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 September 30, 2010

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

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

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

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

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

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

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

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

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

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

Registrant	Number of Shares of Common Stock of             the Registrant Outstanding at September 30, 2010
Pepco Holdings	224,500,318 ($.01 par value)
Pepco	100 ($.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		108
Item 3.	- Quantitative and Qualitative Disclosures About Market Risk		175
Item 4.	- Controls and Procedures		177
PART II	OTHER INFORMATION		179
Item 1.	- Legal Proceedings		179
Item 1A	- Risk Factors		179
Item 2.	- Unregistered Sales of Equity Securities and Use of Proceeds		184
Item 3.	- Defaults Upon Senior Securities		185
Item 4.	- Reserved		185
Item 5.	- Other Information		185
Item 6.	- Exhibits		186
Signatures			187

GLOSSARY OF TERMS

Term	Definition
2.7% Notes	PHI’s 2.7% Notes due October 1, 2015
5.9% Notes	PHI’s 5.9% Notes due 2016
6.0% Notes	PHI’s 6.0% Notes due 2019
6.125% Notes	PHI’s 6.125% Senior Notes due 2017
6.45% Notes	PHI’s 6.45% Senior Notes due 2012
7.45% Notes	PHI’s 7.45% Senior Notes due 2032
ACE	Atlantic City Electric Company
ACE Funding	Atlantic City Electric Transition Funding LLC
ADITC	Accumulated deferred investment tax credits
AOCL	Accumulated other comprehensive loss
ASC	Accounting Standards Codification
BGS	Basic Generation Service (the supply of electricity by ACE to retail customers in New Jersey who have not elected to purchase electricity from a competitive supplier)
Bondable Transition Property	The principal and interest payments on the Transition Bonds and related taxes, expenses and fees
BSA	Bill Stabilization Adjustment
Calpine	Calpine Corporation
CERCLA	Comprehensive Environmental Response, Compensation, and Liability Act of 1980
Conectiv	A wholly owned subsidiary of PHI and the parent of DPL and ACE
Competitive Energy	Competitive energy generation, marketing and supply
Conectiv Energy	Conectiv Energy Holding Company and its subsidiaries
Cooling Degree Days	Daily difference in degrees by which the mean (high and low divided by 2) dry bulb temperature is above a base of 65 degrees Fahrenheit
CSA	Credit Support Annex
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
Delta Project	Conectiv Energy’s 565-megawatt combined cycle generating facility that is under construction
DOE	U.S. Department of Energy
DPL	Delmarva Power & Light Company
DPSC	Delaware Public Service Commission
EDIT	Excess Deferred Income Taxes
Energy Services	Energy savings performance contracting services 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

i

Term	Definition
FHACA	Flood Hazard Area Control Act
GAAP	Accounting principles generally accepted in the United States of America
GCR	Gas Cost Rate
GWh	Gigawatt hour
Heating Degree Days	Daily difference in degrees by which the mean (high and low divided by 2) dry bulb temperature is below a base of 65 degrees Fahrenheit
IRS	Internal Revenue Service
ISDA	International Swaps and Derivatives Association
ISRA	New Jersey’s Industrial Site Recovery Act
MDC	MDC Industries, Inc.
MFVRD	Modified fixed variable rate design
Mirant	Mirant Corporation
MMBtu	One Million British Thermal Units
MPSC	Maryland Public Service Commission
MSCG	Morgan Stanley Capital Group, Inc.
MWh	Megawatt hours
New Jersey Societal Benefit Programs	Various NJBPU - mandated social programs for which ACE receives revenues to recover costs
NJBPU	New Jersey Board of Public Utilities
NJDEP	New Jersey Department of Environmental Protection
Normalization provisions	Sections of the Internal Revenue Code and related regulations that dictate how excess deferred income taxes resulting from the corporate income tax rate reduction enacted by the Tax Reform Act of 1986 and accumulated deferred investment tax credits should be treated for ratemaking purposes
NUGs	Non-utility generators
NYMEX	New York Mercantile Exchange
Panda PPA	PPA between Pepco and Panda-Brandywine, L.P.
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

ii

Term	Definition
Power Delivery	PHI’s Power Delivery Business
PPA	Power purchase agreement
PRP	Potentially responsible party
Purchase Agreement	The agreement dated April 20, 2010, between PHI and Calpine for the purchase of the Generation Business
PUHCA 2005	Public Utility Holding Company Act of 2005
QSPE	Qualifying special purpose entity
RAR	IRS revenue agent’s report
RECs	Renewable energy credits
Regulated T&D Electric Revenue	Revenue from the transmission and the delivery of electricity to PHI’s customers within its service territories at regulated rates
Revenue Decoupling Adjustment	An adjustment equal to the amount by which revenue from distribution sales differs from the revenue that Pepco and DPL are entitled to earn based on the approved distribution charge per customer
ROE	Return on equity
SEC	Securities and Exchange Commission
Transition Bond Charge	Revenue ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds and related taxes, expenses and fees
Transition Bonds	Transition Bonds issued by ACE Funding
Treasury rate lock	A hedging transaction that allows a company to “lock in” a specific interest rate corresponding to the rate of a designated Treasury bond for a determined period of time
VaR	Value at Risk

iii

PART I FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

Listed below is a table that sets forth, for each registrant, the page number where the information is contained herein.

	Registrants
Item	Pepco Holdings		Pepco*		DPL*		ACE
Consolidated Statements of Income (Loss)		2		56		73		93
Consolidated Statements of Comprehensive Income		3		N/A		N/A		N/A
Consolidated Balance Sheets		4		57		74		94
Consolidated Statements of Cash Flows		6		59		76		96
Notes to Consolidated Financial Statements		7		60		77		97

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

1

PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (LOSS)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
	(millions of dollars, except per share data)
Operating Revenue
Power Delivery	$	1,600		$	1,428		$	4,011		$	3,895
Pepco Energy Services		457			611			1,480			1,828
Other		10			11			31			30
Total Operating Revenue		2,067			2,050			5,522			5,753
Operating Expenses
Fuel and purchased energy		1,319			1,442			3,696			4,167
Other services cost of sales		38			25			85			60
Other operation and maintenance		228			213			636			618
Restructuring charge		14			—			14			—
Depreciation and amortization		104			93			286			265
Other taxes		130			100			327			279
Deferred electric service costs		13			(32	)		(69	)		(116	)
Effects of Pepco divestiture-related claims		9			(26	)		11			(40	)
Total Operating Expenses		1,855			1,815			4,986			5,233
Operating Income		212			235			536			520
Other Income (Expenses)
Interest and dividend income		—			—			—			2
Interest expense		(68	)		(85	)		(240	)		(254	)
Gain (loss) from equity investments		—			1			(1	)		2
Loss on extinguishment of debt		(135	)		—			(135	)		—
Other income		6			4			17			12
Other expenses		—			—			—			(1	)
Total Other Expenses		(197	)		(80	)		(359	)		(239	)
Income from Continuing Operations Before Income Tax Expense		15			155			177			281
Income Tax (Benefit) Expense related to Continuing Operations		(6	)		51			52			97
Net Income from Continuing Operations		21			104			125			184
(Loss) Income from Discontinued Operations, net of Income Taxes		(4	)		20			(126	)		10
Net Income (Loss)		17			124			(1	)		194
Retained Earnings at Beginning of Period		1,130			1,222			1,268			1,271
Dividends paid on common stock		(61	)		(59	)		(181	)		(178	)
Retained Earnings at End of Period	$	1,086		$	1,287		$	1,086		$	1,287
Basic and Diluted Share Information
Weighted average shares outstanding (millions)		224			221			223			220
Earnings per share of common stock from Continuing Operations	$	.09		$	.47		$	.56		$	.84
(Loss) Earnings per share of common stock from Discontinued Operations		(.01	)		.09			(.56	)		.04
Basic and diluted earnings (loss) per share	$	.08		$	.56		$	—		$	.88

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

2

PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
	(millions of dollars)
Net income (loss)	$	17		$	124		$	(1	)	$	194
Other comprehensive income (loss) from continuing operations
Gains (losses) on commodity derivatives designated as cash flow hedges:
Losses arising during period		(38	)		(3	)		(116	)		(109	)
Amount of losses reclassified into income		23			36			110			125
Net (losses) gains on commodity derivatives		(15	)		33			(6	)		16
Losses on treasury rate locks reclassified into income		15			1			18			4
Amortization of gains and losses for prior service costs		—			—			4			(10	)
Other comprehensive income from continuing operations, before income taxes		—			34			16			10
Income tax expense related to continuing operations		—			14			7			4
Other comprehensive income from continuing operations, net of income taxes		—			20			9			6
Other comprehensive income (loss) from discontinued operations, net of income taxes		13			30			84			(2	)
Comprehensive income	$	30		$	174		$	92		$	198

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

3

PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30, 2010			December 31, 2009
	(millions of dollars)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	28		$	44
Restricted cash equivalents		14			11
Accounts receivable, less allowance for uncollectible accounts of $57 million and $44 million, respectively		1,058			1,019
Inventories		140			124
Derivative assets		38			22
Prepayments of income taxes		183			167
Deferred income tax assets, net		43			126
Prepaid expenses and other		65			67
Conectiv Energy assets held for sale		169			346
Total Current Assets		1,738			1,926
INVESTMENTS AND OTHER ASSETS
Goodwill		1,407			1,407
Regulatory assets		1,786			1,801
Investment in finance leases held in trust		1,411			1,386
Income taxes receivable		119			141
Restricted cash equivalents		2			4
Assets and accrued interest related to uncertain tax positions		13			12
Derivative assets		7			16
Other		192			194
Conectiv Energy assets held for sale		7			29
Total Investments and Other Assets		4,944			4,990
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		11,918			11,431
Accumulated depreciation		(4,389	)		(4,190	)
Net Property, Plant and Equipment		7,529			7,241
Conectiv Energy assets held for sale		—			1,622
Total Property, Plant and Equipment		7,529			8,863
TOTAL ASSETS	$	14,211		$	15,779

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

4

PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30, 2010			December 31, 2009
	(millions of dollars, except shares)
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Short-term debt	$	540		$	530
Current portion of long-term debt and project funding		75			536
Accounts payable and accrued liabilities		547			574
Capital lease obligations due within one year		7			7
Taxes accrued		116			47
Interest accrued		80			68
Derivative liabilities		77			67
Other		307			282
Liabilities associated with Conectiv Energy assets held for sale		84			191
Total Current Liabilities		1,833			2,302
DEFERRED CREDITS
Regulatory liabilities		568			613
Deferred income taxes, net		2,553			2,600
Investment tax credits		27			35
Pension benefit obligation		217			290
Other postretirement benefit obligations		414			409
Income taxes payable		8			5
Liabilities and accrued interest related to uncertain tax positions		133			96
Derivative liabilities		35			54
Other		153			147
Liabilities associated with Conectiv Energy assets held for sale		16			19
Total Deferred Credits		4,124			4,268
LONG-TERM LIABILITIES
Long-term debt		3,598			4,470
Transition bonds issued by ACE Funding		343			368
Long-term project funding		15			17
Capital lease obligations		89			92
Total Long-Term Liabilities		4,045			4,947
COMMITMENTS AND CONTINGENCIES (NOTE 14)
EQUITY
Common stock, $.01 par value – authorized 400,000,000 shares, 224,500,318 and 222,269,895 shares outstanding, respectively		2			2
Premium on stock and other capital contributions		3,263			3,227
Accumulated other comprehensive loss		(148	)		(241	)
Retained earnings		1,086			1,268
Total Shareholders’ Equity		4,203			4,256
Non-controlling interest		6			6
Total Equity		4,209			4,262
TOTAL LIABILITIES AND EQUITY	$	14,211		$	15,779

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

5

PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months  Ended September 30,
	2010			2009
	(millions of dollars)
OPERATING ACTIVITIES
Net (loss) income	$	(1	)	$	194
Loss (income) from discontinued operations		126			(10	)
Adjustments to reconcile net (loss) income to net cash from operating activities:
Depreciation and amortization		286			265
Non-cash rents from cross-border energy lease investments		(41	)		(41	)
Effects of Pepco divestiture-related claims		11			(40	)
Changes in restricted cash equivalents related to Mirant settlement		—			102
Deferred income taxes		258			246
Losses on treasury rate locks reclassified into income		18			4
Other		(16	)		(5	)
Changes in:
Accounts receivable		(39	)		105
Inventories		(16	)		8
Prepaid expenses		(8	)		(35	)
Regulatory assets and liabilities, net		(103	)		(157	)
Accounts payable and accrued liabilities		11			(213	)
Pension contributions		(100	)		(300	)
Pension benefit obligation		50			71
Cash collateral related to derivative activities		(23	)		13
Taxes accrued		(98	)		(70	)
Interest accrued		11			22
Other assets and liabilities		50			25
Conectiv Energy net assets held for sale		184			124
Net Cash From Operating Activities		560			308
INVESTING ACTIVITIES
Investment in property, plant and equipment		(548	)		(446	)
Proceeds from the sale of Conectiv Energy wholesale power generation business		1,635			—
Changes in restricted cash equivalents		(2	)		(1	)
Net other investing activities		2			5
Investment in property, plant and equipment associated with Conectiv Energy assets held for sale		(138	)		(148	)
Net Cash From (Used By) Investing Activities		949			(590	)
FINANCING ACTIVITIES
Dividends paid on common stock		(181	)		(178	)
Common stock issued for the Dividend Reinvestment Plan		23			23
Issuances of common stock		13			14
Issuances of long-term debt		102			110
Reacquisition of long-term debt		(1,466	)		(75	)
Issuances of short-term debt, net		10			28
Cost of issuances		(6	)		(4	)
Net other financing activities		4			(5	)
Net financing activities associated with Conectiv Energy assets held for sale		(10	)		5
Net Cash Used by Financing Activities		(1,511	)		(82	)
Net Decrease in Cash and Cash Equivalents		(2	)		(364	)
Cash and Cash Equivalents of discontinued operations		(16	)		(1	)
Cash and Cash Equivalents at Beginning of Period		46			384
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	28		$	19
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash received for income taxes, net	$	14		$	74

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 delivery and supply of natural gas (Power Delivery):

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

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

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

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

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

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

Power Delivery

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

Each company is responsible for the delivery of electricity and, in the case of DPL, natural gas, in its service territory, for which it is paid tariff rates established by the applicable local public service commissions. Each company also supplies electricity at regulated rates to retail customers in its service territory who do not elect to purchase electricity from a competitive energy supplier. The regulatory term for this supply service is Standard Offer Service in Delaware, the District of Columbia and Maryland, and Basic Generation Service (BGS) in New Jersey. In this Form 10-Q, these supply services are referred to generally as Default Electricity Supply.

7

PEPCO HOLDINGS

Competitive Energy

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

The business of the Pepco Energy Services segment has consisted primarily of (i) the retail supply of electricity and natural gas and (ii) providing energy savings performance contracting services principally to federal, state and local government customers, and designing, constructing and operating combined heat and power and central energy plants for customers (Energy Services). Pepco Energy Services also owns and operates two oil-fired generation facilities. In December 2009, PHI announced that it will wind down the retail energy supply component of the Pepco Energy Services business. Pepco Energy Services is implementing this wind down by not entering into any new supply contracts, while continuing to perform under its existing supply contracts through 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 September 30, 2010 and 2009 were $377 million and $568 million, respectively, while operating income for the same periods was $15 million and $21 million, respectively. Operating revenues related to the retail energy supply business for the nine months ended September 30, 2010 and 2009 were $1,275 million and $1,733 million, respectively, while operating income for the same periods was $45 million and $74 million, respectively. In connection with the operation of the retail energy supply business, as of September 30, 2010, Pepco Energy Services provided letters of credit of $140 million and posted net cash collateral of $150 million. These collateral requirements, which are based on existing wholesale energy purchase and sale contracts and current market prices, will decrease as the contracts expire and the collateral is expected to be fully released over time by June 1, 2014. The Energy Services business will not be affected by the wind down of the retail energy supply business.

Other Business Operations

Through its subsidiary Potomac Capital Investment Corporation (PCI), PHI maintains a portfolio of cross-border energy lease investments, with a book value at September 30, 2010 of approximately $1.4 billion. This activity constitutes a third operating segment for financial reporting purposes, which is designated as “Other Non-Regulated.”

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, 2009, as revised and superseded by PHI’s Form 8-K filed on September 17, 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 September 30, 2010, in accordance with GAAP. The year-end December 31, 2009 balance sheet was derived from audited financial statements, but does not include all disclosures required by GAAP. Interim results for the three and nine months ended September 30, 2010 may not be indicative of PHI’s results that will be realized for the full year ending December 31, 2010, since its Power Delivery business and the retail energy supply business of Pepco Energy Services are seasonal.

Use of Estimates

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

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

Storm Costs

In the third quarter of 2010, Pepco recorded $23 million in restoration costs related to severe summer storms, of which $13 million was charged to Other Operation and Maintenance expense and $10 million was recorded as capital expenditures. A portion of the recorded costs of the restoration work relates to services provided by outside contractors and other utilities that were not billed as of September 30, 2010, and accordingly have been estimated. These estimates are subject to adjustment when the actual billings are received in the fourth quarter of 2010. The actual billings may vary from the estimates of such billings.

During the first quarter of 2010, Pepco, DPL and ACE incurred significant costs associated with the February 2010 severe winter storms. The actual billings related to the February storms were received by the end of the second quarter with final costs approximating $32 million, with $15 million charged to Other Operation and Maintenance expense and $17 million recorded as capital expenditures. Other Operation and Maintenance expense was further decreased by approximately $5 million during the third quarter due to an adjustment for recoverable February storm costs incurred by Pepco in accordance with the Maryland Public Service Commission rate order issued in August 2010.

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Network Service Transmission Rates

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

Consolidation of Variable Interest Entities

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

ACE Power Purchase Agreements (PPAs)

Pepco Holdings, through its ACE subsidiary, is a party to three PPAs with unaffiliated, non-utility generators (NUGs). Due to a variable element in the pricing structure of the PPAs, Pepco Holdings potentially assumes the variability in the operations of the generating facilities related to the NUGs and, therefore, has a variable interest in the entities. Despite exhaustive efforts to obtain information from these entities during the three months ended September 30, 2010, PHI was unable to obtain sufficient information to conduct the analysis required under FASB guidance to determine whether these three entities were variable interest entities or if ACE was the primary beneficiary. As a result, Pepco Holdings has applied the scope exemption from the guidance for enterprises that have conducted exhaustive efforts to obtain the necessary information, but have not been able to obtain such information.

Net purchase activities with the NUGs for the three months ended September 30, 2010 and 2009, were approximately $82 million and $70 million, respectively, of which approximately $74 million and $66 million, respectively, consisted of power purchases under the PPAs. Net purchase activities with the NUGs for the nine months ended September 30, 2010 and 2009, were approximately $222 million and $214 million, respectively, of which approximately $203 million and $197 million, respectively, consisted of power purchases under the PPAs. The power purchase costs are recoverable from ACE’s customers through regulated rates.

DPL Renewable Energy Transactions

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

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One of the land-based wind facilities became operational and went into service in December 2009. DPL is obligated to purchase energy and RECs from this facility through 2024 in amounts generated and delivered not to exceed 50.25 megawatts at rates that are primarily fixed. DPL’s purchases under this PPA totaled $2 million for the three months ended September 30, 2010 and $8 million for the nine months ended September 30, 2010. Payments under the other wind agreements, which have terms ranging from 20 to 25 years, are currently expected to start in the fourth quarter of 2010 for the other two land-based contracts and 2016 for the offshore contract, if the projects are ultimately completed and become operational. When they become operational, DPL is obligated to purchase energy and RECs in amounts generated and delivered by the sellers at rates that are primarily fixed under these agreements. Under one of the agreements, DPL is also obligated to purchase the capacity associated with the facility at rates that are generally fixed. The inability of the offshore wind facility developer to obtain all necessary permits and financing commitments could result in setbacks in the construction schedules and the operational start dates of the offshore wind facility. If the wind facilities are not operational by specified dates, DPL has the right to terminate the PPAs. The term of the agreement with the solar facility is 20 years and DPL is obligated to purchase RECs in an amount up to seventy percent of the energy output from the solar facility at a fixed price once the facility is operational, which is expected to be by the end of 2011.

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

ACE Transition Funding, LLC

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

Goodwill

Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired at the acquisition date. Substantially all of Pepco Holdings’ goodwill was generated by Pepco’s acquisition of Conectiv in 2002 and was allocated entirely to Pepco Holdings’ Power Delivery reporting unit based on the aggregation of its regulated public utility company components for purposes of testing for impairment. Pepco Holdings tests its goodwill for impairment annually as of November 1 and whenever an event occurs or circumstances change in the interim that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Factors that may result in an interim impairment test include, but are not limited to: a change in the identified reporting units; an adverse change in business conditions; a decline in PHI’s stock price causing market capitalization to fall further below book value; an adverse regulatory action; or an impairment of long-lived assets in the reporting unit. PHI concluded that an interim impairment test was not required during the nine months ended September 30, 2010 as described in Note (6), “Goodwill.”

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Long-Lived Asset Impairment Evaluation

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

PHI recorded an after-tax write-down of the long-lived assets of Conectiv Energy of $67 million for the nine months ended September 30, 2010. The write-down is included as a component of the discontinued operations loss for the nine months ended September 30, 2010.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in Pepco Holdings’ gross revenues were $118 million and $81 million for the three months ended September 30, 2010 and 2009, respectively, and $280 million and $224 million for the nine months ended September 30, 2010 and 2009, respectively.

Reclassifications and Adjustments

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

In the third quarter of 2010, Pepco recorded an adjustment to correct certain errors related to other taxes which resulted in a decrease to Taxes other than income taxes expense of $5 million (pre-tax) for the three and nine months ended September 30, 2010.

During 2010, PHI recorded various adjustments to income tax expense to reflect primarily the benefit from additional deductions related to executive compensation that had erroneously not been included in tax returns prior to 2008, a reduction in income tax expense associated with errors related to the deferred tax assets established in connection with the District of Columbia net operating losses, and an increase to income tax expense associated with the reversal of erroneously recorded interest income for state income tax purposes related to uncertain and effectively settled tax positions. These adjustments resulted in a decrease to income tax expense of $7 million related to continuing operations for the three months ended September 30, 2010 and a decrease to income tax expense of $1 million related to continuing operations for the nine months ended September 30, 2010.

In the third quarter of 2010, PHI recorded adjustments to reverse revenue erroneously recognized in the second quarter of 2010 associated with its discontinued operations. The adjustments resulted in an increase in net loss from discontinued operations of $7 million (pre-tax) for the three months ended September 30, 2010.

(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Transfers and Servicing (ASC 860)

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

The guidance was effective for transfers of financial assets occurring in fiscal periods beginning on January 1, 2010 for PHI. As of January 1, 2010, PHI has adopted the provisions of this guidance and determined that the guidance did not have a material impact on its overall financial condition, results of operations, or cash flows.

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Consolidation of Variable Interest Entities (ASC 810)

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

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

Fair Value Measurements and Disclosures (ASC 820)

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

Subsequent Events (ASC 855)

The FASB issued new guidance which eliminated the requirement for PHI to disclose the date through which it has evaluated subsequent events beginning with its March 31, 2010 financial statements.

(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Fair Value Measurements and Disclosures (ASC 820)

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

Receivables (ASC 310)

The new FASB disclosure requirements relating to an entity’s exposure to credit losses from financing receivables will be effective beginning with PHI’s December 31, 2010 financial statements. The new guidance requires disclosures about the credit quality of receivables with maturities of greater than one year and related accounting policies. PHI is evaluating the impact of this new requirement on the disclosures related to its financial statements.

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(5) SEGMENT INFORMATION

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

	Three Months Ended September 30, 2010
	(millions of dollars)
	Power Delivery			Pepco Energy Services		Other Non- Regulated			Corporate and Other (a)			PHI Consolidated
Operating Revenue	$	1,600		$	457	$	15		$	(5	)	$	2,067
Operating Expenses (b) (c)		1,418	(d)		442		—			(5	)		1,855
Operating Income		182			15		15			—			212
Interest Income		—			—		—			—			—
Interest Expense		51			3		2			12			68
Loss on Extinguishment of Debt		—			—		—			135			135
Other Income (Expense)		6			—		(1	)		1			6
Preferred Stock Dividends		—			—		1			(1	)		—
Income Tax Expense (Benefit)		61			4		2			(73	)(e)		(6	)
Net Income (Loss) from Continuing Operations		76			8		9			(72	)		21
Total Assets		10,569			617		1,524			1,325			14,035
Construction Expenditures	$	178		$	2	$	—		$	4		$	184

(a) Total Assets in this column includes Pepco Holdings’ goodwill balance of $1.4 billion, substantially all of which is allocated to the Power Delivery segment for purposes of assessing impairment. Additionally, Corporate and Other includes intercompany amounts of $(5) million for Operating Revenue, $(2) million for Operating Expense, $(6) million for Interest Income, $(5) million for Interest Expense, and $(1) million for Preferred Stock Dividends.

