retire and receive an unreduced annuity benefit under the SERP at the later of age 65 or being credited with five years of service. In addition, an unreduced annuity is payable under the SERP to a participant with 20 years of service at or after attaining age 62 or to a participant with 35 years of service at or after attaining age 58. A participant who is not eligible for an unreduced annuity but who retires after age 55 and with at least 10 years of service will be eligible for and will receive an annuity that is reduced based on the extent to which the participant’s separation from service is prior to the date the participant would have been eligible for an unreduced annuity (i.e., at age 65 generally, but age 62 for participants with 20 or more years of service and age 58 for participants with 35 or more years of service). To the extent required under applicable IRS rules, the commencement of the payment of benefits under the SERP will be delayed six months, with the first payment being equal to the full amount that would have been payable during such period absent the delay. The reduction for determining the reduced annuity for benefits commencing prior to eligibility for unreduced benefit will be 3% per year (0.25% for each month early).

In the event a participant dies while employed by PHI, but after the date the participant has become vested in his or her benefit under the SERP (i.e., after attaining age 55 or older with 10 or more years of service, or after attaining age 65), and the participant is married at the time of his or her death, a death benefit will be paid to the surviving spouse in the form of an annuity equal to the annuity that would have been paid had the participant retired on the day of his or her death, commenced an annuity in the form of a 50% joint and survivor annuity, and then died next day. No death benefit is payable under the SERP in the case of a single participant if a single participant dies during the term of his or her employment with PHI or if the death of the single participant occurs after the single participant has started to receive an annuity payment under the SERP.

Any participant who terminates employment prior to becoming vested under the SERP will forfeit any benefits accrued thereunder. In addition, regardless of a participant’s years of service, his or her benefit under the SERP will be forfeited if the participant’s employment is terminated for “cause” (as determined by the committee administering the SERP).

In the event there is a change of control as defined in the SERP, each participant shall be fully vested in his or her accrued benefit under the SERP. The payment of benefits shall be as described above for any participant who would have been vested without regard to the change of control at the time of his or her separation from service. In all other cases, including any participant who separates from service prior to the date such participant is eligible for an annuity benefit, the participant will receive a lump sum payment of the actuarial present value of his or her accrued benefit paid as soon as practicable following the participant’s separation from service. Payments are subject to the six month delay rule where applicable (for a participant who is a “specified employee”). The definition of the term “change of control” contained in this SERP is substantially similar to the definition of “change in control” under the existing supplemental benefit plans of PHI.

The foregoing is a description of the material provisions of the SERP and is qualified in its entirety by reference to the more detailed provisions of the SERP and the amendments to each of the Pepco Holdings, Inc. Combined Executive Retirement Plan and the Conectiv Supplemental Executive Retirement Plan, each of which is attached hereto as Exhibits 10.2, 10.3 and 10.4, respectively, to this Quarterly Report on Form 10-Q.

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Item 6. EXHIBITS

The documents listed below are being filed, furnished or submitted on behalf of PHI, Pepco, DPL and/or ACE, as indicated. The warranties, representations and covenants contained in any of the agreements included or incorporated by reference herein or which appear as exhibits hereto should not be relied upon by buyers, sellers or holders of PHI’s or its subsidiaries’ securities and are not intended as warranties, representations or covenants to any individual or entity except as specifically set forth in such agreement.

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
4.1	DPL	Form of First Mortgage Bond, Series 2001C Collateral Bonds due May 1, 2026	Included in Exhibit 4.3 hereto.
4.2	DPL	One Hundred and Seventh Supplemental Indenture	Filed herewith.
4.3	DPL	One Hundred and Eighth Supplemental Indenture	Exhibit 4.2 to DPL’s Form 8-K, June 3, 2011.
10.1	PHI, Pepco, DPL, ACE	Second Amended and Restated Credit Agreement, dated as of August 1, 2011, among PHI, Pepco, DPL and ACE, the lenders party thereto, Wells Fargo Bank, National Association, as agent, issuer and swingline lender, Bank of America, N.A., as syndication agent and issuer, The Royal Bank of Scotland plc and Citicorp USA, Inc., as co-documentation agents, Wells Fargo Securities, LLC and Merrill Lynch, Pierce, Fenner and Smith Incorporated, as active joint lead arrangers and joint book runners, and Citigroup Global Markets Inc. and RBS Securities, Inc. as passive joint lead arrangers and joint book runners	Filed herewith.
10.2	PHI	The Pepco Holdings, Inc. 2011 Supplemental Executive Retirement Plan	Filed herewith.
10.3	PHI	Amendment to the Pepco Holdings, Inc. Combined Executive Retirement Plan	Filed herewith.
10.4	DPL	Amendment to the Conectiv Supplemental Executive Retirement Plan	Filed herewith.
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.

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Exhibit No.	Registrant(s)	Description of Exhibit	Reference
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.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, each of the registrants has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	PEPCO HOLDINGS, INC. (PHI) POTOMAC ELECTRIC POWER COMPANY (Pepco) DELMARVA POWER & LIGHT COMPANY (DPL) ATLANTIC CITY ELECTRIC COMPANY (ACE) (Registrants)
August 3, 2011	By	/s/ ANTHONY J. KAMERICK
		Anthony J. Kamerick
		Senior Vice President and Chief Financial Officer, PHI, Pepco and DPL Chief Financial Officer, ACE

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INDEX TO EXHIBITS FILED HEREWITH OR INCORPORATED BY REFERENCE HEREIN

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
4.1	DPL	Form of First Mortgage Bond, Series 2001C Collateral Bonds due May 1, 2026	Included in Exhibit 4.3 hereto.
4.2	DPL	One Hundred and Seventh Supplemental Indenture	Filed herewith.
4.3	DPL	One Hundred and Eighth Supplemental Indenture	Exhibit 4.2 to DPL’s Form 8-K, June 3, 2011.
10.1	PHI, Pepco, DPL, ACE	Second Amended and Restated Credit Agreement, dated as of August 1, 2011, among PHI, Pepco, DPL and ACE, the lenders party thereto, Wells Fargo Bank, National Association, as agent, issuer and swingline lender, Bank of America, N.A., as syndication agent and issuer, The Royal Bank of Scotland plc and Citicorp USA, Inc., as co-documentation agents, Wells Fargo Securities, LLC and Merrill Lynch, Pierce, Fenner and Smith Incorporated, as active joint lead arrangers and joint book runners, and Citigroup Global Markets Inc. and RBS Securities, Inc. as passive joint lead arrangers and joint book runners	Filed herewith.
10.2	PHI	The Pepco Holdings, Inc. 2011 Supplemental Executive Retirement Plan	Filed herewith.
10.3	PHI	Amendment to the Pepco Holdings, Inc. Combined Executive Retirement Plan	Filed herewith.
10.4	DPL	Amendment to the Conectiv Supplemental Executive Retirement Plan	Filed herewith.
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.

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

INDEX TO EXHIBITS SUBMITTED HEREWITH

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