(b) Includes depreciation and amortization of $104 million, consisting of $97 million for Power Delivery, $5 million for Pepco Energy Services and $2 million for Corporate and Other.

(c) Includes restructuring charge of $14 million, consisting of $13 million for Power Delivery and $1 million for Corporate and Other.

(d) Includes $9 million expense related to effects of Pepco divestiture-related claims.

(e) Includes current state tax benefits resulting from the restructuring of certain PHI subsidiaries which have subjected PHI to state income taxes in new jurisdictions.

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	Three Months Ended September 30, 2009
	(millions of dollars)
	Power Delivery			Pepco Energy Services		Other Non- Regulated		Corporate and Other  (a)			PHI Consolidated
Operating Revenue	$	1,428		$	611	$	13	$	(2	)	$	2,050
Operating Expenses (b)		1,235	(c)		584		—		(4	)		1,815
Operating Income		193			27		13		2			235
Interest Income		—			—		1		(1	)		—
Interest Expense		53			6		4		22			85
Other Income		3			—		1		1			5
Preferred Stock Dividends		—			—		1		(1	)		—
Income Tax Expense (Benefit)		49			7		3		(8	)		51
Net Income (Loss) from Continuing Operations		94	(d)		14		7		(11	)		104
Total Assets		10,181			699		1,562		1,427			13,869
Construction Expenditures	$	138		$	2	$	—	$	9		$	149

(a) Total Assets in this column includes Pepco Holdings’ goodwill balance of $1.4 billion, substantially all of which is allocated to the Power Delivery segment for purposes of assessing impairment. Additionally, Corporate and Other includes intercompany amounts of $(2) million for Operating Revenue, $(1) million for Operating Expense, $(17) million for Interest Income, $(16) million for Interest Expense, and $(1) million for Preferred Stock Dividends.

(b) Includes depreciation and amortization of $93 million, consisting of $84 million for Power Delivery, $4 million for Pepco Energy Services, and $5 million for Corporate and Other.

(c) Includes $26 million gain related to effects of Pepco divestiture-related claims.

(d) Includes $11 million after-tax state income tax benefit, net of fees, related to a change in the tax reporting for the disposition of certain assets in prior years.

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	Nine Months Ended September 30, 2010
	(millions of dollars)
	Power Delivery			Pepco Energy Services		Other Non- Regulated			Corporate and Other (a)			PHI Consolidated
Operating Revenue	$	4,011		$	1,480	$	41		$	(10	)	$	5,522
Operating Expenses (b) (c)		3,583	(d)		1,417		3			(17	)		4,986
Operating Income		428			63		38			7			536
Interest Income		1			—		2			(3	)		—
Interest Expense		155			13		9			63			240
Other Income (Expense)		15			1		(2	)		2			16
Loss on Extinguishment of Debt		—			—		—			135			135
Preferred Stock Dividends		—			—		2			(2	)		—
Income Tax Expense (Benefit)		128	(e)		20		8			(104	)(f)		52
Net Income (Loss) from Continuing Operations		161			31		19			(86	)		125
Total Assets		10,569			617		1,524			1,325			14,035
Construction Expenditures	$	523		$	3	$	—		$	22		$	548

(a) Total Assets in this column includes Pepco Holdings’ goodwill balance of $1.4 billion, substantially all of which is allocated to the Power Delivery segment for purposes of assessing impairment. Additionally, Corporate and Other includes intercompany amounts of $(10) million for Operating Revenue, $(7) million for Operating Expense, $(31) million for Interest Income, $(30) million for Interest Expense, and $(2) million for Preferred Stock Dividends.

(b) Includes depreciation and amortization of $286 million, consisting of $264 million for Power Delivery, $14 million for Pepco Energy Services, $1 million for Other Non-Regulated and $7 million for Corporate and Other.

(c) Includes restructuring charge of $14 million, consisting of $13 million for Power Delivery and $1 million for Corporate and Other.

(d) Includes $11 million expense related to effects of Pepco divestiture-related claims.

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

(f) Includes $14 million of state tax benefits resulting from the restructuring of certain PHI subsidiaries, partially offset by a charge of $4 million to write off deferred tax assets related to the Medicare Part D subsidy.

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	Nine Months Ended September 30, 2009
	(millions of dollars)
	Power Delivery			Pepco Energy Services		Other Non- Regulated		Corporate and Other  (a)			PHI Consolidated
Operating Revenue	$	3,895		$	1,828	$	40	$	(10	)	$	5,753
Operating Expenses (b)		3,488	(c)		1,757		2		(14	)		5,233
Operating Income		407			71		38		4			520
Interest Income		2			1		3		(4	)		2
Interest Expense		159			22		11		62			254
Other Income		9			1		2		1			13
Preferred Stock Dividends		—			—		2		(2	)		—
Income Tax Expense (Benefit)		92			19		8		(22	)		97
Net Income (Loss) from Continuing Operations		167	(d)		32		22		(37	)		184
Total Assets		10,181			699		1,562		1,427			13,869
Construction Expenditures	$	419		$	8	$	—	$	19		$	446

(a) Total Assets in this column includes Pepco Holdings’ goodwill balance of $1.4 billion, substantially all of which is allocated to the Power Delivery segment for purposes of assessing impairment. Additionally, Corporate and Other includes intercompany amounts of $(10) million for Operating Revenue, $(8) million for Operating Expense, $(61) million for Interest Income, $(60) million for Interest Expense, and $(2) million for Preferred Stock Dividends.

(b) Includes depreciation and amortization of $265 million, consisting of $242 million for Power Delivery, $13 million for Pepco Energy Services, $1 million for Other Non-Regulated and $9 million for Corporate and Other.

(c) Includes $40 million gain related to effects of Pepco divestiture-related claims.

(d) Includes $11 million after-tax state income tax benefit, net of fees, related to a change in the tax reporting for the disposition of certain assets in prior years.

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(6) GOODWILL

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

PHI’s annual impairment tests as of July 1, 2009 and November 1, 2009 indicated that goodwill was not impaired. As of September 30, 2010, after review of its significant assumptions in the goodwill impairment analysis, PHI concluded that there were no events requiring it to perform an interim goodwill impairment test. Although PHI’s market capitalization was below book value at September 30, 2010, PHI’s market capitalization has improved compared to earlier periods when it performed interim impairment tests. PHI performed its previous annual goodwill impairment tests as of November 1, 2009 and July 1, 2009, and an interim impairment test as of March 31, 2009 when its market capitalization was further below book value than at September 30, 2010, and concluded that its goodwill was not impaired at those earlier dates. PHI will continue to closely monitor for indicators of goodwill impairment, including the sustained period of time that PHI’s stock price has been below its book value.

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

Balance, December 31, 2008	$	1,411
Less: Impairment charge associated with the wind-down of Pepco Energy Services retail energy business		(4	)
Balance, December 31, 2009		1,407
Less: Adjustments		—
Balance, September 30, 2010	$	1,407

(7) LEASING ACTIVITIES

Investment in Finance Leases Held in Trust

As of September 30, 2010 and December 31, 2009, Pepco Holdings had cross-border energy lease investments of $1.4 billion consisting of hydroelectric generation and coal-fired electric generating facilities and natural gas distribution networks located outside of the United States.

The components of the cross-border energy lease investments at September 30, 2010 and at December 31, 2009 are summarized below:

	September 30, 2010			December 31, 2009
	(millions of dollars)
Scheduled lease payments to PHI, net of non-recourse debt	$	2,265		$	2,281
Less: Unearned and deferred income		(854	)		(895	)
Investment in finance leases held in trust		1,411			1,386
Less: Deferred income tax liabilities		(794	)		(748	)
Net investment in finance leases held in trust	$	617		$	638

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

	Three Months  Ended September 30,				Nine Months  Ended September 30,
	2010		2009		2010		2009
	(millions of dollars)
Pre-tax income from PHI’s cross-border energy lease investments (included in “Other Revenue”)	$	15	$	14	$	41	$	41
Income tax expense		4		4		11		11
Net income from PHI’s cross-border energy lease investments	$	11	$	10	$	30	$	30

(8) PENSION AND OTHER POSTRETIREMENT BENEFITS

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

	Pension Benefits						Other Postretirement Benefits
	2010			2009			2010			2009
	(millions of dollars)
Service cost	$	8		$	9		$	1		$	2
Interest cost		28			27			10			10
Expected return on plan assets		(30	)		(25	)		(4	)		(3	)
Amortization of prior service cost		—			—			(1	)		(1	)
Amortization of net actuarial loss		11			14			3			3
Net periodic benefit cost	$	17		$	25		$	9		$	11

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

	Pension Benefits						Other  Postretirement Benefits
	2010			2009			2010			2009
	(millions of dollars)
Service cost	$	26		$	27		$	4		$	5
Interest cost		83			83			29			30
Expected return on plan assets		(88	)		(76	)		(12	)		(10	)
Amortization of prior service cost		—			—			(3	)		(3	)
Amortization of net actuarial loss		32			43			9			12
Plan amendment		1			—			—			—
Termination benefits		—			—			5			—
Net periodic benefit cost	$	54		$	77		$	32		$	34

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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 benefit costs for the nine months ended September 30, 2010 includes a one time charge of $6 million related to the sale of Conectiv Energy which is reflected in net loss from discontinued operations. After intercompany allocations, the three utility subsidiaries are responsible for substantially all of the total PHI net periodic pension and other postretirement benefit costs related to continuing operations.

Pension Contributions

PHI’s funding policy with regard to PHI’s noncontributory retirement plan (the PHI Retirement Plan) is to maintain a funding level that is at least equal to the funding target level under the Pension Protection Act of 2006. Although PHI currently has no minimum funding requirement under the Pension Protection Act guidelines in 2010, PHI Service Company has made discretionary tax-deductible contributions to the PHI Retirement Plan of $35 million on each of July 1, 2010 and August 2, 2010, and $30 million on September 1, 2010. These contributions in the aggregate amount of $100 million brought the PHI Retirement Plan assets to the funding target level for 2010 under the Pension Protection Act.

During 2009, discretionary tax-deductible contributions totaling $300 million were made to the PHI Retirement Plan which brought plan assets to at least the funding target level for 2009 under the Pension Protection Act. Of this amount, $240 million consisted of tax-deductible contributions made by Pepco, ACE and DPL in the amounts of $170 million, $60 million and $10 million, respectively. The remaining $60 million consisted of tax-deductible contributions made by the PHI Service Company.

(9) DEBT

Credit Facilities

PHI’s principal credit source is an unsecured $1.5 billion syndicated credit facility, which can be used by PHI and its utility subsidiaries to borrow funds, obtain letters of credit and support the issuance of commercial paper. This facility is in effect until May 2012 and consists of commitments from 16 lenders, no one of which is responsible for more than 8.5% of the total $1.5 billion commitment. PHI’s credit limit under the facility is $875 million. The credit limit of each of Pepco, DPL and ACE is the lesser of $500 million and the maximum amount of debt the company is permitted to have outstanding by its regulatory authorities, except that the aggregate amount of credit used by Pepco, DPL and ACE at any given time collectively may not exceed $625 million.

PHI also has a $50 million bi-lateral credit agreement with The Bank of Nova Scotia that expires on November 2, 2010, which only can be used for the purpose of obtaining letters of credit. In addition, PHI had a $400 million unsecured credit facility that terminated on October 15, 2010. As of September 30, 2010, no letters of credit were outstanding under these agreements.

In April 2010, PHI entered into a $450 million unsecured bridge facility with Morgan Stanley Bank, N.A. and Credit Suisse AG. PHI used the proceeds of the loans drawn under the facility to repay (i) $200 million in aggregate principal amount of its 4.0% Senior Notes due May 15, 2010 and (ii) $250 million in aggregate principal amount of its Floating Rate Notes due June 1, 2010. On July 1, 2010, PHI repaid all amounts outstanding under this facility with a portion of the proceeds from the sale of the Conectiv Energy wholesale power generation business, thereby terminating the facility.

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

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At September 30, 2010 and December 31, 2009, the amount of cash plus borrowing capacity under the credit facilities available to meet the future liquidity needs of PHI and its utility subsidiaries on a consolidated basis each totaled $1.4 billion. PHI’s utility subsidiaries had combined cash and borrowing capacity under the $1.5 billion credit facility of $494 million and $582 million at September 30, 2010 and December 31, 2009, respectively. These amounts include (i) the $400 million unsecured credit facility available only to PHI, which expired on October 15, 2010, and was replaced by two PHI bi-lateral 364-day unsecured credit agreements in the aggregate amount of $200 million and (ii) the $50 million PHI bi-lateral credit agreement, which will expire in November 2010, each of which is more fully described below.

Credit Facilities Activity Subsequent to September 30, 2010

On October 15, 2010, a $400 million unsecured credit facility maintained by PHI expired. To replace this facility, PHI, on October 27, 2010, entered into two bi-lateral 364 day unsecured credit agreements totaling $200 million. Under each of the credit agreements, PHI has access to revolving and floating rate loans over the terms of the agreements. Neither agreement provides for the issuance of letters of credit. The interest rate payable on funds borrowed is at PHI’s election, based on either (a) the prevailing Eurodollar rate or (b) the highest of (i) the prevailing prime rate, (ii) the federal funds effective rate plus 0.5% or (iii) the one-month Eurodollar rate plus 1.0%, plus a margin 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, and results of operations or financial condition is not a condition to the availability of credit under the agreements. Neither agreement includes any rating triggers.

PHI does not plan to renew its $50 million bi-lateral credit agreement with The Bank of Nova Scotia that expires on November 2, 2010.

The two expiring credit facilities were established to provide additional liquidity and collateral support for Pepco Energy Services’ retail energy supply business and for Conectiv Energy. Based on the progress toward winding down the retail energy supply business and disposing of the Conectiv Energy segment, the level of liquidity and collateral needed to support these businesses has decreased. As a result, PHI has been able to reduce the total amount of its credit facility needs by $250 million.

Other Financing Activities

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

In July 2010, ACE Funding made principal payments of $5.5 million on Series 2002-1 Bonds, Class A-2, and $2.1 million on Series 2003-1 Bonds, Class A-2.

On July 1, 2010, DPL purchased $31 million of unsecured tax-exempt bonds issued for the benefit of DPL by The Delaware Economic Development Authority that in accordance with the terms of the bonds were subject to mandatory tender. DPL intends to remarket these bonds during the fourth quarter of 2010.

On August 30, 2010, ACE redeemed $1 million of 7.25% secured medium-term notes at maturity.

Debt Tender Offers

On July 2, 2010, PHI purchased, pursuant to a cash tender offer, $640 million in principal amount of its 6.45% Senior Notes due 2012 (6.45% Notes) for an aggregate purchase price of $713 million, plus accrued and unpaid interest. The tender offer for the 6.45% Notes also constituted a solicitation of the consent of the holders of the 6.45% Notes to an amendment of the terms of the 6.45% Notes to reduce the notice period for the redemption from not less than 30 days and not more than 60 days to three business days. This amendment, which required the consent of the holders of a majority of the outstanding 6.45% Notes, was approved upon the repurchase of the 6.45% Notes pursuant to the tender offer. On July 2, 2010, PHI terminated the tender offer and issued a

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notice of redemption for the balance of the 6.45% Notes. On July 8, 2010, PHI redeemed the remaining $110 million of outstanding 6.45% Notes at an aggregate redemption price of $122 million, plus accrued and unpaid interest.

On July 20, 2010, PHI purchased, pursuant to a cash tender offer, (i) $129 million of its 6.125% Senior Notes due 2017 (6.125% Notes), at an aggregate purchase price of $145 million, plus accrued and unpaid interest, and (ii) $65 million of 7.45% Senior Notes due 2032 (7.45% Notes), at an aggregate purchase price of $78 million, plus accrued and unpaid interest.

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

As a result of the aforementioned purchases of debt, PHI recorded a pre-tax loss on extinguishment of debt of $120 million in the third quarter of 2010.

Treasury Rate Locks

In June 2002, PHI entered into several treasury rate lock transactions to hedge changes in interest rates related to the anticipated issuance in August 2002 of several series of senior notes, including the 6.45% Notes and the 7.45% Notes. Upon issuance of the fixed rate debt in August 2002, the treasury rate locks were terminated at a loss that has been deferred in Accumulated Other Comprehensive Loss and is being recognized in income over the life of the debt issued as interest payments on the debt are made. In connection with the purchases of the 6.45% Notes and the 7.45% Notes, PHI accelerated the recognition of $15 million of pre-tax losses attributable to the 6.45% Notes and 7.45% Notes by reclassifying these losses from Accumulated Other Comprehensive Loss to the income statement in the third quarter of 2010. These losses have also been reported as a pre-tax loss on extinguishment of debt.

Financing Activities Subsequent to September 30, 2010

On October 1, 2010, PHI issued $250 million of 2.70% Senior Notes due October 1, 2015 (2.70% Notes).

On October 13, 2010, PHI:

• purchased, pursuant to a cash tender offer, an additional $40 million in principal amount of the 6.125% Notes for an aggregate purchase price of $48 million, plus accrued and unpaid interest. PHI used proceeds from the issuance of the 2.70% Notes to pay the purchase price of the 6.125% Notes; and

• issued notices of redemption of (i) $200 million in principal amount of its 6.0% Senior Notes due 2019 (6.0% Notes) and (ii) $10 million in principal amount of its 5.9% Senior Notes due 2016 (5.9% Notes). PHI will use proceeds from the issuance of the 2.70% Notes to pay the redemption price. The redemption date is November 15, 2010. The redemption price will be determined three business days prior to the redemption date.

PHI expects to record after-tax losses on extinguishment of debt of approximately $33 million in the fourth quarter of 2010 associated with the October 13, 2010 tender offer for the 6.125% Notes and the redemptions of the 6.0% Notes and the 5.9% Notes.

Collateral Requirements

At September 30, 2010 and December 31, 2009, the aggregate amount of cash, plus borrowing capacity under the credit facilities available to meet the combined future liquidity needs of Pepco Energy Services and Conectiv Energy totaled $912 million and $820 million, respectively. On October 15, 2010, a $400 million unsecured credit facility maintained by PHI expired and was replaced by two bi-lateral 364-day unsecured credit agreements in the aggregate amount of $200 million. A PHI $50 million bi-lateral credit agreement will expire on November 2, 2010.

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Collateral Requirements of Pepco Energy Services

In conducting its retail energy supply business, Pepco Energy Services, during periods of declining energy prices, has been exposed to the asymmetrical risk of having to post collateral under its wholesale purchase contracts without receiving a corresponding amount of collateral from its retail customers. To partially address these asymmetrical collateral obligations, Pepco Energy Services, in the first quarter of 2009, entered into a credit intermediation arrangement with Morgan Stanley Capital Group, Inc. (MSCG). Under this arrangement, MSCG, in consideration for the payment to MSCG of certain fees: (i) has assumed by novation certain electricity purchase obligations of Pepco Energy Services in years 2009 through 2011 under several wholesale purchase contracts, and (ii) has agreed to supply electricity to Pepco Energy Services on the same terms as the novated transactions, but without imposing on Pepco Energy Services any obligation to post collateral based on changes in electricity prices. As of September 30, 2010, approximately 3% of Pepco Energy Services’ wholesale electricity purchase obligations (measured in megawatt hours) was covered by this credit intermediation arrangement with MSCG. The upfront fees incurred by Pepco Energy Services in the amount of $25 million are being amortized into expense in declining amounts over the life of the arrangement based on the fair value of the underlying contracts at the time of novation. For the three months ended September 30, 2010 and 2009, approximately $1 million and $4 million, respectively, of the fees have been amortized and reflected in interest expense. For the nine months ended September 30, 2010 and 2009, approximately $6 million and $12 million, respectively, of the fees have been amortized and reflected in interest expense.

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

Depending on the contract terms, the collateral required to be posted by Pepco Energy Services can be of varying forms, including cash and letters of credit. As of September 30, 2010, Pepco Energy Services had posted net cash collateral of $150 million and letters of credit of $140 million. At December 31, 2009, Pepco Energy Services had posted net cash collateral of $123 million and letters of credit of $157 million.

Remaining Collateral Requirements of Conectiv Energy

Depending on the contract terms, the collateral required to be posted by Conectiv Energy was of varying forms, including cash and letters of credit. As of September 30, 2010, Conectiv Energy had posted net cash collateral of $172 million and letters of credit of $2 million. At December 31, 2009, Conectiv Energy had posted net cash collateral of $240 million and letters of credit of $22 million.

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(10) INCOME TAXES

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

	Three Months  Ended September 30,						Nine Months  Ended September 30,
	2010			2009			2010			2009
Federal statutory rate		35.0	%		35.0	%		35.0	%		35.0	%
Increases (decreases) resulting from:
State income taxes, net of federal effect		(37.3	)		5.4			2.0			5.7
State tax benefits related to prior year asset dispositions		—			(8.5	)		—			(4.7	)
Change in estimates and interest related to uncertain and effectively settled tax positions		(0.7	)		1.5			5.5			0.2
Depreciation		9.3			1.4			2.4			1.8
Tax credits		(6.0	)		(0.7	)		(1.6	)		(1.1	)
Cross-border energy lease investments		(10.0	)		(0.9	)		(2.3	)		(1.4	)
Release of deferred tax asset valuation allowance		—			—			(4.4	)		—
Change in state deferred tax balances as a result of corporate restructuring		14.0			—			(3.6	)		—
PHI dividends invested in ESOP Plan		(3.3	)		(0.3	)		(0.9	)		(0.5	)
Asset removal costs		(4.7	)		(0.7	)		(1.0	)		(0.8	)
Adjustment to prior year taxes		(3.3	)		2.1			(0.4	)		0.8
Deferred tax basis adjustments		(28.7	)		—			(0.2	)		—
Other, net		(4.3	)		(1.4	)		(1.1	)		(0.5	)
Consolidated Effective Income Tax Rate		(40.0	)%		32.9	%		29.4	%		34.5	%

PHI’s consolidated effective tax rates from continuing operations for the three months ended September 30, 2010 and 2009 were (40.0%) and 32.9%, respectively. The reduction in the effective tax rate is primarily due to the recording of current state tax benefits resulting from the restructuring of certain PHI subsidiaries which has subjected PHI to state income taxes in new jurisdictions. On April 1, 2010, as part of an ongoing effort to simplify PHI’s organizational structure, certain of PHI’s subsidiaries were converted from corporations to single member limited liability companies. In addition to increased organizational flexibility and reduced administrative costs, converting these entities to limited liability companies allows PHI to include income or losses in the former corporations in a single state income tax return, thus increasing the utilization of state income tax attributes. As a result of the increase in the current state tax benefits discussed above, PHI recorded a $2 million reduction to the $8 million benefit recorded in the second quarter by establishing a valuation allowance on certain state net operating losses.

The consolidated effective tax rate from continuing operations for the three months ended September 30, 2010 is further reduced as a result of a $2 million adjustment to eliminate deferred tax liabilities associated with a goodwill impairment charge recorded in 2005, and the recording of a $2 million benefit related to deferred tax attributes. The decrease in the effective rate was partially offset by a $13 million (after-tax) benefit recorded in 2009 related to a change in tax reporting for certain asset dispositions occurring in prior years.

PHI’s consolidated effective tax rates from continuing operations for the nine months ended September 30, 2010 and 2009 were 29.4% and 34.5%, respectively. The reduction in the effective tax rate is primarily due to the restructuring of PHI subsidiaries discussed above. As a consequence of the restructuring, PHI recorded current state tax benefits that result from subjecting PHI to state income taxes in new jurisdictions; and the release of a net $6 million valuation allowance on deferred tax assets related to state net operating losses recognized in 2010.

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The reduction in the consolidated effective tax rate in the nine months ended September 30, 2010 was partially offset by changes in estimates and interest related to uncertain and effectively settled tax positions. These were primarily related to a $2 million reversal of accrued interest income on state income tax positions that PHI no longer believes is more likely than not to be realized, and the reversal of $6 million of erroneously accrued interest income on uncertain and effectively settled state income tax positions. The decrease in the effective rate was further offset by a $13 million (after-tax) benefit recorded in 2009 related to a change in tax reporting for certain asset dispositions occurring in prior years.

PHI’s consolidated effective tax rate from continuing operations for the nine months ended September 30, 2010 also reflects a deferred tax basis adjustment related to change in taxation of the Medicare Part D subsidy enacted by the Patient Protection and Affordable Care Act. Under this legislation, PHI receives a tax-free federal subsidy for the costs it incurs for certain prescription drugs covered under its post-employment benefit plan. Prior to the legislation, the costs incurred for those prescription drugs were tax deductible. The legislation includes a provision, effective beginning in 2013, which eliminates the tax deductibility of the prescription drug costs. As a result, in the first quarter of 2010, PHI wrote off $5 million of deferred tax assets. Of this amount, $3 million was established as a regulatory asset, which PHI anticipates will be recoverable from its utility customers in the future. This change increased PHI’s 2010 tax expense by $4 million, which was partially offset through a reduction in Operating Expenses, resulting in a $2 million decrease to net income.

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

(11) EARNINGS PER SHARE

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

	Three Months Ended  September 30,
	2010			2009
	(millions of dollars, except per share data)
Income (Numerator):
Net income from continuing operations	$	21		$	104
Net (loss) income from discontinued operations		(4	)		20
Net income	$	17		$	124
Shares (Denominator) (in millions):
Weighted average shares outstanding for basic computation:
Average shares outstanding		224			221
Adjustment to shares outstanding		—			—
Weighted Average Shares Outstanding for Computation of Basic Earnings Per Share of Common Stock		224			221
Net effect of potentially dilutive shares (a)		—			—
Weighted Average Shares Outstanding for Computation of Diluted Earnings Per Share of Common Stock		224			221
Basic and diluted earnings per share of common stock from continuing operations	$	.09		$	.47
Basic and diluted (loss) earnings per share of common stock from discontinued operations		(.01	)		.09
Basic and diluted earnings per share	$	.08		$	.56

(a) The number of options to purchase shares of common stock that were excluded from the calculation of diluted EPS because they were anti-dilutive were 280,266 and 340,066 for the three months ended September 30, 2010 and 2009, respectively.

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	For the Nine  Months Ended September 30,
	2010			2009
	(millions of dollars, except per share data)
Income (Numerator):
Net income from continuing operations	$	125		$	184
Net (loss) income from discontinued operations		(126	)		10
Net (loss) income	$	(1	)	$	194
Shares (Denominator) (in millions):
Weighted average shares outstanding for basic computation:
Average shares outstanding		223			220
Adjustment to shares outstanding		—			—
Weighted Average Shares Outstanding for Computation of Basic Earnings Per Share of Common Stock		223			220
Net effect of potentially dilutive shares (a)		—			—
Weighted Average Shares Outstanding for Computation of Diluted Earnings Per Share of Common Stock		223			220
Basic and diluted earnings per share of common stock from continuing operations	$	.56		$	.84
Basic and diluted (loss) earnings per share of common stock from discontinued operations		(.56	)		.04
Basic and diluted (loss) earnings per share	$	—		$	.88

(a) The number of options to purchase shares of common stock that were excluded from the calculation of diluted EPS as they are considered to be anti-dilutive were 280,266 and 340,066 for the nine months ended September 30, 2010 and 2009, respectively.

(12) DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

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

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

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

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

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PHI and its subsidiaries also use derivative instruments from time to time to mitigate the effects of fluctuating interest rates on debt incurred in connection with the operation of their businesses. In June 2002, PHI entered into several treasury rate lock transactions in anticipation of the issuance of several series of fixed-rate debt commencing in August 2002. Upon issuance of the fixed rate debt in August 2002, the treasury rate locks were terminated at a loss. The loss has been deferred in accumulated other comprehensive loss and is being recognized in income over the life of the debt issued as interest payments are made. In connection with the July 2010 debt tender offers described in Note (9), “Debt,” $15 million of these pre-tax losses ($9 million after-tax) was reclassified to income during the third quarter of 2010.

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

	As of September 30, 2010
Balance Sheet Caption	Derivatives Designated as Hedging Instruments			Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting			Net Derivative Instruments
	(millions of dollars)
Derivative Assets (current assets)	$	62		$	54		$	116		$	(78	)	$	38
Derivative Assets (non-current assets)		24			12			36			(29	)		7
Total Derivative Assets		86			66			152			(107	)		45
Derivative Liabilities (current liabilities)		(178	)		(73	)		(251	)		174			(77	)
Derivative Liabilities (non-current liabilities)		(92	)		(25	)		(117	)		82			(35	)
Total Derivative Liabilities		(270	)		(98	)		(368	)		256			(112	)
Net Derivative (Liability) Asset	$	(184	)	$	(32	)	$	(216	)	$	149		$	(67	)
	As of December 31, 2009
Balance Sheet Caption	Derivatives Designated as Hedging Instruments			Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting			Net Derivative Instruments
	(millions of dollars)
Derivative Assets (current assets)	$	100		$	54		$	154		$	(132	)	$	22
Derivative Assets (non-current assets)		44			21			65			(49	)		16
Total Derivative Assets		144			75			219			(181	)		38
Derivative Liabilities (current liabilities)		(234	)		(70	)		(304	)		237			(67	)
Derivative Liabilities (non-current liabilities)		(88	)		(35	)		(123	)		69			(54	)
Total Derivative Liabilities		(322	)		(105	)		(427	)		306			(121	)
Net Derivative (Liability) Asset	$	(178	)	$	(30	)	$	(208	)	$	125		$	(83	)

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

	September 30, 2010		December 31, 2009
	(millions of dollars)
Cash collateral pledged to counterparties with the right to reclaim (a)	$	149	$	125

(a) Includes cash deposits on commodity brokerage accounts

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

Derivatives Designated as Hedging Instruments

Cash Flow Hedges

Pepco Energy Services

For energy commodity contracts that are designated and qualify as cash flow hedges, the effective portion of the gain or loss on the derivative is reported as a component of accumulated other comprehensive loss (AOCL) and is reclassified into income in the same period or periods during which the hedged transactions affect income. Gains and losses on the derivative, representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness, are recognized in income. This information for the activity during the three and nine months ended September 30, 2010 and 2009 is provided in the tables below:

	Three Months  Ended September 30,						Nine Months  Ended September 30,
	2010			2009			2010			2009
	(millions of dollars)
Amount of net pre-tax loss arising during the period included in other comprehensive loss	$	(38	)	$	(3	)	$	(116	)	$	(109	)
Amount of net pre-tax loss gain reclassified into income:
Effective portion:
Fuel and Purchased Energy		(23	)		(36	)		(108	)		(125	)
Ineffective portion: (a)
Revenue		—			—			(2	)		—
Total net pre-tax loss reclassified into income		(23	)		(36	)		(110	)		(125	)
Net pre-tax (losses) gain on commodity derivatives included in other comprehensive loss	$	(15	)	$	33		$	(6	)	$	16

(a) For the three and nine months ended September 30, 2010 and 2009, no amounts were reclassified from AOCL to income because the forecasted hedged transactions were deemed probable not to occur.

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

	Quantities
Commodity	September 30, 2010		December 31, 2009
Forecasted Purchases Hedges
Natural gas (One Million British Thermal Units (MMBtu))		41,240,000		54,477,500
Electricity (Megawatt hours (MWh))		4,971,008		9,708,919
Electricity Capacity (MW-Days)		55,890		—
Forecasted Sales Hedges
Electricity (MWh)		3,384,800		7,322,535

Power Delivery

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

	Three Months  Ended September 30,						Nine Months  Ended September 30,
	2010			2009			2010			2009
	(millions of dollars)
Net Gain Deferred as a Regulatory Asset or Liability	$	1		$	8		$	1		$	19
Net Loss Reclassified from Regulatory Asset or Liability to Fuel and Purchased Energy Expense		(4	)		(7	)		(9	)		(33	)

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

	Quantities
Commodity	September 30, 2010		December 31, 2009
Forecasted Purchases Hedges
Natural Gas (MMBtu)		2,670,000		5,695,000

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Cash Flow Hedges Included in Accumulated Other Comprehensive Loss

The tables below provide details regarding effective cash flow hedges included in PHI’s consolidated balance sheet as of September 30, 2010 and 2009. Cash flow hedges are marked-to-market on the balance sheet with corresponding adjustments to AOCL. The data in the tables indicate the cumulative net loss after-tax related to effective cash flow hedges by contract type included in AOCL, the portion of AOCL expected to be reclassified to income during the next 12 months, and the maximum hedge or deferral term:

	As of September 30, 2010
Contracts	Accumulated Other Comprehensive Loss After-tax (a)		Portion Expected to be Reclassified to Income during the Next 12 Months		Maximum Term
	(millions of dollars)
Energy Commodity (b)	$	102	$	63		44 months
Interest Rate		11		1		263 months
Total	$	113	$	64

(a) Accumulated other comprehensive loss on PHI’s consolidated balance sheet as of September 30, 2010, includes a $15 million balance related to minimum pension liability and a $20 million balance related to Conectiv Energy. These balances are not included in this table as the minimum pension liability is not a cash flow hedge and Conectiv Energy is reported as a discontinued operation.

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

	As of September 30, 2009
Contracts	Accumulated Other Comprehensive Loss After-tax (a)		Portion Expected to be Reclassified to Income during the Next 12 Months		Maximum Term
	(millions of dollars)
Energy Commodity (b)	$	111	$	8		56 months
Interest Rate		23		3		275 months
Total	$	134	$	11

(a) Accumulated other comprehensive loss on PHI’s consolidated balance sheet as of September 30, 2009, includes a $15 million balance related to minimum pension liability and a $109 million balance related to Conectiv Energy. These balances are not included in this table as the minimum pension liability is not a cash flow hedge and Conectiv Energy is reported as a discontinued operation.

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

Other Derivative Activity

Pepco Energy Services

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

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

	Three Months  Ended September 30, 2010						Three Months Ended September 30, 2009
	Revenue		Fuel and Purchased Energy Expense		Total		Revenue			Fuel and Purchased Energy Expense		Total
	(millions of dollars)
Realized mark-to-market gains (losses)	$	1	$	—	$	1	$	—		$	—	$	—
Unrealized mark-to-market gains (losses)		—		—		—		(4	)		—		(4	)
Total net mark-to-market gains (losses)	$	1	$	—	$	1	$	(4	)	$	—	$	(4	)

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	Nine Months Ended September 30, 2010						Nine Months Ended September 30, 2009
	Revenue		Fuel and Purchased Energy Expense		Total		Revenue			Fuel and Purchased Energy Expense		Total
	(millions of dollars)
Realized mark-to-market gains (losses)	$	2	$	—	$	2	$	(2	)	$	—	$	(2	)
Unrealized mark-to-market gains (losses)		—		—		—		(4	)		—		(4	)
Total net mark-to-market gains (losses)	$	2	$	—	$	2	$	(6	)	$	—	$	(6	)

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

	September 30, 2010				December 31, 2009
Commodity	Quantity		Net Position		Quantity		Net Position
Financial transmission rights (MWh)		555,649		Long		532,556		Long
Electric Capacity (MW – Days)		3,645		Long		—		—

Power Delivery

DPL holds certain derivatives that do not qualify as hedges. These derivatives are recorded at fair value on the balance sheet with the gain or loss recorded in income. In accordance with FASB guidance on regulated operations, offsetting regulatory assets or regulatory liabilities are recorded on the balance sheet and the recognition of the gain or recovery of the loss is deferred. For the three and nine months ended September 30, 2010 and 2009, the amount of the derivative loss recognized in the consolidated statements of income is provided in the table below by line item:

	Three Months  Ended September 30,						Nine Months  Ended September 30,
	2010			2009			2010			2009
	(millions of dollars)
Gain (Loss) Deferred as a Regulatory Asset or Liability	$	(4	)	$	2		$	(3	)	$	(8	)
Loss Reclassified from Regulatory Asset or Liability to Fuel and Purchased Energy Expense		(5	)		(1	)		(18	)		(6	)

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

	September 30, 2010				December 31, 2009
Commodity	Quantity		Net Position		Quantity		Net Position
Natural Gas (MMBtu)		9,484,375		Long		10,442,546		Long

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Contingent Credit Risk Features

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

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 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 these derivative liabilities, excluding the impact of offsetting transactions or collateral under master netting agreements, with credit risk-related contingent features on September 30, 2010 and December 31, 2009, was $232 million and $303 million, respectively. As of those dates, PHI had posted cash collateral of $5 and $6 million, respectively, in the normal course of business against the gross derivative liability resulting in a net liability of $227 million and $297 million, respectively, before giving effect to offsetting transactions that are encompassed within master netting agreements that would reduce this amount. PHI’s net settlement amount in the event of a downgrade of PHI and DPL below “investment grade” as of September 30, 2010 and December 31, 2009, would have been approximately $213 million and $183 million, respectively, after taking into consideration the master netting agreements. The offsetting transactions or collateral that would reduce PHI’s obligation to the net settlement amount include derivatives and normal purchase and normal sale contracts in a gain position as well as letters of credit already posted as collateral.

PHI’s primary sources for posting cash collateral or letters of credit are its credit facilities. At September 30, 2010 and December 31, 2009, the aggregate amount of cash plus borrowing capacity under the credit facilities available to meet the future liquidity needs of PHI and its subsidiaries totaled $1.4 billion, of which $912 million and $820 million, respectively, was available for the business of Pepco Energy Services. On October 15, 2010, a $400 million unsecured credit facility maintained by PHI expired and was replaced by two bi-lateral 364-day unsecured credit agreements in the aggregate amount of $200 million. A PHI $50 million bi-lateral credit agreement will expire on November 2, 2010.

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(13) FAIR VALUE DISCLOSURES

Fair Value of Assets and Liabilities Excluding Debt

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

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

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

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

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

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

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

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

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The following tables set forth, by level within the fair value hierarchy, PHI’s financial assets and liabilities (excluding assets and liabilities held for sale) that were accounted for at fair value on a recurring basis as of September 30, 2010 and December 31, 2009. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. PHI’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Fair Value Measurements at September 30, 2010
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Derivative instruments (a)
Electricity (b)	$	31	$	—	$	31	$	—
Cash equivalents
Treasury Fund		18		18		—		—
Executive deferred compensation plan assets
Money Market Funds		15		15		—		—
Life Insurance Contracts		59		—		40		19
	$	123	$	33	$	71	$	19
LIABILITIES
Derivative instruments (a)
Electricity (b)	$	111	$	—	$	111	$	—
Natural Gas (c)		136		104		—		32
Executive deferred compensation plan liabilities
Life Insurance Contracts		30		—		30		—
	$	277	$	104	$	141	$	32

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

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

(c) Represents wholesale gas futures and swaps that are used mainly as part of Pepco Energy Service’s retail energy supply business and natural gas options purchased by DPL as part of a natural gas hedging program approved by the DPSC.

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	Fair Value Measurements at December 31, 2009
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Derivative instruments (a)
Electricity (b)	$	21	$	—	$	21	$	—
Cash equivalents
Treasury Fund		36		36		—		—
Other (e.g. Commercial Paper)		1		1		—		—
Executive deferred compensation plan assets
Money Market Funds		13		13		—		—
Life Insurance Contracts		62		—		43		19
	$	133	$	50	$	64	$	19
LIABILITIES
Derivative instruments (a)
Electricity (b)	$	116	$	—	$	116	$	—
Natural Gas (c)		113		84		—		29
Executive deferred compensation plan liabilities
Life Insurance Contracts		32		—		32		—
	$	261	$	84	$	148	$	29

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

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

(b) Represents wholesale gas futures and swaps that are used mainly as part of Pepco Energy Service’s retail energy supply business and 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 nine months ended September 30, 2010 and 2009 are shown below:

	Nine Months Ended September 30, 2010
	Natural Gas			Life Insurance Contracts
	(millions of dollars)
Beginning balance as of January 1, 2010	$	(29	)	$	19
Total gains or (losses) (realized and unrealized)
Included in income		—			3
Included in accumulated other comprehensive loss		—			—
Included in regulatory liabilities		(18	)		—
Purchases and issuances		—			(3	)
Settlements		15			—
Transfers in (out) of Level 3		—			—
Ending balance as of September 30, 2010	$	(32	)	$	19

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	Nine Months Ended September 30, 2009
	Natural Gas			Life Insurance Contracts
	(millions of dollars)
Beginning balance as of January 1, 2009	$	(24	)	$	18
Total gains or (losses) (realized and unrealized)
Included in income		—			3
Included in accumulated other comprehensive loss		—			—
Included in regulatory liabilities		(13	)		—
Purchases and issuances		—			(3	)
Settlements		9			—
Transfers in (out) of Level 3		—			—
Ending balance as of September 30, 2009	$	(28	)	$	18

Gains or (losses) (realized and unrealized) included in income for the periods below are reported in Other Operation and Maintenance Expense as follows:

	Nine Months Ended September 30, 2010		Nine Months Ended September 30, 2009
	(millions of dollars)
Total gains included in income for the period	$	3	$	3
Change in unrealized gains relating to assets still held at reporting date	$	3	$	3

Fair Value of Debt Instruments

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

	September 30, 2010				December 31, 2009
	(millions of dollars)
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	3,633	$	4,242	$	4,969	$	5,350
Transition Bonds issued by ACE Funding		378		432		402		427
Long-Term Project Funding		20		20		20		20
Redeemable Serial Preferred Stock		6		5		6		4

The methods and assumptions described below were used to estimate, as of September 30, 2010 and December 31, 2009, the fair value of each class of non-derivative financial instruments shown above for which it is practicable to estimate a value.

The fair value of long-term debt issued by PHI and its utility subsidiaries was based on actual trade prices as of September 30, 2010 and December 31, 2009, or bid prices obtained from brokers if actual trade prices were not available. The fair values of Transition Bonds issued by ACE Funding, including amounts due within one year, were derived based on bid prices obtained from brokers if actual trade prices were not available or were based on discounted cash flows using current rates for similar issues with similar credit ratings, terms, and remaining maturities for issues with no market price available.

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

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

(14) COMMITMENTS AND CONTINGENCIES

Regulatory and Other Matters

Proceeds from Settlement of Mirant Bankruptcy Claims

In 2007, Pepco received proceeds from the settlement of its Mirant Corporation (Mirant) bankruptcy claims relating to a power purchase agreement between Pepco and Panda-Brandywine L.P. (Panda PPA). In September 2008, Pepco transferred the Panda PPA to an unaffiliated third party, along with a payment to the third party of a portion of the settlement proceeds. In March 2009, the District of Columbia Public Service Commission (DCPSC) approved an allocation between Pepco and its District of Columbia customers of the District of Columbia portion of the Mirant bankruptcy settlement proceeds remaining after the transfer of the Panda PPA. As a result, Pepco recorded a pre-tax gain of $14 million in the first quarter of 2009 reflecting the District of Columbia proceeds retained by Pepco. In July 2009, the MPSC approved an allocation between Pepco and its Maryland customers of the Maryland portion of the Mirant bankruptcy settlement proceeds remaining after the transfer of the Panda PPA. As a result, Pepco recorded a pre-tax gain of $26 million in the third quarter of 2009 reflecting the Maryland proceeds retained by Pepco.

Rate Proceedings

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

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

• A modified fixed variable rate design (MFVRD) has been approved in concept for DPL electric service in Delaware and a settlement among the parties to the ongoing base rate proceeding (as described below) has been submitted to the DPSC, which provides for the implementation of the MFVRD after the conclusion of the proceeding.

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

• A BSA remains pending for ACE in New Jersey.

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

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provides for a fixed customer charge (i.e., not tied to the customer’s volumetric consumption) to recover the utility’s fixed costs, plus a reasonable rate of return. Although different from the BSA, PHI views the MFVRD as an appropriate distribution revenue decoupling mechanism.

Delaware

In August 2009, DPL submitted to the DPSC its 2009 Gas Cost Rate (GCR) filing, which permits DPL to recover gas procurement costs through customer rates. The requested 10.2% decrease in the level of GCR, became effective on a temporary basis on November 1, 2009, subject to refund and pending final DPSC approval. On August 17, 2010, the DPSC approved the rates as filed.

On August 31, 2010, DPL submitted to the DPSC its 2010 GCR filing, which proposed a two-year amortization of under-recovered gas costs in the 2010 filing. In October 2010, the DPSC issued an order placing those 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 essentially flat (an increase of 0.1% in the level of GCR). If the DPSC does not accept DPL’s proposal, the full GCR would result in an increase of 6.9% in the level of GCR.

In September 2009, DPL submitted an application with the DPSC to increase its electric distribution base rates. The filing, as revised in March 2010, sought approval of an annual rate increase of approximately $26.2 million, assuming approval of the implementation of the MFVRD, based on a requested return on equity (ROE) of 10.75%. As permitted by Delaware law, DPL placed an increase of approximately $2.5 million annually into effect on a temporary basis in November 2009, subject to refund and pending final DPSC approval of the entirety of the requested increase. As permitted by Delaware law, DPL placed approximately $23.7 million of the remaining requested increase into effect on April 19, 2010, subject to refund and pending final DPSC approval. On April 16, 2010, all of the parties to the base rate proceeding, including DPL, the DPSC staff, the Division of the Public Advocate, the Delaware Department of Natural Resources and Environmental Control, and the Delaware Energy Users Group, which represents large industrial consumers of electricity, entered into a settlement agreement regarding implementation of the MFVRD. The settlement agreement (as modified non-materially on August 27, 2010) provides for implementation of the MFVRD after the conclusion of the current base rate proceeding. Hearings on the unresolved issues in the case were concluded in late May 2010. In June 2010, DPL lowered the requested annual rate increase to approximately $24.2 million. On October 1, 2010, the Hearing Examiner issued a report to the DPSC, recommending an increase of approximately $6.3 million, based on an ROE of 8.5% with the MFVRD (or approximately $9.7 million, based on an ROE of 9.5%, without the MFVRD), and recommending approval of the settlement agreement providing for implementation of the MFVRD. On October 25, 2010, DPL filed a number of objections to the Hearing Examiner’s report. The DPSC is expected to consider the case at its meeting on November 10, 2010, during which DPL will have an additional opportunity to challenge each of the recommendations in the report to which it objects.

On July 2, 2010, DPL submitted an application with the DPSC to increase its natural gas distribution base rates. As subsequently amended on September 10, 2010 (to replace test year data for the twelve months ended June 2010 with the actual data) and on October 11, 2010 (based on an update to DPL’s Gas advanced metering infrastructure implementation schedule), the filing seeks approval of an annual rate increase of approximately $10.2 million, assuming the implementation of the MFVRD, based on a requested ROE of 11.00%. DPL placed an annual increase of approximately $2.5 million into effect on a temporary basis on August 31, 2010, subject to refund and pending final DPSC approval of the entirety of the requested increase. A procedural schedule has been set which provides for a hearing in January 2011 and a DPSC decision in April 2011. Previously, in June 2009, DPL filed an application requesting approval for the implementation of the MFVRD for gas distribution rates. The parties to the MFVRD proceeding have been working toward a settlement agreement that would be submitted to the DPSC. DPL anticipates that the MFVRD proceeding will be merged with the natural gas base rate proceeding discussed above.

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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. On August 6, 2010, the MPSC issued an order approving a rate increase of approximately $7.8 million, based on an ROE of 9.83%. On September 2, 2010, Pepco filed with the MPSC a motion for reconsideration of the following issues: (1) denial of inclusion in rate base of certain reliability plant investments, which occurred subsequent to the test period but before the rate effective period; (2) denial of Pepco’s request to increase depreciation rates to reflect a corrected formula relating to the cost of removal expenses; and (3) imposition of imputed cost savings to partially offset the costs of Pepco’s enhanced vegetation management program. The Office of People’s Counsel and MPSC Staff filed responses to Pepco’s motion on October 4, 2010. Maryland law and regulation do not mandate a response time from the MPSC regarding Pepco’s motion and, therefore, it is not known when the MPSC will issue a ruling on the motion.

District of Columbia Divestiture Case

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

On May 18, 2010, the DCPSC issued an order addressing all of the remaining issues related to the sharing of the proceeds of Pepco’s divestiture of its generating assets. In the order, the DCPSC ruled that Pepco is not required to share EDIT and ADITC with customers. However, the order also disallowed certain items that Pepco had included in the costs deducted from the proceeds of the sale of the generation assets. The disallowance of these costs, together with interest on the allowed amount, increases the aggregate amount Pepco is required to distribute to customers, pursuant to the sharing formula, by approximately $11 million. On June 17, 2010, Pepco filed an application for reconsideration of the DCPSC’s order, contesting (i) approximately $5 million of the approximate total of $6 million in disallowances and (ii) approximately $4 million of the approximately $5 million in interest to be credited to customers (reflecting a difference in the period of time over which interest was calculated as well as the balance to which interest would be applied). On July 16, 2010, the DCPSC denied Pepco’s application for reconsideration. On September 7, 2010, Pepco filed an appeal of the DCPSC’s decision with the District of Columbia Court of Appeals. PHI recognized expenses of $9 million and $11 million, respectively, for the three and nine months ended September 30, 2010 corresponding to the disallowed items. Pepco intends to continue to pursue its appeal.

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

On Thursday, July 15, 2010, Pepco Energy Services’ thermal energy business unit disconnected chilled water service to four facilities in Atlantic City, New Jersey due to a break in a 36-inch water line. Chilled water is used to provide air conditioning to the casinos and other customer facilities served by Pepco Energy Services. The affected facilities are located along the boardwalk in the midtown area of Atlantic City; service to thermal customers not served by the water line was not affected. Pepco Energy Services secured replacement equipment including chillers, cooling towers and generators, and restored cooling service to the affected customers that needed service by Sunday, July 18, 2010. Pepco Energy Services then evaluated the water line failure, completed the permanent repair and was able to restore normal service to customers on July 23, 2010. The pre-tax cost of installing and operating the temporary cooling equipment and completing the repair of the water line was approximately $3 million. Pepco Energy Services’ thermal energy service agreements with customers require Pepco Energy Services to undertake the repair of any assets that caused interruption of chilled water services. Under the agreements, the customers may seek to claim direct damages, such as costs to repair or

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replace customers’ assets, but are not entitled to indirect damages, such as lost profits or consequential damages. Because Pepco Energy Services incurred the costs to secure temporary chilled water service and to perform the permanent repair of the pipe leak, Pepco Energy Services currently expects that it has no additional material exposure from its customers for damages.

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

On July 1, 2010, PHI sold the Conectiv Energy wholesale power generation business to Calpine. Under New Jersey’s Industrial Site Recovery Act (ISRA), the transfer of ownership triggered an obligation on the part of Conectiv Energy to remediate any environmental contamination at each of the nine Conectiv Energy generating facility sites located in New Jersey. Under the Purchase Agreement dated April 20, 2010, between PHI and Calpine (the Purchase Agreement), Calpine has assumed responsibility for performing the ISRA-required remediation and for the payment of all related ISRA compliance costs up to $10 million. 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 $4 million as of September 30, 2010 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 that PHI intends to close, located at Conectiv Energy’s Edge Moor generating facility. The preliminary estimate of the costs to PHI to close the coal ash landfill ranges from approximately $2 million to $3 million, plus annual post-closure operations, maintenance and monitoring costs, estimated to range between $120,000 and $193,000 per year for 30 years. As of the end of the third quarter of 2010, PHI had accrued approximately $5 million for landfill closure and monitoring.

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

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 September 30, 2010, there are approximately 180 cases still pending against Pepco in the State Courts of Maryland, of which approximately 90 cases were filed after December 19, 2000, and were tendered to Mirant for defense and indemnification pursuant to the terms of the Asset Purchase and Sale Agreement between Pepco and Mirant under which Pepco sold its generation assets to Mirant in 2000.

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

Environmental Litigation

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

Franklin Slag Pile Site. On November 26, 2008, ACE received a general notice letter from the U.S. Environmental Protection Agency (EPA) concerning the Franklin Slag Pile site in Philadelphia, Pennsylvania, asserting that ACE is a potentially responsible party (PRP) that may have liability with respect to the site. If liable, ACE would be responsible for reimbursing EPA for clean-up costs incurred and to be incurred by the agency and for the costs of implementing an EPA-mandated remedy. The EPA’s claims are based on ACE’s sale of boiler slag from the B.L. England generating facility to MDC Industries, Inc. (MDC) during the period June 1978 to May 1983 (ACE owned B.L. England at that time and MDC formerly operated the Franklin Slag Pile site). EPA further claims that the boiler slag ACE sold to MDC contained copper and lead, which are hazardous substances under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA), and that the sales transactions may have constituted an arrangement for the disposal or treatment of hazardous substances at the site, which could be a basis for liability under CERCLA. The EPA’s letter also states that as of the date of the letter, EPA’s expenditures for response measures at the site exceed $6 million. EPA estimates approximately $6 million as the cost for future response measures it recommends. ACE understands that the EPA sent similar general notice letters to three other companies and various individuals.

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

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

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

Benning Road Site. On September 21, 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 distribution and generating facility as one of six land-based sites potentially contributing to contamination of the Lower Anacostia River. The letter states 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 facility if an agreement for a comprehensive study to evaluate (and, if necessary as a result of the study, to clean up the facility) is not in effect by mid-December 2010. In a letter dated October 8, 2010, 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 facility. The District’s letter also states that EPA will list the Benning Road facility on the National Priorities List by December 2010 if contamination at the facility is not addressed in a timely manner and that if Pepco fails to meet the District’s December 2010 deadline, the District intends to sue Pepco and Pepco Energy Services in federal court to seek a scientific study to identify the nature of conditions at the Benning Road facility, abatement of conditions, compensation for natural resource damages, and reimbursement of DDOE’s related costs. PHI is in the process of evaluating the potential financial exposure at this site and has scheduled a meeting with DDOE with the intent of reaching an agreement by the mid-December deadline.

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

Indian River Oil Release

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

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PHI’s Cross-Border Energy Lease Investments

Between 1994 and 2002, PCI, a subsidiary of PHI, entered into eight cross-border energy lease investments involving public utility assets (primarily consisting of hydroelectric generation and coal-fired electric generating facilities and natural gas distribution networks) located outside of the United States. Each of these investments is structured as a sale and leaseback transaction commonly referred to as a sale-in/lease-out or SILO transaction. PHI’s current annual tax benefits from these eight cross-border energy lease investments are approximately $59 million. As of September 30, 2010, PHI’s equity investment in its cross-border energy leases was approximately $1.4 billion, which included the impact of the reassessments discussed below. From January 1, 2001, the earliest year that remains open to audit, to September 30, 2010, PHI has derived approximately $560 million in federal and state income tax benefits from the depreciation and interest deductions in excess of rental income with respect to these cross-border energy lease investments.

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

PHI believes that it is unlikely that a resolution will be reached with the Appeals Office and, therefore, PHI currently intends to pursue litigation against the IRS to defend its tax position, which, absent a settlement, may take several years to resolve. PHI expects to pay the $74 million of additional tax claimed by the IRS to be due with respect to the cross border energy leases for 2001 and 2002, plus interest and penalties of approximately $34 million, by December 31, 2010.

In the last several years, IRS challenges to certain cross-border lease transactions have been the subject of litigation, including several decisions in favor of the IRS which were factored into PHI’s decision to adjust the lease values in June 2008. On October 21, 2009, the U.S. Court of Federal Claims issued a decision in favor of a taxpayer regarding a cross-border lease transaction. PHI views this ruling as a favorable development in PHI’s dispute with the IRS because the transaction that is the subject of the ruling is similar in many respects to PHI’s cross-border energy lease investments.

At December 31, 2009, PHI modified its tax cash flow assumptions under its cross-border energy lease investments for the period 2010-2012 to reflect the anticipated timing of potential litigation with the IRS concerning the investments. As a result of the recalculation of the equity investment, PHI recorded a $2 million after-tax non-cash earnings charge in 2009, and expects to record an offsetting $3 million after-tax non-cash earnings benefit during the latter part of 2010, once the tax payment for the 2001 and 2002 income tax returns is made.

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 September 30, 2010, it would be obligated to pay approximately $673 million in additional federal and state taxes and $126 million of interest. In addition, the IRS could require PHI to pay a penalty of up to 20% on the amount of additional taxes due.

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PHI anticipates that any additional taxes that it would be required to pay as a result of the disallowance of prior deductions or a re-characterization of the leases as loans would be recoverable in the form of lower taxes over the remaining terms of the affected leases. Moreover, the entire amount of any additional tax would not be due immediately. Rather, the federal and state taxes would be payable when the open audit years are closed and PHI amends subsequent tax returns not then under audit. To mitigate the taxes due in the event of a total disallowance of tax benefits, PHI could, were it to so elect, choose to liquidate all or a portion of its cross-border energy lease portfolio, which PHI estimates could be accomplished over a period of six months to one year. Based on current market values, PHI estimates that liquidation of the entire portfolio would generate sufficient cash proceeds to cover the estimated $799 million in federal and state taxes and interest due as of September 30, 2010, in the event of a total disallowance of tax benefits and a recharacterization of the transactions as loans. If payments of additional taxes and interest preceded the receipt of liquidation proceeds, the payments would be funded by currently available sources of liquidity.

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

District of Columbia Tax Legislation

On December 24, 2009, the Mayor of the District of Columbia approved legislation adopted by the City Council that imposes mandatory combined unitary business reporting beginning with tax year 2011, and revises the District’s related party expense disallowance beginning with tax year 2009. Because the City Council must still enact further legislation providing guidance on how to implement combined unitary business reporting before this provision is effective, PHI believes that the legislative process was not complete as of September 30, 2010, and, therefore, the effect of the legislation for combined unitary business tax reporting has not been accounted for as of September 30, 2010. However, because the City Council is not required to enact any further legislation in order for the provisions for the disallowance of related party transactions to become effective, PHI accrued approximately $500,000 of additional income tax expense during the first quarter of 2010.

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

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

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

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

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As of September 30, 2010, Pepco Holdings and its subsidiaries were parties to a variety of agreements pursuant to which they were guarantors for standby letters of credit, performance residual value, and other commitments and obligations. The commitments and obligations, in millions of dollars, were as follows:

	Guarantor
	PHI		DPL		ACE		Pepco		Total
Energy marketing obligations of Conectiv Energy (a)	$	179	$	—	$	—	$	—	$	179
Energy procurement obligations of Pepco Energy Services (a)		315		—		—		—		315
Guaranteed lease residual values (b)		1		4		3		2		10
Total	$	495	$	4	$	3	$	2	$	504

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

(b) Subsidiaries of Pepco Holdings have guaranteed residual values in excess of fair value of certain equipment and fleet vehicles held through lease agreements. As of September 30, 2010, obligations under the guarantees were approximately $10 million. Assets leased under agreements subject to residual value guarantees are typically for periods ranging from 2 years to 10 years. Historically, payments under the guarantees have not been made by the guarantor as, under normal conditions, the contract runs to full term at which time the residual value is minimal. As such, Pepco Holdings believes the likelihood of payment being required under the guarantee is remote.

Pepco Energy Services has entered into various energy savings guaranty contracts associated with the installation of energy savings equipment for federal, state and local government customers. As part of those contracts, Pepco Energy Services typically guarantees that the equipment will generate a specified amount of energy savings on an annual basis based on contractually established performance measures. The longest remaining term of the guarantees currently in effect is 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. The liability for energy savings guaranty contracts has not changed during the nine month reporting period ending September 30, 2010 and currently is less than $1 million. Pepco Energy Services did not make any significant payouts under the guarantees, and there was no significant change in guarantees issued or expired for the three and nine months ended September 30, 2010.

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

Dividends

On October 28, 2010, Pepco Holdings’ Board of Directors declared a dividend on common stock of 27 cents per share payable December 31, 2010, to shareholders of record on December 10, 2010.

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(15) DISCONTINUED OPERATIONS

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

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

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

Operating Results

The operating results of Conectiv Energy are as follows:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2010			2009		2010			2009
	(millions of dollars)
(Loss) income from operations of discontinued operations, net of income taxes	$	(6	)	$	20	$	2		$	10
Net gains (losses) from dispositions of assets and businesses of discontinued operations, net of income taxes		2			—		(128	)		—
(Loss) Income From Discontinued Operations, net of income taxes	$	(4	)	$	20	$	(126	)	$	10

(Loss) income from operations of discontinued operations, net of income taxes for the nine months ended September 30, 2010, includes after-tax expenses for employee severance and retention benefits of $9 million and after-tax accrued expenses for certain obligations associated with the sale of the wholesale power generation business to Calpine of $12 million.

Net gains (losses) from dispositions of assets and businesses of discontinued operations, net of income taxes for the nine months ended September 30, 2010, includes (i) the after-tax loss on the sale of the wholesale power generation business to Calpine of $73 million (which is inclusive of the after-tax writedown of $67 million recorded in the second quarter of 2010 and is subject to final post-closing adjustments), (ii) after-tax net losses on sales of assets and businesses not sold to Calpine of $27 million (which is 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 $28 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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PHI currently estimates that the sale of the wholesale power generation business to Calpine and the liquidation of the remaining Conectiv Energy assets and businesses will result in a loss through the completion of the liquidation for financial reporting purposes ranging from $110 million to $125 million, after tax. This range of loss includes estimates of (i) the loss on the Calpine transaction, including transaction expenses, (ii) the additional income tax charges associated with the disposition transactions, (iii) expenses for employee severance and retention benefits, and (iv) accrued expenses for certain obligations associated with the Calpine transaction, offset by (v) estimated net gains from the ongoing disposition of Conectiv Energy’s remaining assets and businesses not included in the Calpine sale, including load service supply contracts, the energy hedging portfolio, certain tolling agreements and other non-generation assets.

The estimated after-tax proceeds from the sale of the wholesale power generation business to Calpine and the liquidation of the remaining Conectiv Energy assets and businesses, combined with the return of cash collateral posted under the contracts, are expected to total approximately $1.7 billion, with a related current income tax obligation approximating $217 million.

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Balance Sheet Information

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

	September 30, 2010			December 31, 2009
	(millions of dollars)
Current Assets
Cash and cash equivalents	$	16		$	2
Accounts receivable, less allowance for uncollectible accounts		117			194
Inventories		23			128
Derivative assets		11			21
Prepaid expenses and other		2			1
Total Current Assets		169			346
Investments And Other Assets
Derivative assets		5			27
Other		2			2
Total Investments and Other Assets		7			29
Property, Plant And Equipment
Property, plant and equipment		2			2,286
Accumulated depreciation		(2	)		(664	)
Net Property, Plant and Equipment		—			1,622
Current Liabilities
Accounts payable and accrued liabilities		44			138
Derivative liabilities		30			37
Other		10			16
Total Current Liabilities		84			191
Deferred Credits
Derivative liabilities		16			8
Other		—			11
Total Deferred Credits		16			19
Net Assets	$	76		$	1,787

Derivative Instruments and Hedging Activities

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

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

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

	As of September 30, 2010
Balance Sheet Caption	Derivatives Designated as Hedging Instruments			Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting			Net Derivative Instruments
	(millions of dollars)
Derivative Assets (current assets held for sale)	$	—		$	756		$	756		$	(745	)	$	11
Derivative Assets (non-current assets held for sale)		—			68			68			(63	)		5
Total Derivative Assets		—			824			824			(808	)		16
Derivative Liabilities (current liabilities associated with assets held for sale)		(33	)		(844	)		(877	)		847			(30	)
Derivative Liabilities (non-current liabilities associated with assets held for sale)		—			(79	)		(79	)		63			(16	)
Total Derivative Liabilities		(33	)		(923	)		(956	)		910			(46	)
Net Derivative (Liability) Asset	$	(33	)	$	(99	)	$	(132	)	$	102		$	(30	)
	As of December 31, 2009
Balance Sheet Caption	Derivatives Designated as Hedging Instruments			Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting			Net Derivative Instruments
	(millions of dollars)
Derivative Assets (current assets held for sale)	$	52		$	574		$	626		$	(605	)	$	21
Derivative Assets (non-current assets held for sale)		23			44			67			(40	)		27
Total Derivative Assets		75			618			693			(645	)		48
Derivative Liabilities (current liabilities associated with assets held for sale)		(236	)		(575	)		(811	)		774			(37	)
Derivative Liabilities (non-current liabilities associated with assets held for sale)		(14	)		(27	)		(41	)		33			(8	)
Total Derivative Liabilities		(250	)		(602	)		(852	)		807			(45	)
Net Derivative (Liability) Asset	$	(175	)	$	16		$	(159	)	$	162		$	3

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PEPCO HOLDINGS

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

	September 30, 2010		December 31, 2009
	(millions of dollars)
Cash collateral pledged to counterparties with the right to reclaim	$	102	$	168
Cash collateral received from counterparties with the obligation to return		—		(6	)

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

Derivatives Designated as Hedging Instruments

Cash Flow Hedges

For energy commodity contracts that are designated and qualify as cash flow hedges, the effective portion of the gain or loss on the derivative is reported as a component of accumulated other comprehensive loss (AOCL) and is reclassified into income in the same period or periods during which the hedged transactions affect income. Gains and losses on the derivative representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current income. This information for the activity of Conectiv Energy during the three and nine months ended September 30, 2010 and 2009 is provided in the table below:

	Three Months  Ended September 30,						Nine Months  Ended September 30,
	2010			2009			2010			2009
	(millions of dollars)
Amount of net pre-tax gain (loss) arising during the period included in other comprehensive loss	$	(5	)	$	(11	)	$	(79	)	$	(187	)
Amount of net pre-tax (loss) gain reclassified into income:
Effective portion:
Loss from Discontinued Operations, net of income taxes		(28	)		(63	)		(134	)		(183	)
Ineffective portion:
Loss from Discontinued Operations, net of income taxes (a) (b)		2			2			(85	)		(1	)
Total net (loss) gain reclassified into income		(26	)		(61	)		(219	)		(184	)
Net pre-tax gain (loss) on commodity derivatives included in other comprehensive loss	$	21		$	50		$	140		$	(3	)

(a) For the three months ended September 30, 2010 and 2009, amounts of $(2) million and zero, respectively, were reclassified from AOCL to income because the forecasted transactions were deemed probable not to occur.

(b) For the nine months ended September 30, 2010 and 2009, amounts of $86 million and $3 million, respectively, were reclassified from AOCL to income because the forecasted transactions were deemed probable not to occur.

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PEPCO HOLDINGS

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

	Quantities
Commodity	September 30, 2010		December 31, 2009
Forecasted Purchases Hedges
Coal (Tons)		—		325,000
Natural gas (One Million British Thermal Units (MMBtu))		—		43,032,500
Electricity (Megawatt hours (MWh))		762,429		10,758,844
Heating oil (Barrels)		—		89,000
Forecasted Sales Hedges
Coal (Tons)		—		255,000
Natural gas (MMBtu)		—		3,859,643
Electricity (MWh)		—		5,701,472
Electric capacity (MW-Days)		—		203,640
Financial transmission rights (MWh)		12,480		48,014

Cash Flow Hedges Included in Accumulated Other Comprehensive Loss

The tables below provide details regarding effective cash flow hedges of Conectiv Energy included in PHI’s consolidated balance sheet as of September 30, 2010 and December 31, 2009. Cash flow hedges are marked-to-market on the balance sheet with corresponding adjustments to AOCL. The data in the tables indicate the cumulative net loss after-tax related to effective cash flow hedges by contract type included in AOCL, the portion of AOCL expected to be reclassified to income during the next 12 months, and the maximum hedge or deferral term:

	Accumulated Other Comprehensive Loss After-tax (a)		Portion Expected to be Reclassified to Income during the Next 12 Months		Maximum Term
	(millions of dollars)
Energy Commodity Contracts as of September 30, 2010 (a)	$	20	$	20		3 months
Energy Commodity Contracts as of September 30, 2009 (b)	$	109	$	140		51 months

(a) The unrealized derivative losses recorded in AOCL are largely offset by forecasted electricity physical purchases in gain positions that are not recorded on the balance sheet because they qualify as normal sales under FASB guidance on derivatives and hedging.

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

Fair Value Hedges

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

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PEPCO HOLDINGS

Other Derivative Activity

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

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

	Three Months  Ended September 30,						Nine Months  Ended September 30,
	2010			2009			2010			2009
	(millions of dollars)
Realized mark-to-market gains (losses)	$	3		$	8		$	29		$	44
Unrealized mark-to-market (losses) gains		(3	)		(4	)		(27	)		(53	)
Total net mark-to-market (losses) gains	$	—		$	4		$	2		$	(9	)

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

	September 30, 2010				December 31, 2009
Commodity	Quantity		Net Position		Quantity		Net Position
Coal (Tons)		—		—		60,000		Long
Natural gas (MMBtu)		1,272,024		Long		2,268,024		Long
Natural gas basis (MMBtu)		—		—		12,445,000		Long
Heating oil (Barrels)		46,000		Short		139,000		Short
RBOB UL gasoline (Barrels)		1,000		Short		—		—
Electricity (MWh)		1,204,830		Long		76,324		Long
Electric capacity (MW-Days)		16,560		Short		—		—
Financial transmission rights (MWh)		934,112		Short		1,241,237		Short

Contingent Credit Risk Features

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

The gross fair value of Conectiv Energy’s derivative liabilities, excluding the impact of offsetting transactions or collateral under master netting agreements, with credit risk-related contingent features on September 30, 2010 and December 31, 2009, was $212 million and $179 million, respectively. As of those dates, Conectiv Energy had posted cash collateral of $11 million and $17 million, respectively, in the normal course of business against the gross derivative liability resulting in a net liability of $201 million and $162 million, respectively, before giving effect to offsetting transactions that are encompassed within master netting agreements that would reduce this amount. Conectiv Energy’s net settlement amount in the event of a downgrade of PHI below “investment grade” as of September 30, 2010 and December 31, 2009, would have been approximately $59 million and $63 million, respectively, after taking into consideration the master netting agreements. The offsetting transactions or

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collateral that would reduce Conectiv Energy’s obligation to the net settlement amount include derivatives and normal purchase and normal sale contracts in a gain position as well as letters of credit already posted as collateral.

PHI’s primary sources for posting cash collateral or letters of credit are its credit facilities. At September 30, 2010 and December 31, 2009, the aggregate amount of cash plus borrowing capacity under the credit facilities available to meet the future liquidity needs of PHI, including Conectiv Energy, totaled $912 million and $820 million, respectively. On October 15, 2010, a $400 million unsecured credit facility maintained by PHI expired and was replaced by two bi-lateral 364-day unsecured credit agreements in the aggregate amount of $200 million. A PHI $50 million bi-lateral credit agreement will expire on November 2, 2010.

Fair Value Disclosures

Conectiv Energy has adopted FASB guidance on fair value measurement and disclosures (ASC 820) which established a framework for measuring fair value and expanded disclosures about fair value measurements, that is further described in Note (13), “Fair Value Disclosures.”

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

The level 3 instruments with the most significant amount of fair value at September 30, 2010 are electricity derivatives. The majority of Conectiv Energy’s pricing information for these level 3 valuations was obtained from a third party pricing system used widely throughout the energy industry. A portion of these electricity derivatives are comprised of load service contracts valued using liquid hub prices, a zonal congestion adder that is calculated using historical regression, historical ancillary service costs, and a series of modeled risk adders.

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

	Fair Value Measurements at September 30, 2010
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Derivative instruments (a)
Natural Gas (b)	$	3	$	—	$	3	$	—
Electricity (c)		13		—		5		8
	$	16	$	—	$	8	$	8
LIABILITIES
Derivative instruments (a)
Natural Gas (b)	$	55	$	23	$	32	$	—
Electricity (c)		93		—		93		—
	$	148	$	23	$	125	$	—

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

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

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

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PEPCO HOLDINGS

	Fair Value Measurements at December 31, 2009
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Derivative instruments (a)
Coal (b)	$	8	$	—	$	8	$	—
Natural Gas (c)		4		—		4		—
Electricity (d)		34		—		4		30
Capacity (e)		8		8		—		—
	$	54	$	8	$	16	$	30
LIABILITIES
Derivative instruments (a)
Coal (b)	$	6	$	—	$	6	$	—
Natural Gas (c)		74		52		22		—
Electricity (d)		126		—		123		3
Oil (f)		5		4		1		—
Capacity (e)		2		2		—		—
	$	213	$	58	$	152	$	3

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

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

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

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

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

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

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

	Nine Months  Ended September 30,
	2010			2009
	(millions of dollars)
Beginning balance as of January 1	$	27		$	2
Total gains or (losses) (realized and unrealized)
Included in loss from discontinued operations, net of tax (a)		81			8
Included in accumulated other comprehensive loss		(13	)		25
Purchases and issuances		—			—
Settlements		(87	)		(6	)
Transfers in (out) of Level 3		—			(7	)
Ending balance as of September 30	$	8		$	22

(a) For the nine months ended September 30, 2010, of the $81 million gain, $8 million is still held as of the reporting date. For the nine months ended September 30, 2009, of the $8 million gain, $5 million is still held as of the reporting date.

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(16) RESTRUCTURING CHARGE

With the ongoing wind down of the retail energy supply business of Pepco Energy Services and the disposition of Conectiv Energy, PHI is repositioning itself as a regulated transmission and distribution company. In connection with this repositioning, PHI commenced a comprehensive organizational review in the second quarter of 2010 to identify opportunities to streamline the organization and to achieve certain reductions in corporate overhead costs that are allocated to its operating segments. This review has resulted in the adoption of a phased restructuring plan (the plan). PHI began implementing the initial phase of the plan during the third quarter, identifying 165 positions that will be eliminated during the fourth quarter of 2010. The second phase of the plan has also commenced, which will focus on identifying additional cost reduction opportunities through process improvements and operational efficiencies. PHI currently estimates that the implementation of the plan will result in an annual reduction of at least $20 million in corporate overhead costs.

In connection with the restructuring plan, PHI recorded a pre-tax restructuring charge of $14 million for the three and nine months ended September 30, 2010 related to severance and health and welfare benefits for anticipated employee terminations. The severance and health and welfare benefits were estimated based on the years of service and compensation levels of the employees that could be associated with the 165 eliminated positions. The final amount of the restructuring charge for severance and health and welfare benefits may vary from the estimate depending on the specific employees severed as part of the plan. The restructuring charge has been allocated to PHI’s operating segments and has been reflected as a separate line item in the Consolidated Statements of Income (Loss). The amount of restructuring charge recorded by segment is as follows:

	For The Three And Nine Months Ended September 30, 2010
	(millions of dollars)
	Power Delivery		Pepco Energy Services		Other Non- Regulated		Corporate and Other		PHI Consolidated
Employee severance and health and welfare benefits	$	13	$	—	$	—	$	1	$	14
Total restructuring charge	$	13	$	—	$	—	$	1	$	14

Reconciliations of the beginning and ending balances of PHI’s accrued restructuring charges for the three months ended September 30, 2010 are as follows:

	Three Months Ended September 30, 2010
	(millions of dollars)
	Power Delivery		Pepco Energy Services		Other Non- Regulated		Corporate and Other		PHI Consolidated
Beginning balance as of July 1, 2010	$	—	$	—	$	—	$	—	$	—
Restructuring charge		13		—		—		1		14
Cash payments		—		—		—		—		—
Ending balance as of September 30, 2010	$	13	$	—	$	—	$	1	$	14

Under FASB guidance on exit or disposal cost obligations (ASC 420), certain severance costs are being recognized over the remaining service periods for certain employees to be terminated under the restructuring plan. Generally, the remaining service periods are expected to end by December 31, 2010 and, accordingly, PHI expects to record an additional $4 million of employee severance and health and welfare benefits in the fourth quarter of 2010. PHI may incur further severance costs if additional positions are identified for elimination. PHI may incur other restructuring charges for employee termination benefits and other cost reduction efforts as part of the implementation of the plan.

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POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
	(millions of dollars)
Operating Revenue	$	706		$	648		$	1,797		$	1,743
Operating Expenses
Purchased energy		356			350			932			972
Other operation and maintenance		93			84			252			244
Restructuring charge		6			—			6			—
Depreciation and amortization		43			36			121			108
Other taxes		110			83			273			230
Effects of divestiture-related claims		9			(26	)		11			(40	)
Total Operating Expenses		617			527			1,595			1,514
Operating Income		89			121			202			229
Other Income (Expenses)
Interest and dividend income		—			—			1			1
Interest expense		(24	)		(25	)		(74	)		(75	)
Other income		5			2			10			7
Other expenses		—			—			—			(1	)
Total Other Expenses		(19	)		(23	)		(63	)		(68	)
Income Before Income Tax Expense		70			98			139			161
Income Tax Expense		33			40			62			67
Net Income		37			58			77			94
Retained Earnings at Beginning of Period		720			660			730			624
Dividends Paid to Parent		(45	)		—			(95	)		—
Retained Earnings at End of Period	$	712		$	718		$	712		$	718

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

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POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

(Unaudited)

	September 30, 2010			December 31, 2009
	(millions of dollars)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	177		$	213
Restricted cash equivalents		—			1
Accounts receivable, less allowance for uncollectible accounts of $23 million and $17 million, respectively		394			354
Inventories		47			43
Prepayments of income taxes		73			79
Income taxes receivable		19			—
Prepaid expenses and other		36			48
Total Current Assets		746			738
INVESTMENTS AND OTHER ASSETS
Regulatory assets		181			166
Prepaid pension expense		279			295
Investment in trust		25			25
Income taxes receivable		37			64
Other		75			70
Total Investments and Other Assets		597			620
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		6,070			5,865
Accumulated depreciation		(2,576	)		(2,481	)
Net Property, Plant and Equipment		3,494			3,384
TOTAL ASSETS	$	4,837		$	4,742

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

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PEPCO

POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

(Unaudited)

	September 30, 2010		December 31, 2009
	(millions of dollars, except shares)
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Current portion of long-term debt	$	—	$	16
Accounts payable and accrued liabilities		199		154
Accounts payable due to associated companies		78		111
Capital lease obligations due within one year		7		7
Taxes accrued		100		37
Interest accrued		37		18
Liabilities and accrued interest related to uncertain tax positions		3		—
Other		108		124
Total Current Liabilities		532		467
DEFERRED CREDITS
Regulatory liabilities		155		145
Deferred income taxes, net		920		893
Investment tax credits		7		8
Other postretirement benefit obligation		75		71
Income taxes payable		5		5
Liabilities and accrued interest related to uncertain tax positions		43		29
Other		54		58
Total Deferred Credits		1,259		1,209
LONG-TERM LIABILITIES
Long-term debt		1,540		1,539
Capital lease obligations		89		92
Total Long-Term Liabilities		1,629		1,631
COMMITMENTS AND CONTINGENCIES (NOTE 10)
EQUITY
Common stock, $.01 par value, 200,000,000 shares authorized, 100 shares outstanding		—		—
Premium on stock and other capital contributions		705		705
Retained earnings		712		730
Total Equity		1,417		1,435
TOTAL LIABILITIES AND EQUITY	$	4,837	$	4,742

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

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POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months  Ended September 30,
	2010			2009
	(millions of dollars)
OPERATING ACTIVITIES
Net income	$	77		$	94
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		121			108
Effects of divestiture-related claims		11			(40	)
Changes in restricted cash equivalents related to Mirant settlement		—			102
Deferred income taxes		50			101
Changes in:
Accounts receivable		(40	)		(12	)
Regulatory assets and liabilities, net		(25	)		(55	)
Accounts payable and accrued liabilities		12			(25	)
Pension contributions		—			(170	)
Taxes accrued		60			56
Other assets and liabilities		27			23
Net Cash From Operating Activities		293			182
INVESTING ACTIVITIES
Investment in property, plant and equipment		(222	)		(196	)
Changes in restricted cash equivalents		1			—
Net other investing activities		(1	)		(3	)
Net Cash Used By Investing Activities		(222	)		(199	)
FINANCING ACTIVITIES
Dividends paid to Parent		(95	)		—
Capital contribution from Parent		—			94
Issuances of long-term debt		—			110
Reacquisition of long-term debt		(16	)		(50	)
Repayments of short-term debt, net		—			(125	)
Net other financing activities		4			(4	)
Net Cash (Used by) From Financing Activities		(107	)		25
Net (Decrease) Increase in Cash and Cash Equivalents		(36	)		8
Cash and Cash Equivalents at Beginning of Period		213			146
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	177		$	154
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash received for income taxes (includes payments from PHI for Federal income taxes)	$	25		$	86

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

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NOTES TO FINANCIAL STATEMENTS

POTOMAC ELECTRIC POWER COMPANY

(1) ORGANIZATION

Potomac Electric Power Company (Pepco) is engaged in the transmission and distribution of electricity in the District of Columbia and major portions of Prince George’s County and Montgomery County in suburban Maryland. Pepco also provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its 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, 2009. In the opinion of Pepco’s management, the financial statements contain all adjustments (which all are of a normal recurring nature) necessary to present fairly Pepco’s financial condition as of September 30, 2010, in accordance with GAAP. The year-end December 31, 2009 balance sheet was derived from audited financial statements, but does not include all disclosures required by GAAP. Interim results for the three and nine months ended September 30, 2010 may not be indicative of results that will be realized for the full year ending December 31, 2010 since the sales of electric energy are seasonal.

Use of Estimates

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

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

Storm Costs

In the third quarter of 2010, Pepco recorded $23 million in restoration costs related to severe summer storms, of which $13 million was charged to Other Operation and Maintenance expense and $10 million was recorded as capital expenditures. A portion of the recorded costs of the restoration work relates to services provided by outside contractors and other utilities that were not billed as of September 30, 2010, and accordingly have been estimated. These estimates are subject to adjustment when the actual billings are received in the fourth quarter of 2010. The actual billings may vary from the estimates of such billings.

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During the first quarter of 2010, Pepco incurred significant costs associated with the February 2010 severe winter storms. The actual billings related to the February storms were received by the end of the second quarter with final costs approximating $10 million, with $8 million charged to Other Operation and Maintenance expense and $2 million recorded as capital expenditures. Other Operation and Maintenance expense was further decreased by approximately $5 million during the third quarter due to an adjustment for recoverable February storm costs in accordance with the Maryland Public Service Commission rate order issued in August 2010.

Network Service Transmission Rates

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

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in Pepco’s gross revenues were $106 million and $71 million for the three months ended September 30, 2010 and 2009, respectively, and $249 million and $194 million for the nine months ended September 30, 2010 and 2009, respectively.

Reclassifications and Adjustments

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

In 2010, Pepco recorded certain adjustments to correct errors in Income tax expense which resulted in an increase to Income tax expense of $4 million each for the three and nine months ended September 30, 2010, respectively.

In the third quarter of 2010, Pepco recorded an adjustment to correct certain errors related to other taxes which resulted in a decrease to Other taxes expense of $5 million (pre-tax) for the three and nine months ended September 30, 2010.

During the third quarter of 2009, Pepco recorded an adjustment to correct amounts incorrectly recorded as an expense related to a new PJM Interconnection, LLC (PJM) program, which should have been deferred as a regulatory asset. The adjustment resulted in a decrease to Purchased energy expenses for the three and nine months ended September 30, 2009 of $1 million.

(3) NEWLY ADOPTED ACCOUNTING STANDARDS

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

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

The guidance was effective for transfers of financial assets occurring in fiscal periods beginning on January 1, 2010 for Pepco. As of January 1, 2010, Pepco has adopted the provisions of this guidance and determined that the guidance did not have a material impact on its overall financial condition, results of operations, or cash flows.

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Consolidation of Variable Interest Entities (ASC 810)

The FASB issued new consolidation guidance regarding variable interest entities effective January 1, 2010 that eliminated the quantitative analysis requirement and added new qualitative factors to determine whether consolidation is required. The new qualitative factors are applied on a quarterly basis to interests in variable interest entities. Under the new guidance, the holder of the interest with the power to direct the most significant activities of the entity and the right to receive benefits or absorb losses significant to the entity would consolidate. The new guidance retained the provision that allows entities created before December 31, 2003 to be scoped out from a consolidation assessment if exhaustive efforts are taken and there is insufficient information to determine whether there is a relationship with a variable interest entity or the primary beneficiary of a variable interest entity. Pepco has adopted the provisions of the new FASB guidance on consolidation of variable interest entities, and it did not have a material impact on its overall financial condition, results of operations, or cash flows.

Fair Value Measurements and Disclosures (ASC 820)

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

Subsequent Events (ASC 855)

The FASB issued new guidance which eliminated the requirement for Pepco to disclose the date through which it has evaluated subsequent events beginning with its March 31, 2010 financial statements.

(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Fair Value Measurements and Disclosures (ASC 820)

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

(5) SEGMENT INFORMATION

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

(6) PENSION AND OTHER POSTRETIREMENT BENEFITS

Pepco accounts for its participation in the Pepco Holdings benefit plans as participation in a multi-employer plan. PHI’s pension and other postretirement net periodic benefit cost for the three months ended September 30, 2010 and 2009, before intercompany allocations from the PHI Service Company, of $26 million and $36 million, respectively, included $10 million and $9 million, respectively, for Pepco’s allocated share. PHI’s pension and other postretirement net periodic benefit cost for the nine months ended September 30, 2010 and 2009, before intercompany allocations from the PHI Service Company, of $86 million and $111 million, respectively, included $30 million and $28 million, respectively, for Pepco’s allocated share.

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(7) DEBT

Credit Facilities

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

At September 30, 2010 and December 31, 2009, the amount of cash plus borrowing capacity under the $1.5 billion credit facility available to meet the liquidity needs of PHI’s utility subsidiaries was $494 million and $582 million, respectively.

(8) INCOME TAXES

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

	Three Months  Ended September 30,						Nine Months  Ended September 30,
	2010			2009			2010			2009
Federal statutory rate		35.0	%		35.0	%		35.0	%		35.0	%
Increases (decreases) resulting from:
Depreciation		1.7			1.2			2.7			2.2
State income taxes, net of federal effect		5.4			5.4			5.5			5.5
Change in estimates and interest related to uncertain and effectively settled tax positions		6.8			.8			5.1			1.6
Other, net		(1.8	)		(1.6	)		(3.7	)		(2.7	)
Effective Income Tax Rate		47.1	%		40.8	%		44.6	%		41.6	%

Pepco’s effective tax rates for the three months ended September 30, 2010 and 2009 were 47.1% and 40.8%, respectively. The increase in the effective tax rate primarily results from the reversal of $2 million of previously recorded tax benefits related to changes in estimates and interest related to uncertain and effectively settled tax positions.

Pepco’s effective tax rates for the nine months ended September 30, 2010 and 2009 were 44.6% and 41.6%, respectively. The increase in the effective tax rate primarily results from the reversal of $2 million of previously recorded tax benefits related to changes in estimates and interest related to uncertain and effectively settled tax positions.

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

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(9) FAIR VALUE DISCLOSURES

Fair Value of Assets and Liabilities Excluding Debt

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

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

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

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

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

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

The following tables set forth, by level within the fair value hierarchy, Pepco’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2010 and December 31, 2009. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Pepco’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

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	Fair Value Measurements at September 30, 2010
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Executive deferred compensation plan assets
Money Market Funds	$	12	$	12	$	—	$	—
Life Insurance Contracts		52		—		34		18
	$	64	$	12	$	34	$	18
LIABILITIES
Executive deferred compensation plan liabilities
Life Insurance Contracts	$	12	$	—	$	12	$	—
	$	12	$	—	$	12	$	—

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

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

	Nine Months Ended September 30, 2010
	Life Insurance Contracts
	(millions of dollars)
Beginning balance as of January 1, 2010	$	18
Total gains or (losses) (realized and unrealized)
Included in income		3
Included in accumulated other comprehensive loss		—
Purchases and issuances		(3	)
Settlements		—
Transfers in (out) of Level 3		—
Ending balance as of September 30, 2010	$	18

	Nine Months Ended September 30, 2009
	Life Insurance Contracts
	(millions of dollars)
Beginning balance as of January 1, 2009	$	17
Total gains or (losses) (realized and unrealized)
Included in income		3
Included in accumulated other comprehensive loss		—
Purchases and issuances		(3	)
Settlements		—
Transfers in (out) of Level 3		—
Ending balance as of September 30, 2009	$	17

Gains or (losses) (realized and unrealized) included in income for the periods below are reported in Other Operation and Maintenance Expense as follows:

	Nine Months  Ended September 30, 2010
	(millions of dollars)
Total gains included in income for the period	$	3	$	3
Change in unrealized gains relating to assets still held at reporting date	$	3	$	3

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Fair Value of Debt Instruments

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

	September 30, 2010				December 31, 2009
	(millions of dollars)
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	1,540	$	1,846	$	1,555	$	1,707

The methods and assumptions described below were used to estimate, as of September 30, 2010 and December 31, 2009, the fair value of non-derivative financial instruments shown above for which it is practicable to estimate a value.

The fair value of long-term debt issued by Pepco was based on actual trade prices as of September 30, 2010 and December 31, 2009, or bid prices obtained from brokers if actual trade prices were not available.

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

(10) COMMITMENTS AND CONTINGENCIES

Regulatory and Other Matters

Proceeds from Settlement of Mirant Bankruptcy Claims

In 2007, Pepco received proceeds from the settlement of its Mirant Corporation (Mirant) bankruptcy claims relating to a power purchase agreement between Pepco and Panda-Brandywine L.P. (Panda PPA). In September 2008, Pepco transferred the Panda PPA to an unaffiliated third party, along with a payment to the third party of a portion of the settlement proceeds. In March 2009, the District of Columbia Public Service Commission (DCPSC) approved an allocation between Pepco and its District of Columbia customers of the District of Columbia portion of the Mirant bankruptcy settlement proceeds remaining after the transfer of the Panda PPA. As a result, Pepco recorded a pre-tax gain of $14 million in the first quarter of 2009 reflecting the District of Columbia proceeds retained by Pepco. In July 2009, the MPSC approved an allocation between Pepco and its Maryland customers of the Maryland portion of the Mirant bankruptcy settlement proceeds remaining after the transfer of the Panda PPA. As a result, Pepco recorded a pre-tax gain of $26 million in the third quarter of 2009 reflecting the Maryland proceeds retained by Pepco.

Rate Proceedings

In recent electric service distribution base rate cases, a bill stabilization adjustment mechanism (BSA) for Pepco electric service in Maryland and the District of Columbia has been approved and implemented by the MPSC and the DCPSC, respectively. Under the BSA, customer delivery rates are subject to adjustment (through a credit or surcharge mechanism), depending on whether actual distribution revenue per customer exceeds or falls short of the revenue-per-customer amount approved by the applicable public service commission. The BSA increases rates if actual distribution revenues fall below the approved level and decreases rates if actual distribution revenues are above the approved level. The result is that, over time, Pepco collects its authorized revenues for distribution deliveries. As a consequence, a BSA “decouples” distribution revenue from unit sales consumption and ties the growth in distribution revenues to the growth in the number of customers. Some advantages of the BSA are that it (i) eliminates revenue fluctuations due to weather and changes in customer usage patterns and, therefore, provides for more predictable distribution

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revenues that are better aligned with costs, (ii) provides for more reliable fixed-cost recovery, (iii) tends to stabilize customers’ delivery bills, and (iv) removes any disincentives for Pepco to promote energy efficiency programs for their customers, because it breaks the link between overall sales volumes and distribution revenues.

Maryland

In December 2009, Pepco filed an electric distribution base rate case in Maryland. The filing sought approval of an annual rate increase of approximately $40 million, based on a requested return on equity (ROE) of 10.75%. During the course of the proceeding, Pepco reduced its request to approximately $28.2 million. On August 6, 2010, the MPSC issued an order approving a rate increase of approximately $7.8 million, based on an ROE of 9.83%. On September 2, 2010, Pepco filed with the MPSC a motion for reconsideration of the following issues: (1) denial of inclusion in rate base of certain reliability plant investments, which occurred subsequent to the test period but before the rate effective period; (2) denial of Pepco’s request to increase depreciation rates to reflect a corrected formula relating to the cost of removal expenses; and (3) imposition of imputed cost savings to partially offset the costs of Pepco’s enhanced vegetation management program. The Office of People’s Counsel and MPSC Staff filed responses to Pepco’s motion on October 4, 2010. Maryland law and regulation do not mandate a response time from the MPSC regarding Pepco’s motion and, therefore, it is not known when the MPSC will issue a ruling on the motion.

District of Columbia Divestiture Case

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

On May 18, 2010, the DCPSC issued an order addressing all of the remaining issues related to the sharing of the proceeds of Pepco’s divestiture of its generating assets. In the order, the DCPSC ruled that Pepco is not required to share EDIT and ADITC with customers. However, the order also disallowed certain items that Pepco had included in the costs deducted from the proceeds of the sale of the generation assets. The disallowance of these costs, together with interest on the allowed amount, increases the aggregate amount Pepco is required to distribute to customers, pursuant to the sharing formula, by approximately $11 million. On June 17, 2010, Pepco filed an application for reconsideration of the DCPSC’s order, contesting (i) approximately $5 million of the approximate total of $6 million in disallowances and (ii) approximately $4 million of the approximately $5 million in interest to be credited to customers (reflecting a difference in the period of time over which interest was calculated as well as the balance to which interest would be applied). On July 16, 2010, the DCPSC denied Pepco’s application for reconsideration. On September 7, 2010, Pepco filed an appeal of the DCPSC’s decision with the District of Columbia Court of Appeals. PHI recognized expenses of $9 million and $11 million, respectively, for the three and nine months ended September 30, 2010 corresponding to the disallowed items. Pepco intends to continue to pursue its appeal.

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.

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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 September 30, 2010, there are approximately 180 cases still pending against Pepco in the State Courts of Maryland, of which approximately 90 cases were filed after December 19, 2000, and were tendered to Mirant for defense and indemnification pursuant to the terms of the Asset Purchase and Sale Agreement between Pepco and Mirant under which Pepco sold its generation assets to Mirant in 2000.

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

Environmental Litigation

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

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

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

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

Benning Road Site. On September 21, 2010, PHI received a letter from EPA stating that EPA and the District of Columbia Department of the Environment (DDOE) have identified Pepco’s Benning Road distribution facility as one of six land-based sites potentially contributing to contamination of the Lower Anacostia River. The letter states 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 facility if an agreement for a comprehensive study to evaluate (and, if necessary as a result of the study, to clean up the facility) is not in effect by mid-December 2010. In a letter dated October 8, 2010, the Office of the Attorney General of the District of Columbia notified Pepco of the District’s intent to sue Pepco under the Resource Conservation and Recovery Act for abatement of conditions related to Pepco’s historical activities, including the discharge of PCBs at the Benning Road facility. The District’s letter also states that EPA will list the Benning Road facility on the National Priorities List by December 2010 if contamination at the facility is not addressed in a timely manner and that if Pepco fails to meet the District’s December 2010 deadline, the District intends to sue Pepco in federal court to seek a scientific study to identify the nature of conditions at the Benning Road facility, abatement of conditions, compensation for natural resource damages, and reimbursement of DDOE’s related costs. Pepco is in the process of evaluating the potential financial exposure at this site and has scheduled a meeting with DDOE with the intent of reaching an agreement by the mid-December deadline.

District of Columbia Tax Legislation

On December 24, 2009, the Mayor of the District of Columbia approved legislation adopted by the City Council that imposes mandatory combined unitary business reporting beginning with tax year 2011, and revises the District’s related party expense disallowance beginning with tax year 2009. Because the City Council must still enact further legislation providing guidance on how to implement combined unitary business reporting before this provision is effective, PHI believes that the legislative process was not complete as of September 30, 2010, and, therefore, the effect of the legislation for combined unitary business tax reporting has not been accounted for as of September 30, 2010.

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

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

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(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 September 30, 2010 and 2009 were approximately $51 million and $43 million, respectively. PHI Service Company costs directly charged or allocated to Pepco for the nine months ended September 30, 2010 and 2009 were approximately $137 million and $127 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 September 30, 2010 and 2009 were approximately $3 million and $2 million, respectively. Amounts charged to Pepco by these companies for the nine months ended September 30, 2010 and 2009 were approximately $6 million and $5 million, respectively.

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

	For the Three  Months Ended September 30,				For the Nine  Months Ended September 30,
Income (Expense)	2010		2009		2010		2009
	(millions of dollars)
Purchased power under Default Electricity Supply contracts with Conectiv Energy Supply, Inc (a)	$	—	$	—	$	—	$	1

(a) Included in purchased energy expense.

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

	September 30, 2010			December 31, 2009
Asset (Liability)	(millions of dollars)
(Payable to) Receivable from Related Party (current) (a)
PHI Parent Company	$	—		$	(8	)
PHI Service Company		(25	)		(3	)
Pepco Energy Services (b)		(54	)		(99	)
Other		1			(1	)
Total	$	(78	)	$	(111	)
Money Pool Balance with Pepco Holdings (included in Cash and cash equivalents)	$	165		$	203

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

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

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(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 is repositioning itself as a regulated transmission and distribution company. In connection with this repositioning, PHI commenced a comprehensive organizational review in the second quarter of 2010 to identify opportunities to streamline the organization and to achieve certain reductions in corporate overhead costs that are allocated to its operating segments. This review has resulted in the adoption of a phased restructuring plan (the plan). PHI began implementing the initial phase of the plan during the third quarter, identifying 165 positions that will be eliminated during the fourth quarter of 2010. The second phase of the plan has also commenced, which will focus on identifying additional cost reduction opportunities through process improvements and operational efficiencies. PHI currently estimates that the implementation of the plan will result in an annual reduction of at least $20 million in corporate overhead costs.

In connection with the restructuring plan, Pepco recorded a pre-tax restructuring charge of $6 million for the three and nine months ended September 30, 2010 related to its allocation of severance and health and welfare benefits for anticipated terminations of corporate services employees at PHI. The severance and health and welfare benefits were estimated based on the years of service and compensation levels of the employees that could be associated with the 165 eliminated positions at PHI. The final amount of the restructuring charge for severance and health and welfare benefits may vary from the estimate depending on the specific employees severed as part of the plan. The restructuring charge has been reflected as a separate line item in the Statements of Income.

Reconciliations of the beginning and ending balances of Pepco’s accrued restructuring charges for the three months ended September 30, 2010 are as follows:

	Three Months Ended September 30, 2010
	(millions of dollars)
Beginning balance as of July 1, 2010	$	—
Restructuring charge		6
Cash payments		—
Ending balance as of September 30, 2010	$	6

Under FASB guidance on exit or disposal cost obligations (ASC 420), certain severance costs are being recognized over the remaining services periods for certain employees to be terminated under the restructuring plan. Generally, the remaining service periods are expected to end by December 31, 2010 and, accordingly, Pepco expects to record an additional $2 million of employee severance and health and welfare benefits in the fourth quarter of 2010. Pepco may incur further severance costs if additional positions are identified for elimination. Pepco may incur other restructuring charges for employee termination benefits and other cost reduction efforts as part of the implementation of the plan.

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DELMARVA POWER & LIGHT COMPANY

STATEMENTS OF INCOME

(Unaudited)

	Three Months  Ended September 30,						Nine Months  Ended September 30,
	2010			2009			2010			2009
	(millions of dollars)
Operating Revenue
Electric	$	342		$	311		$	901		$	883
Natural Gas		35			28			166			199
Total Operating Revenue		377			339			1,067			1,082
Operating Expenses
Purchased energy		225			211			585			591
Gas purchased		26			19			117			147
Other operation and maintenance		65			64			191			182
Restructuring charge		4			—			4			—
Depreciation and amortization		22			19			62			56
Other taxes		10			8			28			27
Total Operating Expenses		352			321			987			1,003
Operating Income		25			18			80			79
Other Income (Expenses)
Interest expense		(10	)		(11	)		(32	)		(33	)
Other income		1			—			4			1
Total Other Expenses		(9	)		(11	)		(28	)		(32	)
Income Before Income Tax Expense		16			7			52			47
Income Tax Expense (Benefit)		7			(7	)		23			7
Net Income		9			14			29			40
Retained Earnings at Beginning of Period		469			446			472			448
Dividends Paid to Parent		—			—			(23	)		(28	)
Retained Earnings at End of Period	$	478		$	460		$	478		$	460

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

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DELMARVA POWER & LIGHT COMPANY

BALANCE SHEETS

(Unaudited)

	September 30, 2010			December 31, 2009
	(millions of dollars)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	5		$	26
Accounts receivable, less allowance for uncollectible accounts of $15 million and $12 million, respectively		188			193
Inventories		42			40
Prepayments of income taxes		91			64
Prepaid expenses and other		20			19
Total Current Assets		346			342
INVESTMENTS AND OTHER ASSETS
Goodwill		8			8
Regulatory assets		245			207
Prepaid pension expense		143			157
Other		20			28
Total Investments and Other Assets		416			400
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		2,958			2,807
Accumulated depreciation		(894	)		(860	)
Net Property, Plant and Equipment		2,064			1,947
TOTAL ASSETS	$	2,826		$	2,689

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

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DELMARVA POWER & LIGHT COMPANY

BALANCE SHEETS

(Unaudited)

	September 30, 2010		December 31, 2009
	(millions of dollars, except shares)
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Short-term debt	$	108	$	105
Current portion of long-term debt		35		31
Accounts payable and accrued liabilities		74		106
Accounts payable due to associated companies		30		14
Taxes accrued		6		3
Interest accrued		13		6
Derivative liabilities		19		15
Other		66		64
Total Current Liabilities		351		344
DEFERRED CREDITS
Regulatory liabilities		310		290
Deferred income taxes, net		541		489
Investment tax credits		7		7
Other postretirement benefit obligation		29		23
Above-market purchased energy contracts and other electric restructuring liabilities		14		17
Liabilities and accrued interest related to uncertain tax positions		21		20
Derivative liabilities		13		13
Other		27		23
Total Deferred Credits		962		882
LONG-TERM LIABILITIES
Long-term debt		699		655
COMMITMENTS AND CONTINGENCIES (NOTE 12)
EQUITY
Common stock, $2.25 par value, 1,000 shares authorized, 1,000 shares outstanding		—		—
Premium on stock and other capital contributions		336		336
Retained earnings		478		472
Total Equity		814		808
TOTAL LIABILITIES AND EQUITY	$	2,826	$	2,689

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

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DELMARVA POWER & LIGHT COMPANY

STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
	2010			2009
	(millions of dollars)
OPERATING ACTIVITIES
Net income	$	29		$	40
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		62			56
Deferred income taxes		53			50
Changes in:
Accounts receivable		3			31
Inventories		(2	)		6
Regulatory assets and liabilities, net		(8	)		38
Accounts payable and accrued liabilities		(3	)		(38	)
Pension contributions		—			(10	)
Taxes accrued		(22	)		(57	)
Other assets and liabilities		33			15
Net Cash From Operating Activities		145			131
INVESTING ACTIVITIES
Investment in property, plant and equipment		(191	)		(125	)
Net other investing activities		3			1
Net Cash Used By Investing Activities		(188	)		(124	)
FINANCING ACTIVITIES
Dividends paid to Parent		(23	)		(28	)
Capital contribution from Parent		—			32
Issuances of long-term debt		78			—
Reacquisition of long-term debt		(31	)		—
Issuances (repayments) of short-term debt, net		3			(141	)
Net other financing activities		(5	)		(2	)
Net Cash From (Used By) Financing Activities		22			(139	)
Net Decrease in Cash and Cash Equivalents		(21	)		(132	)
Cash and Cash Equivalents at Beginning of Period		26			138
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	5		$	6
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash (received) paid for income taxes (includes payments (from) to PHI for Federal income taxes)	$	(5	)	$	18

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

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NOTES TO FINANCIAL STATEMENTS

DELMARVA POWER & LIGHT COMPANY

(1) ORGANIZATION

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

(2) SIGNIFICANT ACCOUNTING POLICIES

Financial Statement Presentation

DPL’s unaudited financial statements are prepared in conformity with accounting principles generally accepted in the United States of America (GAAP). Pursuant to the rules and regulations of the Securities and Exchange Commission, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been omitted. Therefore, these financial statements should be read along with the annual financial statements included in DPL’s Annual Report on Form 10-K for the year ended December 31, 2009. In the opinion of DPL’s management, the financial statements contain all adjustments (which all are of a normal recurring nature) necessary to present fairly DPL’s financial condition as of September 30, 2010, in accordance with GAAP. The year-end December 31, 2009 balance sheet was derived from audited financial statements, but does not include all disclosures required by GAAP. Interim results for the three and nine months ended September 30, 2010 may not be indicative of results that will be realized for the full year ending December 31, 2010 since the sales of electric energy are seasonal.

Use of Estimates

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

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

Network Service Transmission Rates

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

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Consolidation of Variable Interest Entities – DPL Renewable Energy Transactions

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

One of the land-based wind facilities became operational and went into service in December 2009. DPL is obligated to purchase energy and RECs from this facility through 2024 in amounts generated and delivered not to exceed 50.25 megawatts at rates that are primarily fixed. DPL’s purchases under this PPA totaled $2 million for the three months ended September 30, 2010 and $8 million for the nine months ended September 30, 2010. Payments under the other wind agreements, which have terms ranging from 20 to 25 years, are currently expected to start in the fourth quarter of 2010 for the other two land-based contracts and 2016 for the offshore contract, if the projects are ultimately completed and become operational. When they become operational, DPL is obligated to purchase energy and RECs in amounts generated and delivered by the sellers at rates that are primarily fixed under these agreements. Under one of the agreements, DPL is also obligated to purchase the capacity associated with the facility at rates that are generally fixed. The inability of the offshore wind facility developer to obtain all necessary permits and financing commitments could result in setbacks in the construction schedules and the operational start dates of the offshore wind facility. If the wind facilities are not operational by specified dates, DPL has the right to terminate the PPAs. The term of the agreement with the solar facility is 20 years and DPL is obligated to purchase RECs in an amount up to seventy percent of the energy output from the solar facility at a fixed price once the facility is operational, which is expected to be by the end of 2011.

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

Goodwill

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

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in DPL’s gross revenues were $4 million for the three months ended September 30, 2010 and 2009, and $13 million for the nine months ended September 30, 2010 and 2009.

Reclassifications and Adjustments

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

During the second and third quarters of 2009, DPL recorded adjustments to correct certain income tax errors related to prior periods. These adjustments resulted in an increase in income tax expense of $1 million for the three months ended September 30, 2009.

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During the third quarter of 2009, DPL recorded an adjustment to correct certain errors in the Bill Stabilization Adjustment (BSA) calculation. The adjustment resulted in a decrease in revenue of $1 million for the three and nine months ended September 30, 2009.

(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Transfers and Servicing (ASC 860)

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

The guidance was effective for transfers of financial assets occurring in fiscal periods beginning on January 1, 2010 for DPL. As of January 1, 2010, DPL has adopted the provisions of this guidance and determined that the guidance did not have a material impact on its overall financial condition, results of operations, or cash flows.

Consolidation of Variable Interest Entities (ASC 810)

The FASB issued new consolidation guidance regarding variable interest entities effective January 1, 2010 that eliminated the quantitative analysis requirement and added new qualitative factors to determine whether consolidation is required. The new qualitative factors are applied on a quarterly basis to interests in variable interest entities. Under the new guidance, the holder of the interest with the power to direct the most significant activities of the entity and the right to receive benefits or absorb losses significant to the entity would consolidate. The new guidance retained the provision that allows entities created before

December 31, 2003 to be scoped out from a consolidation assessment if exhaustive efforts are taken and there is insufficient information to determine whether there is a relationship with a variable interest entity or the primary beneficiary of a variable interest entity. DPL has adopted the provisions of the new FASB guidance on consolidation of variable interest entities, and it did not have a material impact on its overall financial condition, results of operations, or cash flows.

Fair Value Measurements and Disclosures (ASC 820)

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

Subsequent Events (ASC 855)

The FASB issued new guidance which eliminated the requirement for DPL to disclose the date through which it has evaluated subsequent events beginning with its March 31, 2010 financial statements.

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(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Fair Value Measurements and Disclosures (ASC 820)

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

(5) SEGMENT INFORMATION

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

(6) GOODWILL

DPL’s goodwill balance of $8 million was unchanged during the three and nine month periods ending September 30, 2010. All of DPL’s goodwill was generated by its acquisition of Conowingo Power Company in 1995.

DPL’s annual impairment tests as of July 1, 2009 and November 1, 2009 indicated that goodwill was not impaired. As of September 30, 2010, after review of its significant assumptions in the goodwill impairment analysis, DPL concluded that there were no events requiring it to perform an interim goodwill impairment test. DPL will continue to closely monitor for indicators of goodwill impairment.

(7) PENSION AND OTHER POSTRETIREMENT BENEFITS

DPL accounts for its participation in the Pepco Holdings benefit plans as participation in a multi-employer plan. PHI’s pension and other postretirement net periodic benefit cost for the three months ended September 30, 2010 and 2009, before intercompany allocations from the PHI Service Company, of $26 million and $36 million, respectively, included $7 million and $6 million, respectively, for DPL’s allocated share. PHI’s pension and other postretirement net periodic benefit cost for the nine months ended September 30, 2010 and 2009, before intercompany allocations from the PHI Service Company, of $86 million and $111 million, respectively, included $21 million and $19 million, respectively, for DPL’s allocated share.

(8) DEBT

Credit Facilities

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

At September 30, 2010 and December 31, 2009, the amount of cash plus borrowing capacity under the $1.5 billion credit facility available to meet the liquidity needs of PHI’s utility subsidiaries was $494 million and $582 million, respectively.

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Other Financing Activities

On July 1, 2010, DPL purchased $31 million of unsecured tax-exempt bonds issued for the benefit of DPL by The Delaware Economic Development Authority that in accordance with the terms of the bonds were subject to mandatory tender. DPL intends to remarket these bonds during the fourth quarter of 2010.

(9) INCOME TAXES

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

	Three Months  Ended September 30,						Nine Months  Ended September 30,
	2010			2009			2010			2009
Federal statutory rate		35.0	%		35.0	%		35.0	%		35.0	%
Increases (decreases) resulting from:
Depreciation		3.8			11.4			2.7			3.4
State income taxes, net of federal effect		5.0			5.7			5.2			5.5
State tax benefit related to prior years’ asset dispositions		—			(187.1	)		—			(27.9	)
Tax credits		(1.3	)		(2.9	)		(1.2	)		(1.3	)
Change in estimates and interest related to uncertain and effectively settled tax positions		(0.6	)		21.4			2.1			(1.9	)
Adjustment to prior year taxes		1.9			22.9			0.6			3.4
Other, net		—			(6.4	)		(0.2	)		(1.3	)
Effective Income Tax Rate		43.8	%		(100.0	)%		44.2	%		14.9	%

DPL’s effective tax rates for the three months ended September 30, 2010 and 2009 were 43.8% and (100.0)%, respectively. The increase in the rate primarily resulted from the filing of amended returns to recover state tax benefits related to prior year asset dispositions recorded in 2009. This increase is partially offset by the changes in estimates and interest related to uncertain and effectively settled tax positions and an adjustment to prior year taxes.

DPL’s effective tax rates for the nine months ended September 30, 2010 and 2009 were 44.2% and 14.9%, respectively. The increase in the rate resulted from the change in estimates and interest related to uncertain and effectively settled tax positions, primarily related to the $2 million reversal of accrued interest income on state income tax positions in 2010 that DPL no longer believes is more likely than not to be realized and the tax benefits related to the filing of the amended state income tax returns recorded in 2009.

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

(10) DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

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

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

	As of September 30, 2010
Balance Sheet Caption	Derivatives Designated as Hedging Instruments			Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting		Net Derivative Instruments
	(millions of dollars)
Derivative Assets (current assets)	$	—		$	—		$	—		$	—	$	—
Derivative Assets (non-current assets)		—			—			—			—		—
Total Derivative Assets		—			—			—			—		—
Derivative Liabilities (current liabilities)		(9	)		(19	)		(28	)		9		(19	)
Derivative Liabilities (non-current liabilities)		—			(13	)		(13	)		—		(13	)
Total Derivative Liabilities		(9	)		(32	)		(41	)		9		(32	)
Net Derivative (Liability) Asset	$	(9	)	$	(32	)	$	(41	)	$	9	$	(32	)

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

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

	September 30, 2010		December 31, 2009
	(millions of dollars)
Cash collateral pledged to counterparties with the right to reclaim	$	9	$	11

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As of September 30, 2010 and December 31, 2009, all DPL cash collateral pledged or received related to derivatives accounted for at fair value was entitled to offset under master netting arrangements.

Derivatives Designated as Hedging Instruments

Cash Flow Hedges

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

	Three Months  Ended September 30,						Nine Months  Ended September 30,
	2010			2009			2010			2009
	(millions of dollars)
Net Gain Deferred as a Regulatory Asset or Liability	$	1		$	8		$	1		$	19
Net Loss Reclassified from Regulatory Asset or Liability to Purchased Energy or Gas Purchased		(4	)		(7	)		(9	)		(33	)

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

	Quantities
Commodity	September 30, 2010		December 31, 2009
Forecasted Purchases Hedges
Natural Gas (One Million British Thermal Units (MMBtu))		2,670,000		5,695,000

Other Derivative Activity

DPL holds certain derivatives that do not qualify as hedges. Under FASB guidance on derivatives and hedging, these derivatives are recorded at fair value on the balance sheet with the gain or loss recorded in income. In accordance with FASB guidance on regulatory operations, offsetting regulatory assets or regulatory liabilities are recorded on the balance sheet and the recognition of the gain or recovery of the loss is deferred. For the three and nine months ended September 30, 2010 and 2009 the amount of the derivative gain (loss) recognized in the statements of income is provided in the table below by line item:

	Three Months  Ended September 30,						Nine Months  Ended September 30,
	2010			2009			2010			2009
	(millions of dollars)
Net Gain (Loss) Deferred as a Regulatory Asset or Liability	$	(4	)	$	2		$	(3	)	$	(8	)
Net Loss Reclassified from Regulatory Asset or Liability to Purchased Energy or Gas Purchased		(5	)		(1	)		(18	)		(6	)

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

	September 30, 2010				December 31, 2009
Commodity	Quantity		Net Position		Quantity		Net Position
Natural Gas (MMBtu)		9,484,375		Long		10,442,546		Long

Contingent Credit Risk Features

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

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

The gross fair value of DPL’s derivative liabilities, excluding the impact of offsetting transactions or collateral under master netting agreements, with credit-risk-related contingent features on September 30, 2010 and December 31, 2009, was $31 million and $28 million, respectively. As of those dates, DPL had posted cash collateral of zero and less than one million dollars, respectively, in the normal course of business against the gross derivative liability resulting in a net liability of $31 million and $28 million, respectively, before giving effect to offsetting transactions that are encompassed within master netting agreements that would reduce this amount. DPL’s net settlement amount in the event of a downgrade of DPL below “investment grade” as of September 30, 2010 and December 31, 2009, would have been approximately $27 million and $24 million respectively, after taking into account the master netting agreements.

DPL’s primary source for posting cash collateral or letters of credit are PHI’s credit facilities. At September 30, 2010 and December 31, 2009, the aggregate amount of cash plus borrowing capacity under PHI credit facilities available to meet the liquidity needs of PHI’s utility subsidiaries was $494 million and $582 million, respectively.

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(11) FAIR VALUE DISCLOSURES

Fair Value of Assets and Liabilities Excluding Debt

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

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

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

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

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

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

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

The following tables set forth, by level within the fair value hierarchy, DPL’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2010 and December 31, 2009. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. DPL’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Fair Value Measurements at September 30, 2010
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Executive deferred compensation plan assets
Money Market Funds	$	2	$	2	$	—	$	—
Life Insurance Contracts		1		—		—		1
	$	3	$	2	$	—	$	1
LIABILITIES
Derivative instruments (a)
Natural Gas (b)	$	41	$	9	$	—	$	32
	$	41	$	9	$	—	$	32

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

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

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

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

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

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

	Nine Months Ended September 30, 2010
	Natural Gas			Life Insurance Contracts
	(millions of dollars)
Beginning balance as of January 1, 2010	$	(29	)	$	1
Total gains or (losses) (realized and unrealized)
Included in income		—			—
Included in accumulated other comprehensive loss		—			—
Included in regulatory liabilities		(18	)		—
Purchases and issuances		—			—
Settlements		15			—
Transfers in (out) of Level 3		—			—
Ending balance as of September 30, 2010	$	(32	)	$	1
	Nine Months Ended September 30, 2009
	Natural Gas			Life Insurance Contracts
	(millions of dollars)
Beginning balance as of January 1, 2009	$	(24	)	$	1
Total gains or (losses) (realized and unrealized)
Included in income		—			—
Included in accumulated other comprehensive loss		—			—
Included in regulatory liabilities		(13	)		—
Purchases and issuances		—			—
Settlements		9			—
Transfers in (out) of Level 3		—			—
Ending balance as of September 30, 2009	$	(28	)	$	1
Gains or (losses) (realized and unrealized) included in income for the periods below are reported in Other Operation and Maintenance Expense as follows:
	Nine Months Ended September 30, 2010			Nine Months Ended September 30, 2009
	(millions of dollars)
Total gains included in income for the period	$	—		$	—
Change in unrealized gains relating to assets still held at reporting date	$	—		$	—

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Fair Value of Debt Instruments

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

	September 30, 2010				December 31, 2009
	(millions of dollars)
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	734	$	805	$	686	$	733

The methods and assumptions described below were used to estimate, as of September 30, 2010 and December 31, 2009, the fair value of non-derivative financial instruments shown above for which it is practicable to estimate a value.

The fair value of long-term debt issued by DPL was based on actual trade prices as of September 30, 2010 and December 31, 2009, or bid prices obtained from brokers if actual trade prices were not available.

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

(12) COMMITMENTS AND CONTINGENCIES

Regulatory and Other Matters

Rate Proceedings

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

• A BSA has been approved and implemented for DPL electric service in Maryland.

• A modified fixed variable rate design (MFVRD) has been approved in concept for DPL electric service in Delaware and a settlement among the parties to the ongoing base rate proceeding (as described below) has been submitted to the DPSC, which provides for the implementation of the MFVRD after the conclusion of the proceeding.

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

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

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provides for a fixed customer charge (i.e., not tied to the customer’s volumetric consumption) to recover the utility’s fixed costs, plus a reasonable rate of return. Although different from the BSA, PHI views the MFVRD as an appropriate distribution revenue decoupling mechanism.

Delaware

In August 2009, DPL submitted to the DPSC its 2009 Gas Cost Rate (GCR) filing, which permits DPL to recover gas procurement costs through customer rates. The requested 10.2% decrease in the level of GCR, became effective on a temporary basis on November 1, 2009, subject to refund and pending final DPSC approval. On August 17, 2010, the DPSC approved the rates as filed.

On August 31, 2010, DPL submitted to the DPSC its 2010 GCR filing, which proposed a two-year amortization of under-recovered gas costs in the 2010 filing. In October 2010, the DPSC issued an order placing those 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 essentially flat (an increase of 0.1% in the level of GCR). If the DPSC does not accept DPL’s proposal, the full GCR would result in an increase of 6.9% in the level of GCR.

In September 2009, DPL submitted an application with the DPSC to increase its electric distribution base rates. The filing, as revised in March 2010, sought approval of an annual rate increase of approximately $26.2 million, assuming approval of the implementation of the MFVRD, based on a requested return on equity (ROE) of 10.75%. As permitted by Delaware law, DPL placed an increase of approximately $2.5 million annually into effect on a temporary basis in November 2009, subject to refund and pending final DPSC approval of the entirety of the requested increase. As permitted by Delaware law, DPL placed approximately $23.7 million of the remaining requested increase into effect on April 19, 2010, subject to refund and pending final DPSC approval. On April 16, 2010, all of the parties to the base rate proceeding, including DPL, the DPSC staff, the Division of the Public Advocate, the Delaware Department of Natural Resources and Environmental Control, and the Delaware Energy Users Group, which represents large industrial consumers of electricity, entered into a settlement agreement regarding implementation of the MFVRD. The settlement agreement (as modified non-materially on August 27, 2010) provides for implementation of the MFVRD after the conclusion of the current base rate proceeding. Hearings on the unresolved issues in the case were concluded in late May 2010. In June 2010, DPL lowered the requested annual rate increase to approximately $24.2 million. On October 1, 2010, the Hearing Examiner issued a report to the DPSC, recommending an increase of approximately $6.3 million, based on an ROE of 8.5% with the MFVRD (or approximately $9.7 million, based on an ROE of 9.5%, without the MFVRD), and recommending approval of the settlement agreement providing for implementation of the MFVRD. On October 25, 2010, DPL filed a number of objections to the Hearing Examiner’s report. The DPSC is expected to consider the case at its meeting on November 10, 2010, during which DPL will have an additional opportunity to challenge each of the recommendations in the report to which it objects.

On July 2, 2010, DPL submitted an application with the DPSC to increase its natural gas distribution base rates. As subsequently amended on September 10, 2010 (to replace test year data for the twelve months ended June 2010 with the actual data) and on October 11, 2010 (based on an update to DPL’s Gas advanced metering infrastructure implementation schedule), the filing seeks approval of an annual rate increase of approximately $10.2 million, assuming the implementation of the MFVRD, based on a requested ROE of 11.00%. DPL placed an annual increase of approximately $2.5 million into effect on a temporary basis on August 31, 2010, subject to refund and pending final DPSC approval of the entirety of the requested increase. A procedural schedule has been set which provides for a hearing in January 2011 and a DPSC decision in April 2011. Previously, in June 2009, DPL filed an application requesting approval for the implementation of the MFVRD for gas distribution rates. The parties to the MFVRD proceeding have been working toward a settlement agreement that would be submitted to the DPSC. DPL anticipates that the MFVRD proceeding will be merged with the natural gas base rate proceeding discussed above.

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Environmental Litigation

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

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

Indian River Oil Release

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

(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 September 30, 2010 and 2009 were approximately $38 million and $33 million, respectively. PHI Service Company costs directly charged or allocated to DPL for the nine months ended September 30, 2010 and 2009 were approximately $103 million and $95 million, respectively.

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

	For the Three  Months Ended September 30,						For the Nine  Months Ended September 30,
Income (Expenses)	2010			2009			2010			2009
	(millions of dollars)
Purchased power under Default Electricity Supply contracts with Conectiv Energy Supply, Inc. (a)	$	(37	)	$	(14	)	$	(76	)	$	(73	)
Intercompany lease transactions (b)		1			2			5			6

(a) Included in purchased energy expense.

(b) Included in electric revenue.

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

Asset (Liability)	September 30, 2010			December 31, 2009
	(millions of dollars)
(Payable to) Receivable from Related Party (current) (a)
PHI Service Company	$	(19	)	$	22
PHI Parent Company		2			(27	)
Conectiv Energy Supply, Inc.		(11	)		(7	)
Pepco Energy Services, Inc. and its subsidiaries (Pepco Energy Services) (b)		(2	)		(3	)
Other		—			1
Total	$	(30	)	$	(14	)

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

(b) DPL bills customers on behalf of Pepco Energy Services where customers have selected Pepco Energy Services as their alternative 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 is repositioning itself as a regulated transmission and distribution company. In connection with this repositioning, PHI commenced a comprehensive organizational review in the second quarter of 2010 to identify opportunities to streamline the organization and to achieve certain reductions in corporate overhead costs that are allocated to its operating segments. This review has resulted in the adoption of a phased restructuring plan (the plan). PHI began implementing the initial phase of the plan during the third quarter, identifying 165 positions that will be eliminated during the fourth quarter of 2010. The second phase of the plan has also commenced, which will focus on identifying additional cost reduction opportunities through process improvements and operational efficiencies. PHI currently estimates that the implementation of the plan will result in an annual reduction of at least $20 million in corporate overhead costs.

In connection with the restructuring plan, DPL recorded a pre-tax restructuring charge of $4 million for the three and nine months ended September 30, 2010 related to its allocation of severance and health and welfare benefits for anticipated terminations of corporate services employees at PHI. The severance and health and welfare benefits were estimated based on the years of service and compensation levels of the employees that could be associated with the 165 eliminated positions at PHI. The final amount of the restructuring charge for severance and health and welfare benefits may vary from the estimate depending on the specific employees severed as part of the plan. The restructuring charge has been reflected as a separate line item in the Statements of Income.

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Reconciliations of the beginning and ending balances of DPL’s accrued restructuring charges for the three months ended September 30, 2010 are as follows:

	Three Months Ended September 30, 2010
	(millions of dollars)
Beginning balance as of July 1, 2010	$	—
Restructuring charge		4
Cash payments		—
Ending balance as of September 30, 2010	$	4

Under FASB guidance on exit or disposal cost obligations (ASC 420), certain severance costs are being recognized over the remaining service periods for certain employees to be terminated under the restructuring plan. Generally, the remaining service periods are expected to end by December 31, 2010 and, accordingly, DPL expects to record an additional $1 million of employee severance and health and welfare benefits in the fourth quarter of 2010. DPL may incur further severance costs if additional positions are identified for elimination. DPL may incur other restructuring charges for employee termination benefits and other cost reduction efforts as part of the implementation of the plan.

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CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months  Ended September 30,						Nine Months  Ended September 30,
	2010			2009			2010			2009
	(millions of dollars)
Operating Revenue	$	518		$	441		$	1,150		$	1,072
Operating Expenses
Purchased energy		341			334			819			850
Other operation and maintenance		54			50			151			145
Restructuring charge		3			—			3			—
Depreciation and amortization		32			29			81			78
Other taxes		8			6			20			16
Deferred electric service costs		13			(32	)		(69	)		(116	)
Total Operating Expenses		451			387			1,005			973
Operating Income		67			54			145			99
Other Income (Expenses)
Interest expense		(17	)		(16	)		(49	)		(50	)
Other income		—			—			1			1
Total Other Expenses		(17	)		(16	)		(48	)		(49	)
Income Before Income Tax Expense		50			38			97			50
Income Tax Expense		20			15			43			17
Net Income		30			23			54			33
Retained Earnings at Beginning of Period		167			152			143			166
Dividends Paid to Parent		—			—			—			(24	)
Retained Earnings at End of Period	$	197			175		$	197		$	175

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

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CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30, 2010			December 31, 2009
	(millions of dollars)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	8		$	7
Restricted cash equivalents		14			10
Accounts receivable, less allowance for uncollectible accounts of $12 million and $7 million, respectively		251			176
Inventories		18			15
Prepayments of income taxes		28			38
Assets and accrued interest related to uncertain tax positions		19			—
Prepaid expenses and other		29			12
Total Current Assets		367			258
INVESTMENTS AND OTHER ASSETS
Regulatory assets		675			712
Prepaid pension expense		54			63
Income taxes receivable		60			76
Restricted cash equivalents		2			4
Assets and accrued interest related to uncertain tax positions		42			57
Other		14			9
Total Investments and Other Assets		847			921
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		2,416			2,328
Accumulated depreciation		(724	)		(699	)
Net Property, Plant and Equipment		1,692			1,629
TOTAL ASSETS	$	2,906		$	2,808

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

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CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30, 2010		December 31, 2009
	(millions of dollars, except shares)
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Short-term debt	$	146	$	83
Current portion of long-term debt		35		35
Accounts payable and accrued liabilities		120		120
Accounts payable due to associated companies		32		58
Taxes accrued		25		5
Interest accrued		17		13
Other		37		42
Total Current Liabilities		412		356
DEFERRED CREDITS
Regulatory liabilities		103		178
Deferred income taxes, net		623		604
Investment tax credits		8		9
Other postretirement benefit obligation		29		25
Other		11		11
Total Deferred Credits		774		827
LONG-TERM LIABILITIES
Long-term debt		632		609
Transition Bonds issued by ACE Funding		343		368
Total Long-Term Liabilities		975		977
COMMITMENTS AND CONTINGENCIES (NOTE 10)
REDEEMABLE SERIAL PREFERRED STOCK		6		6
EQUITY
Common stock, $3.00 par value, 25,000,000 shares authorized, 8,546,017 shares outstanding		26		26
Premium on stock and other capital contributions		516		473
Retained earnings		197		143
Total Equity		739		642
TOTAL LIABILITIES AND EQUITY	$	2,906	$	2,808

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

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CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
	2010			2009
	(millions of dollars)
OPERATING ACTIVITIES
Net income	$	54		$	33
Adjustments to reconcile net income to net cash from (used by) operating activities:
Depreciation and amortization		81			78
Deferred income taxes		15			46
Changes in:
Accounts receivable		(75	)		(5	)
Regulatory assets and liabilities, net		(70	)		(139	)
Accounts payable and accrued liabilities		(25	)		(9	)
Pension contributions		—			(60	)
Prepaid New Jersey sales and excise tax		(45	)		(44	)
Taxes accrued		64			3
Other assets and liabilities		11			15
Net Cash From (Used By) Operating Activities		10			(82	)
INVESTING ACTIVITIES
Investment in property, plant and equipment		(110	)		(98	)
Net other investing activities		(3	)		—
Net Cash Used By Investing Activities		(113	)		(98	)
FINANCING ACTIVITIES
Dividends paid to Parent		—			(24	)
Capital contribution from Parent		43			129
Issuances of long-term debt		23			—
Reacquisition of long-term debt		(25	)		(23	)
Issuances of short-term debt, net		63			40
Net other financing activities		—			(2	)
Net Cash From Financing Activities		104			120
Net Increase (Decrease) in Cash and Cash Equivalents		1			(60	)
Cash and Cash Equivalents at Beginning of Period		7			65
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	8		$	5
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash received for income taxes (includes payments from PHI for Federal income taxes)	$	2		$	16

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ATLANTIC CITY ELECTRIC COMPANY

(1) ORGANIZATION

Atlantic City Electric Company (ACE) is engaged in the transmission and distribution of electricity in southern New Jersey. ACE also provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its service territory who do not elect to purchase electricity from a competitive 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, 2009. In the opinion of ACE’s management, the consolidated financial statements contain all adjustments (which all are of a normal recurring nature) necessary to present fairly ACE’s financial condition as of September 30, 2010, in accordance with GAAP. The year-end December 31, 2009 balance sheet was derived from audited financial statements, but does not include all disclosures required by GAAP. Interim results for the three and nine months ended September 30, 2010 may not be indicative of results that will be realized for the full year ending December 31, 2010 since the sales of electric energy are seasonal.

Use of Estimates

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

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

Network Service Transmission Rates

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

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Consolidation of Variable Interest Entities

ACE Power Purchase Agreements (PPAs)

ACE has PPAs with a number of entities, including three contracts between unaffiliated non-utility generators (NUGs). Due to a variable element in the pricing structure of the PPAs, ACE potentially assumes the variability in the operations of the generating facilities related to the NUGs and, therefore, has a variable interest in the entities. Despite exhaustive efforts to obtain information from these entities during the three months ended September 30, 2010, PHI was unable to obtain sufficient information to conduct the analysis required under Financial Accounting Standards Board (FASB) guidance to determine whether these three entities were variable interest entities or if ACE was the primary beneficiary. As a result, ACE has applied the scope exemption from the guidance for enterprises that have conducted exhaustive efforts to obtain the necessary information, but have not been able to obtain such information.

Net purchase activities with the NUGs for the three months ended September 30, 2010 and 2009 were approximately $82 million and $70 million, respectively, of which approximately $74 million and $66 million, respectively, consisted of power purchases under the PPAs. Net purchase activities with the NUGs for the nine months ended September 30, 2010 and 2009 were approximately $222 million and $214 million, respectively, of which approximately $203 million and $197 million, respectively, consisted of power purchases under the PPAs. The power purchase costs are recoverable from ACE’s customers through regulated rates.

ACE Transition Funding, LLC

ACE Transition Funding, LLC (ACE Funding) was established in 2001 by ACE solely for the purpose of securitizing authorized portions of ACE’s recoverable stranded costs through the issuance and sale of 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 in an amount sufficient to fund the principal and interest payments on the Transition Bonds and related taxes, expenses and fees (Bondable Transition Property). ACE collects the Transition Bond Charges from its customers on behalf of ACE Funding and the holders of the Transition Bonds. The assets of ACE Funding, including the Bondable Transition Property, and the Transition Bond Charges collected from ACE’s customers, are not available to creditors of ACE. The holders of the Transition Bonds have recourse only to the assets of ACE Funding. ACE owns 100 percent of the equity of ACE Funding and has consolidated ACE Funding in its financial statements. The amendment to the variable interest entity consolidation guidance effective January 1, 2010 resulted in ACE Funding meeting the definition of a variable interest entity. ACE continues to consolidate ACE Funding in its financial statements as ACE is the primary beneficiary of ACE Funding under the amended variable interest entity consolidation guidance.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in ACE’s gross revenues were $8 million and $6 million for the three months ended September 30, 2010 and 2009, respectively, and $18 million and $17 million for the nine months ended September 30, 2010 and 2009, respectively.

Reclassifications and Adjustments

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

During 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 nine months ended September 30, 2010.

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During the first and second quarters of 2009, ACE recorded adjustments to correct certain income tax errors related to prior periods. These adjustments resulted in a decrease in income tax expense of $1 million for the nine months ended September 30, 2009.

(3) NEWLY ADOPTED ACCOUNTING STANDARDS

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

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

The guidance was effective for transfers of financial assets occurring in fiscal periods beginning on January 1, 2010 for ACE. As of January 1, 2010, ACE has adopted the provisions of this guidance and determined that the guidance did not have a material impact on its overall financial condition, results of operations, or cash flows.

Consolidation of Variable Interest Entities (ASC 810)

The FASB issued new consolidation guidance regarding variable interest entities effective January 1, 2010 that eliminated the quantitative analysis requirement and added new qualitative factors to determine whether consolidation is required. The new qualitative factors are applied on a quarterly basis to interests in variable interest entities. Under the new guidance, the holder of the interest with the power to direct the most significant activities of the entity and the right to receive benefits or absorb losses significant to the entity would consolidate. The new guidance retained the provision that allows entities created before December 31, 2003 to be scoped out from a consolidation assessment if exhaustive efforts are taken and there is insufficient information to determine whether there is a relationship with a variable interest entity or the primary beneficiary of a variable interest entity. ACE has adopted the provisions of the new FASB guidance on consolidation of variable interest entities, and it did not have a material impact on its overall financial condition, results of operations, or cash flows.

Fair Value Measurements and Disclosures (ASC 820)

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

Subsequent Events (ASC 855)

The FASB issued new guidance which eliminated the requirement for ACE to disclose the date through which it has evaluated subsequent events beginning with its March 31, 2010 financial statements.

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(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Fair Value Measurements and Disclosures (ASC 820)

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

(5) SEGMENT INFORMATION

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

(6) PENSION AND OTHER POSTRETIREMENT BENEFITS

ACE accounts for its participation in the Pepco Holdings benefit plans as participation in a multi-employer plan. PHI’s pension and other postretirement net periodic benefit cost for the three months ended September 30, 2010 and 2009, before intercompany allocations from the PHI Service Company, of $26 million and $36 million, respectively, included $6 million and $5 million, respectively, for ACE’s allocated share. PHI’s pension and other postretirement net periodic benefit cost for the nine months ended September 30, 2010 and 2009, before intercompany allocations from the PHI Service Company, of $86 million and $111 million, respectively, included $17 million and $15 million, respectively, for ACE’s allocated share.

(7) DEBT

Credit Facilities

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

At September 30, 2010 and December 31, 2009, the amount of cash plus borrowing capacity under the $1.5 billion credit facility available to meet the liquidity needs of PHI’s utility subsidiaries was $494 million and $582 million, respectively.

Other Financing Activities

In July 2010, ACE Funding made principal payments of $5.5 million on Series 2002-1 Bonds, Class A-2, and $2.1 million on Series 2003-1 Bonds, Class A-2.

On August 30, 2010, ACE redeemed $1 million of 7.25% secured medium-term notes at maturity.

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(8) INCOME TAXES

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

	Three Months Ended  September 30,						Nine Months Ended  September 30,
	2010			2009			2010			2009
Federal statutory rate		35.0	%		35.0	%		35.0	%		35.0	%
Increases (decreases) resulting from:
State income taxes, net of federal effect		6.6			7.1			6.8			7.8
Change in estimates and interest related to uncertain and effectively settled tax positions		(1.2	)		(1.3	)		3.7			(4.4	)
Adjustment to prior year taxes		—			—			—			(2.0	)
Other, net		(0.4	)		(1.3	)		(1.2	)		(2.4	)
Consolidated Effective Income Tax Rate		40.0	%		39.5	%		44.3	%		34.0	%

ACE’s consolidated effective tax rates for the three months ended September 30, 2010 and 2009 were 40.0% and 39.5%, respectively. The increase in the rate resulted from changes in estimates and interest related to uncertain and effectively settled tax positions, partially offset by the impact of certain permanent state tax differences.

ACE’s consolidated effective tax rates for the nine months ended September 30, 2010 and 2009 were 44.3% and 34.0%, respectively. The increase in the rate resulted from the reversal of $6 million of accrued interest income on uncertain and effectively settled state income tax positions in 2010 and the $1 million non-recurring adjustment in 2009 to prior year taxes. This increase is partially offset by the impact of certain permanent state tax differences.

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

(9) FAIR VALUE DISCLOSURES

Fair Value of Assets and Liabilities Excluding Debt

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

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

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

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

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

The following tables set forth, by level within the fair value hierarchy, ACE’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2010 and December 31, 2009. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. ACE’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Fair Value Measurements at September 30, 2010
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Cash equivalents
Treasury Fund	$	17	$	17	$	—	$	—
	$	17	$	17	$	—	$	—
LIABILITIES
Executive deferred compensation plan liabilities
Life Insurance Contracts	$	1	$	—	$	1	$	—
	$	1	$	—	$	1	$	—

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

Fair Value of Debt Instruments

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

	September 30, 2010				December 31, 2009
			(millions of dollars)
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	632		$745	$	610	$	674
Transition Bonds issued by ACE Funding		378		432		402		427
Redeemable Serial Preferred Stock		6		5		6		4

The methods and assumptions described below were used to estimate, as of September 30, 2010 and December 31, 2009, the fair value of each class of non-derivative financial instruments shown above for which it is practicable to estimate a value.

The fair value of long-term debt issued by ACE was based on actual trade prices as of September 30, 2010 and December 31, 2009, or bid prices obtained from brokers if actual trade prices were not available. The fair values of Transition Bonds issued by ACE Funding, including amounts due within one year, were derived based on bid prices obtained from brokers if actual trade prices were not available or were based on discounted cash flows using current rates for similar issues with similar credit ratings, terms, and remaining maturities for issues with no market price available.

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

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

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(10) COMMITMENTS AND CONTINGENCIES

Regulatory and Other Matters

Rate Proceedings

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

Environmental Litigation

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

Franklin Slag Pile Site. On November 26, 2008, ACE received a general notice letter from the U.S. Environmental Protection Agency (EPA) concerning the Franklin Slag Pile site in Philadelphia, Pennsylvania, asserting that ACE is a potentially responsible party (PRP) that may have liability with respect to the site. If liable, ACE would be responsible for reimbursing EPA for clean-up costs incurred and to be incurred by the agency and for the costs of implementing an EPA-mandated remedy. The EPA’s claims are based on ACE’s sale of boiler slag from the B.L. England generating facility to MDC Industries, Inc. (MDC) during the period June 1978 to May 1983 (ACE owned B.L. England at that time and MDC formerly operated the Franklin Slag Pile site). EPA further claims that the boiler slag ACE sold to MDC contained copper and lead, which are hazardous substances under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA), and that the sales transactions may have constituted an arrangement for the disposal or treatment of hazardous substances at the site, which could be a basis for liability under CERCLA. The EPA’s letter also states that as of the date of the letter, EPA’s expenditures for response measures at the site exceed $6 million. EPA estimates approximately $6 million as the cost for future response measures it recommends. ACE understands that the EPA sent similar general notice letters to three other companies and various individuals.

ACE believes that the B.L. England boiler slag sold to MDC was a valuable material with various industrial applications and, therefore, the sale was not an arrangement for the disposal or treatment of any hazardous substances as would be necessary to constitute a basis for liability under CERCLA. ACE intends to contest any claims to the contrary made by the EPA. In a May 2009 decision arising under CERCLA, which did not involve ACE, the U.S. Supreme Court rejected an EPA argument that the sale of a useful product constituted

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an arrangement for disposal or treatment of hazardous substances. While this decision supports ACE’s position, at this time ACE cannot predict how EPA will proceed with respect to the Franklin Slag Pile site, or what portion, if any, of the Franklin Slag Pile site response costs EPA would seek to recover from ACE.

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

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

(11) RELATED PARTY TRANSACTIONS

PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries including ACE. The cost of these services is allocated in accordance with cost allocation methodologies set forth in the service agreement using a variety of factors, including the subsidiaries’ share of employees, operating expenses, assets, and other cost causal methods. These intercompany transactions are eliminated by PHI in consolidation and no profit results from these transactions at PHI. PHI Service Company costs directly charged or allocated to ACE for the three months ended September 30, 2010 and 2009 were approximately $28 million and $24 million, respectively. PHI Service Company costs directly charged or allocated to ACE for the nine months ended September 30, 2010 and 2009 were approximately $73 million and $75 million, respectively.

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

	For the Three  Months Ended September 30,						For the Nine  Months Ended September 30,
Income (Expense)	2010			2009			2010			2009
	(millions of dollars)
Purchased power under Default Electricity Supply contracts with Conectiv Energy Supply, Inc. (a)	$	(61	)	$	(61	)	$	(141	)	$	(148	)
Meter reading services provided by Millennium Account Services LLC (b)		(1	)		(1	)		(3	)		(3	)
Intercompany lease transactions (b)		—			—			(1	)		(1	)
Intercompany use revenue (c)		1			1			2			3

(a) Included in purchased energy expense.

(b) Included in other operation and maintenance expense.

(c) Included in operating revenue.

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

Asset (Liability)	September 30, 2010			December 31, 2009
	(millions of dollars)
Payable to Related Party (current) (a)
PHI Service Company	$	(14	)	$	(38	)
PHI Parent Company		—			(3	)
Conectiv Energy Supply, Inc.		(16	)		(15	)
Other		(2	)		(2	)
Total	$	(32	)	$	(58	)

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

(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 is repositioning itself as a regulated transmission and distribution company. In connection with this repositioning, PHI commenced a comprehensive organizational review in the second quarter of 2010 to identify opportunities to streamline the organization and to achieve certain reductions in corporate overhead costs that are allocated to its operating segments. This review has resulted in the adoption of a phased restructuring plan (the plan). PHI began implementing the initial phase of the plan during the third quarter, identifying 165 positions that will be eliminated during the fourth quarter of 2010. The second phase of the plan has also commenced, which will focus on identifying additional cost reduction opportunities through process improvements and operational efficiencies. PHI currently estimates that the implementation of the plan will result in an annual reduction of at least $20 million in corporate overhead costs.

In connection with the restructuring plan, ACE recorded a pre-tax restructuring charge of $3 million for the three and nine months ended September 30, 2010 related to its allocation of severance and health and welfare benefits for anticipated terminations of corporate services employees at PHI. The severance and health and welfare benefits were estimated based on the years of service and compensation levels of the employees that could be associated with the 165 eliminated positions at PHI. The final amount of the restructuring charge for severance and health and welfare benefits may vary from the estimate depending on the specific employees severed as part of the plan. The restructuring charge has been reflected as a separate line item in the Consolidated Statements of Income.

Reconciliations of the beginning and ending balances of ACE’s accrued restructuring charges for the three months ended September 30, 2010 are as follows:

	For the Three  Months Ended September 30, 2010
	(millions of dollars)
Beginning balance as of July 1, 2010	$	—
Restructuring charge		3
Cash payments		—
Ending balance as of September 30, 2010	$	3

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Under FASB guidance on exit or disposal cost obligations (ASC 420), certain severance costs are being recognized over the remaining services periods for certain employees to be terminated under the restructuring plan. Generally, the remaining service periods are expected to end by December 31, 2010 and, accordingly, ACE expects to record an additional $1 million of employee severance and health and welfare benefits in the fourth quarter of 2010. ACE may incur further severance costs if additional positions are identified for elimination. ACE may incur other restructuring charges for employee termination benefits and other cost reduction efforts as part of the implementation of the plan.

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Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The information required by this item is contained herein, as follows:

Registrants	Page No.
Pepco Holdings		109
Pepco		150
DPL		159
ACE		168

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

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
Percentage of Consolidated Operating Revenue
Power Delivery		77	%		70	%		73	%		68	%
Pepco Energy Services		22	%		30	%		27	%		32	%
Intercompany transactions and other		1	%		—			—			—
Percentage of Consolidated Operating Income
Power Delivery		86	%		82	%		80	%		78	%
Pepco Energy Services		7	%		11	%		12	%		14	%
Intercompany transactions and other		7	%		7	%		8	%		8	%
Percentage of Power Delivery Operating Revenue
Power Delivery Electric		98	%		98	%		96	%		95	%
Power Delivery Gas		2	%		2	%		4	%		5	%

Power Delivery

Power Delivery Electric consists primarily of the transmission, distribution and default supply of electricity, and Power Delivery Gas consists of the distribution and supply of natural gas. Power Delivery represents a single operating segment for financial reporting purposes.

The Power Delivery business is conducted by PHI’s three utility subsidiaries: Potomac Electric Power Company (Pepco), Delmarva Power & Light Company (DPL), and Atlantic City Electric Company (ACE). Each of these companies is a regulated public utility in the jurisdictions that comprise its service territory. Each company is responsible for the delivery of electricity and, in the case of DPL, natural gas in its service territory, for which it is paid tariff rates established by the applicable local public service commission. Each company also supplies electricity at regulated rates to retail customers in its service territory who do not elect to purchase electricity from a competitive energy supplier. The regulatory term for this supply service is Standard Offer Service in Delaware, the District of Columbia and Maryland, and Basic Generation Service in New Jersey. In this Form 10-Q, these supply service obligations are referred to generally as Default Electricity Supply.

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

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

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

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

Competitive Energy

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

PHI currently estimates that the sale of the wholesale power generation business to Calpine and the liquidation of the remaining Conectiv Energy assets and businesses will result in a loss through the completion of the liquidation for financial reporting purposes ranging from $110 million to $125 million, after tax. This range of loss includes estimates of (i) the loss on the Calpine sale, including transaction expenses, (ii) the additional income tax charges associated with the Calpine sale, (iii) expenses for employee severance and retention benefits, and (iv) accrued expenses for certain obligations associated with the Calpine sale, offset by (v) estimates of gains from the anticipated disposition of Conectiv Energy’s remaining assets and businesses not included in the Calpine sale, including load service supply contracts, the energy hedging portfolio, certain tolling agreements and other non-generation assets.

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The estimated after-tax proceeds from the sale of the wholesale power generation business to Calpine and the liquidation of the remaining Conectiv Energy assets and businesses, combined with the return of cash collateral posted under the contracts, are expected to total approximately $1.7 billion, with a related current income tax obligation approximating $217 million.

The business of the Pepco Energy Services segment has consisted primarily of (i) the retail supply of electricity and natural gas and (ii) providing energy savings performance contracting services principally to federal, state and local government customers, and designing, constructing and operating combined heat and power and central energy plants for customers (Energy Services). Pepco Energy Services also owns and operates two oil-fired generation facilities. In December 2009, PHI announced that it will wind down the retail energy supply component of the Pepco Energy Services business. Pepco Energy Services is implementing this wind down by not entering into any new supply contracts, while continuing to perform under its existing supply contracts through 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 September 30, 2010 and 2009 were $377 million and $568 million, respectively, while operating income for the same periods was $15 million and $21 million, respectively. Operating revenues related to the retail energy supply business for the nine months ended September 30, 2010 and 2009 were $1,275 million and $1,733 million, respectively, while operating income for the same periods was $45 million and $74 million, respectively. PHI anticipates that the decline in operating revenues and operating income will continue as the retail energy supply business winds down. In connection with the operation of the retail energy supply business, as of September 30, 2010, Pepco Energy Services provided letters of credit of $140 million and posted net cash collateral of $150 million. These collateral requirements, which are based on existing wholesale energy purchase and sale contracts and current market prices, will decrease as the contracts expire and the collateral is expected to be fully released over time by September 1, 2014. The Energy Services business will not be affected by the wind down of the retail energy supply business.

Other Non-regulated

Through its subsidiary Potomac Capital Investment Corporation, PHI maintains a portfolio of cross-border energy sale-leaseback transactions with a book value at September 30, 2010 of approximately $1.4 billion. This activity constitutes a third operating segment, which is designated as “Other Non-Regulated,” for financial reporting purposes. For a discussion of PHI’s cross-border leasing transactions, see Note (14), “Commitments and Contingencies—Regulatory and Other Matters – PHI’s Cross-Border Energy Lease Investments,” to the consolidated financial statements of PHI set forth in Part I, Item 1 of this Form 10-Q.

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Earnings Overview

PHI’s net income from continuing operations for the three months ended September 30, 2010 was $21 million, or $.09 per share, compared to $104 million, or $.47 per share, for the three months ended September 30, 2009.

Net income from continuing operations for the three months ended September 30, 2010, included the charges set forth below in the business segments noted, which are presented net of federal and state income taxes and are in millions of dollars:

Debt extinguishment costs including treasury lock hedge (Corporate and Other)	$	81
Restructuring charge (All segments)	$	8
Effects of Pepco divestiture-related claims (Power Delivery)	$	6

Excluding these items, net income from continuing operations would have been $116 million, or $.52 per share, for the three months ended September 30, 2010.

Net income from continuing operations for the three months ended September 30, 2009, included the credits set forth below in the Power Delivery segment, which are presented net of federal and state income taxes and are in millions of dollars:

Settlement of Pepco divestiture-related Mirant Corporation (Mirant) bankruptcy claims	$	16
Maryland income tax benefit, net of fees	$	11

Excluding these items, net income from continuing operations would have been $77 million, or $.35 per share, for the three months ended September 30, 2009.

PHI’s net loss from discontinued operations for the three months ended September 30, 2010 was $4 million, or $.01 per share, compared to net income of $20 million, or $.09 per share, for the three months ended September 30, 2009.

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

	2010			2009			Change
Power Delivery	$	76		$	94		$	(18	)
Pepco Energy Services		8			14			(6	)
Other Non-Regulated		9			7			2
Corporate and Other		(72	)		(11	)		(61	)
Net Income from Continuing Operations		21			104			(83	)
Discontinued Operations		(4	)		20			(24	)
Total PHI Net Income	$	17		$	124		$	(107	)

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Discussion of Operating Segment Net Income Variances:

Power Delivery’s $18 million decrease in earnings is primarily due to the following:

• $16 million decrease due to the 2009 earnings impact of the approval by the Maryland Public Service Commission (MPSC) of Pepco’s proposal for sharing the Maryland portion of the proceeds of the Mirant bankruptcy settlement remaining after the transfer of the power purchase agreement between Panda-Brandywine, L.P. and Pepco (the Panda PPA) to a third party.

• $15 million decrease primarily due to the 2009 earnings impact of a Maryland income tax benefit related to a change in tax reporting for the disposition of certain assets in prior years.

• $8 million decrease due to a restructuring charge.

• $6 million decrease due to an order by the District of Columbia Public Service Commission (DCPSC) associated with the effects of Pepco divestiture-related claims.

• $5 million decrease due to higher operating and maintenance expenses primarily resulting from July and August 2010 storm restoration activity.

The aggregate amount of these decreases was partially offset by:

• $19 million increase from higher distribution revenue consisting of:

• an $11 million increase due to higher distribution sales, primarily due to warmer weather and growth in the number of customers; and

• an $8 million increase due to distribution rate increases (Pepco in the District of Columbia effective November 2009 and March 2010; DPL in Maryland effective December 2009; DPL in Delaware effective April 2010; and ACE in New Jersey effective June 2010).

• $7 million increase from higher transmission revenue primarily attributable to higher rates effective June 1, 2010.

• $3 million increase associated with higher Default Electricity Supply margins for Pepco in the District of Columbia and Maryland.

Pepco Energy Services’ $6 million decrease in earnings is primarily due to the cost to repair a thermal services’ distribution system pipe leak, higher costs with operating a customer’s cogeneration plant, losses from sales of excess natural gas at low prices due to low demand, and the on-going winddown of the retail electricity supply business.

Corporate and Other’s $61 million decrease in earnings is primarily due to the unfavorable impact of debt extinguishment costs related to the purchase of outstanding debt with the proceeds from sale of the Conectiv Energy wholesale power generation business.

The $24 million decrease in earnings from discontinued operations was primarily due to the recognition of additional costs associated with the sale of the wholesale power generation business to Calpine Corporation, and unrealized losses on derivative instruments no longer qualifying for cash flow hedge accounting, partially offset by gains on sales of load service supply contracts.

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Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009

PHI’s net income from continuing operations for the nine months ended September 30, 2010 was $125 million, or $.56 per share, compared to $184 million, or $.84 per share, for the nine months ended September 30, 2009.

Net income from continuing operations for the nine months ended September 30, 2010, included the charges set forth below in the business segments noted, which are presented net of federal and state income taxes and are in millions of dollars:

Debt extinguishment costs including treasury lock hedge (Corporate and Other)	$	81
Restructuring charge (All segments)	$	8
Effects of Pepco divestiture-related claims (Power Delivery)	$	6

Excluding these items, net income from continuing operations would have been $220 million, or $.99 per share, for the nine months ended September 30, 2010.

Net income from continuing operations for the nine months ended September 30, 2009, included the credits set forth below in the Power Delivery segment, which are presented net of federal and state income taxes and are in millions of dollars:

Settlement of Pepco divestiture-related Mirant bankruptcy claims	$	24
Maryland income tax benefit, net of fees	$	11

Excluding these items, net income from continuing operations would have been $149 million, or $.68 per share, for the nine months ended September 30, 2009.

PHI’s net loss from discontinued operations for the nine months ended September 30, 2010 was $126 million, or $.56 per share, compared to net income of $10 million, or $.04 per share, for the nine months ended September 30, 2009.

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

	2010			2009			Change
Power Delivery	$	161		$	167		$	(6	)
Pepco Energy Services		31			32			(1	)
Other Non-Regulated		19			22			(3	)
Corporate and Other		(86	)		(37	)		(49	)
Net Income from Continuing Operations		125			184			(59	)
Discontinued Operations		(126	)		10			(136	)
Total PHI Net (Loss) Income	$	(1	)	$	194		$	(195	)

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Discussion of Operating Segment Net Income Variances:

Power Delivery’s $6 million decrease in earnings is primarily due to the following:

• $28 million decrease primarily due to the 2009 earnings impact of a Maryland income tax benefit related to a change in tax reporting for the disposition of certain assets in prior years and interest on uncertain and effectively settled tax positions in 2010.

• $24 million decrease due to the 2009 earnings impact of the approvals by the DCPSC and the MPSC of Pepco’s proposals for sharing the proceeds of the Mirant bankruptcy settlement remaining after the transfer of the Panda PPA to a third party.

• $9 million decrease due to higher operating and maintenance costs primarily resulting from February, July and August 2010 storm restoration activity; partially offset by lower pension expense.

• $8 million decrease due to a restructuring charge.

• $6 million decrease due to an order by the DCPSC associated with the effects of Pepco divestiture-related claims.

The aggregate of these decreases was partially offset by:

• $37 million increase from higher distribution revenue consisting of:

• a $17 million increase due to distribution rate increases (Pepco in the District of Columbia effective November 2009 and March 2010; DPL in Maryland effective December 2009; DPL in Delaware effective April 2010; and ACE in New Jersey effective June 2010); and

• a $20 million increase due to higher distribution sales, primarily due to growth in the number of customers and warmer weather.

• $16 million increase from higher transmission revenue primarily attributable to the accrual of true-ups to reflect costs incurred in the June 2009 through May 2010 service period that were included in the final determination of network service transmission rates effective June 1, 2010 through May 31, 2011, which include rate adjustments for such true-ups and the higher rates effective June 1, 2010.

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

Pepco Energy Services’ $1 million decrease in earnings is primarily due to the following:

• $17 million decrease due to lower retail electricity sales volumes due to the ongoing wind down of the retail electricity supply business; partially offset by gains on energy derivative contracts accounted for at fair value.

• $6 million decrease due to the cost to repair a thermal services’ distribution system pipe leak and higher costs with operating a customer’s cogeneration plant.

The aggregate amount of these decreases was partially offset by:

• $16 million increase due to higher electricity generation output that resulted from warmer than normal weather.

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• $5 million increase due to lower interest and other expenses, primarily associated with credit and collateral facilities for the retail energy supply business.

Corporate and Other’s $49 million decrease in earnings is primarily due to the unfavorable impact of debt extinguishment costs related to the purchase of outstanding debt with the proceeds from the sale of the Conectiv Energy wholesale power generation business; partially offset by the favorable impact of deferred state income tax benefits related to the April 1, 2010 corporate restructuring and effectively settled tax positions.

The $136 million decrease in earnings from discontinued operations was primarily due to the recognition of a write-down associated with the sale of the wholesale power generation business to Calpine Corporation and unrealized losses on derivative instruments no longer qualifying for cash flow hedge accounting, partially offset by gains on sales of load service supply contracts.

Consolidated Results of Operations

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

Continuing Operations

Operating Revenue

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

	2010			2009			Change
Power Delivery	$	1,600		$	1,428		$	172
Pepco Energy Services		457			611			(154	)
Other Non-Regulated		15			13			2
Corporate and Other		(5	)		(2	)		(3	)
Total Operating Revenue	$	2,067		$	2,050		$	17

Power Delivery Business

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

	2010		2009		Change
Regulated T&D Electric Revenue	$	567	$	482	$	85
Default Electricity Supply Revenue		979		901		78
Other Electric Revenue		19		17		2
Total Electric Operating Revenue		1,565		1,400		165
Regulated Gas Revenue		16		20		(4	)
Other Gas Revenue		19		8		11
Total Gas Operating Revenue		35		28		7
Total Power Delivery Operating Revenue	$	1,600	$	1,428	$	172

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

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

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

Regulated T&D Electric

Regulated T&D Electric Revenue	2010		2009		Change
Residential	$	231	$	190	$	41
Commercial and industrial		261		229		32
Other		75		63		12
Total Regulated T&D Electric Revenue	$	567	$	482	$	85

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

Regulated T&D Electric Sales (Gigawatt hours (GWh))	2010		2009		Change
Residential		5,871		4,997		874
Commercial and industrial		8,887		8,653		234
Other		58		59		(1	)
Total Regulated T&D Electric Sales		14,816		13,709		1,107

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Regulated T&D Electric Customers (in thousands)	2010		2009		Change
Residential		1,631		1,614		17
Commercial and industrial		198		197		1
Other		2		2		—
Total Regulated T&D Electric Customers		1,831		1,813		18

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 $85 million primarily due to:

• An increase of $30 million due to higher pass-through revenue (which is substantially offset by a corresponding increase in Other Taxes) primarily the result of rate increases in Montgomery County, Maryland utility taxes that are collected by Pepco on behalf of the county.

• An increase of $17 million due to higher sales in the District of Columbia, Delaware and New Jersey service territories as a result of warmer weather during the 2010 summer months as compared to 2009. Distribution revenue in Maryland is decoupled from consumption in the third quarters of both 2009 and 2010 and, therefore, the period-to-period comparison is not affected by weather. Distribution revenue in the District of Columbia is not decoupled from consumption in the third quarter of 2009 and, therefore, the period-to-period comparison is affected by weather.

• An increase of $15 million due to distribution rate increases (Pepco in the District of Columbia effective November 2009, March 2010 and July 2010; DPL in Maryland effective December 2009; DPL in Delaware effective April 2010; and ACE in New Jersey effective June 2010).

• An increase of $11 million in transmission revenue due to transmission rate increases in June 2010.

• An increase of $8 million due to higher non-weather related average customer usage.

• An increase of $5 million due to the implementation of the EmPower Maryland (demand side management program for Pepco and DPL) surcharge rate in March 2010 (which is substantially offset by a corresponding increase in Depreciation and Amortization).

• An increase of $3 million due to customer growth of 1% primarily in the residential class in 2010.

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Default Electricity Supply

Default Electricity Supply Revenue	2010		2009		Change
Residential	$	705	$	619	$	86
Commercial and industrial		214		247		(33	)
Other		60		35		25
Total Default Electricity Supply Revenue	$	979	$	901	$	78

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

Default Electricity Supply Sales (GWh)	2010		2009		Change
Residential		5,553		4,804		749
Commercial and industrial		1,988		2,144		(156	)
Other		20		23		(3	)
Total Default Electricity Supply Sales		7,561		6,971		590

Default Electricity Supply Customers (in thousands)	2010		2009		Change
Residential		1,554		1,563		(9	)
Commercial and industrial		152		159		(7	)
Other		2		2		—
Total Default Electricity Supply Customers		1,708		1,724		(16	)

Default Electricity Supply Revenue increased by $78 million primarily due to:

• An increase of $81 million due to higher sales as a result of warmer weather during the 2010 summer months as compared to 2009.

• An increase of $32 million due to higher non-weather related average customer usage.

• An increase of $23 million in wholesale energy and capacity revenues primarily due to higher market prices for the sale of electricity purchased from NUGs.

The aggregate amount of these increases was partially offset by:

• A decrease of $39 million due to lower sales, primarily as a result of commercial customer migration to competitive suppliers.

• A decrease of $17 million as a result of lower Default Electricity Supply rates.

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Regulated Gas

Regulated Gas Revenue	2010		2009		Change
Residential	$	9	$	11	$	(2	)
Commercial and industrial		6		7		(1	)
Transportation and other		1		2		(1	)
Total Regulated Gas Revenue	$	16	$	20	$	(4	)
Regulated Gas Sales (billion cubic feet)	2010		2009		Change
Residential		—		1		(1	)
Commercial and industrial		—		1		(1	)
Transportation and other		2		1		1
Total Regulated Gas Sales		2		3		(1	)
Regulated Gas Customers (in thousands)	2010		2009		Change
Residential		113		113		—
Commercial and industrial		10		9		1
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 decreased by $4 million primarily due to lower non-weather related average customer usage.

Other Gas Revenue

Other Gas Revenue increased by $11 million primarily due to higher revenue from off-system sales resulting from:

• An increase of $5 million due to higher demand from electric generators and gas marketers.

• An increase of $4 million due to higher market prices.

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Pepco Energy Services

Pepco Energy Services’ operating revenue decreased $154 million primarily due to:

• A decrease of $194 million due to lower retail electricity sales volume primarily attributable to the ongoing wind down of the retail energy supply business.

The decrease is partially offset by:

• An increase of $25 million due to higher electricity generation output due to warmer than normal weather.

• An increase of $10 million due to increased high voltage and energy services construction activities.

• An increase of $5 million due to higher retail gas supply load from customer acquisitions in 2009 prior to the commencement of the wind down of the business, partially offset by lower retail natural gas prices.

Operating Expenses

Fuel and Purchased Energy and Other Services Cost of Sales

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

	2010		2009			Change
Power Delivery	$	948	$	914		$	34
Pepco Energy Services		410		555			(145)
Corporate and Other		(1)		(2	)		1
Total	$	1,357	$	1,467		$	(110	)

Power Delivery Business

Power Delivery’s Fuel and Purchased Energy consists of the cost of electricity and gas purchased by its utility subsidiaries to fulfill their respective Default Electricity Supply and Regulated Gas obligations and, as such, is recoverable from customers in accordance with the terms of public service commission orders. It also includes the cost of gas purchased for off-system sales. Fuel and Purchased Energy expense increased by $34 million primarily due to:

• An increase of $80 million due to higher electricity sales as a result of warmer weather during the 2010 summer months as compared to 2009.

The increase was partially offset by:

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

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Pepco Energy Services

Pepco Energy Services’ Fuel and Purchased Energy and Other Services Cost of Sales decreased $145 million primarily due to:

• A decrease of $180 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.

The decrease is partially offset by:

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

• An increase of $9 million due to higher retail gas supply load from 2009 customer acquisitions partially offset by lower wholesale natural gas prices.

• An increase of $13 million due to increased high voltage and energy services construction activities.

Other Operation and Maintenance

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

	2010			2009			Change
Power Delivery	$	210		$	198		$	12
Pepco Energy Services		26			24			2
Corporate and Other		(8	)		(9	)		1
Total	$	228		$	213		$	15

Other Operation and Maintenance expense for Power Delivery increased by $12 million; however, excluding an increase of $6 million primarily related to bad debt and administrative expenses that are deferred and recoverable in Default Electricity Supply Revenue, Other Operation and Maintenance expense increased by $6 million. The $6 million increase was primarily due to:

• An increase of $14 million in emergency restoration costs primarily due to severe summer storms in 2010. A portion of the costs of the restoration work relates to services provided by outside contractors and other utilities that were not billed as of September 30, 2010, and accordingly have been estimated. These estimates are subject to adjustment when the actual billings are received in the fourth quarter of 2010. The actual billings may vary from the estimates of such billings.

• An increase of $2 million due to higher tree trimming costs and system costs related to the implementation of smart meters.

The aggregate amount of these increases was partially offset by:

• A decrease of $6 million primarily due to an adjustment for February 2010 severe winter storm costs incurred by Pepco that previously were charged to other operation and maintenance expense. The adjustment was recorded in accordance with a MPSC rate order issued in August 2010 allowing for the recovery of the costs.

• A decrease of $5 million in employee-related costs, primarily due to lower pension and other postretirement benefit expenses.

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Restructuring Charge

With the ongoing wind down of the retail energy supply business of Pepco Energy Services and the disposition of Conectiv Energy, PHI is repositioning itself as a regulated transmission and distribution company. In connection with this repositioning, PHI commenced a comprehensive organizational review in the second quarter of 2010 to identify opportunities to streamline the organization and to achieve certain reductions in corporate overhead costs that are allocated to its operating segments. This review has resulted in the adoption of a phased restructuring plan (the plan). PHI began implementing the initial phase of the plan during the third quarter, identifying 165 positions that will be eliminated during the fourth quarter of 2010. The second phase of the plan has also commenced, which will focus on identifying additional cost reduction opportunities through process improvements and operational efficiencies. PHI currently estimates that the implementation of the plan will result in an annual reduction of at least $20 million in corporate overhead costs.

Pursuant to the plan, PHI recorded a pre-tax restructuring charge of $14 million for the three months ended September 30, 2010, related to severance and health and welfare benefits to be provided to terminated employees.

Under Financial Accounting Standards Board (FASB) guidance on exit or disposal cost obligations (Accounting Standards Codification (ASC) 420), certain severance costs are being recognized over the remaining service periods for certain employees to be terminated under the restructuring plan. Generally, the remaining service periods are expected to end by December 31, 2010 and, accordingly, PHI expects to record an additional $4 million of employee severance and health and welfare benefits in the fourth quarter of 2010. PHI may incur further severance costs if additional positions are identified for elimination. PHI may incur other restructuring charges for employee termination benefits and other cost reduction efforts as part of the implementation of the plan.

Depreciation and Amortization

Depreciation and Amortization expenses increased by $11 million to $104 million in 2010 from $93 million in 2009 primarily due to:

• An increase of $5 million in amortization of regulatory assets primarily due to the EmPower Maryland surcharge rate that became effective in March 2010 (which is substantially offset by a corresponding increase in Regulated T&D Electric Revenue).

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

Other Taxes

Other Taxes increased by $30 million to $130 million in 2010 from $100 million in 2009. The increase was primarily due to increased pass-throughs experienced by Power Delivery (which are substantially offset by a corresponding increase in Regulated T&D Electric Revenue) primarily resulting from rate increases in utility taxes imposed by Montgomery County, Maryland.

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Deferred Electric Service Costs

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

Deferred Electric Service Costs increased by $45 million, to an expense of $13 million in 2010 as compared to an expense reduction of $32 million in 2009, primarily due to an increase in deferred electricity expense as a result of lower electricity supply costs.

Effects of Pepco Divestiture-Related Claims

District of Columbia Divestiture Case

As further described in Note (14), “Commitments and Contingencies,” the DCPSC on May 18, 2010 issued an order addressing all of the outstanding issues relating to Pepco’s obligation 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 order disallowed certain items that Pepco had included in the costs it deducted in calculating the net proceeds of the sale. The disallowance of these costs, together with interest, increased the aggregate amount Pepco is required to distribute to customers by approximately $11 million. While Pepco has filed an appeal of the DCPSC’s decision with the District of Columbia Court of Appeals, in view of the DCPSC order, PHI recognized a pre-tax expense of $9 million for the three months ended September 30, 2010. PHI intends to continue to pursue its appeal.

Settlement of Mirant Bankruptcy Claims

As further described in Note (14), “Commitments and Contingencies,” in July 2009, the MPSC approved an allocation between Pepco and its Maryland customers of the Maryland portion of the Mirant bankruptcy settlement proceeds. As a result, Pepco recorded a pre-tax gain of $26 million in the third quarter of 2009 reflecting the Maryland proceeds retained by Pepco.

Other Income (Expenses)

Other Expenses (which are net of Other Income) increased by $117 million primarily due to the loss on extinguishment of debt that was recorded during the third quarter of 2010, partially offset by lower interest expense of $17 million.

Loss on Extinguishment of Debt

During the three months ended September 30, 2010, PHI recorded a loss on extinguishment of debt of $135 million which is further discussed below.

In July 2010, PHI purchased, pursuant to a cash tender offer, $640 million in principal amount of its 6.45% Senior Notes due 2012 (6.45% Notes), redeemed the remaining $110 million of outstanding 6.45% Notes, and purchased pursuant to a cash tender offer $129 million of its 6.125% Senior Notes due 2017 (6.125% Notes) and $65 million of 7.45% Senior Notes due 2032 (7.45% Notes). In connection with these transactions, PHI recorded a pre-tax loss on extinguishment of debt of $120 million in the third quarter of 2010.

On October 13, 2010, PHI purchased pursuant to a cash tender offer an additional $40 million of outstanding 6.125% Notes. PHI expects to record an after-tax loss on extinguishment of debt of approximately $33 million in the fourth quarter of 2010 in connection with this transaction.

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In June 2002, PHI entered into several treasury rate lock transactions to hedge changes in interest rates related to the anticipated issuance in August 2002 of several series of Senior Notes, including the 6.45% Notes and the 7.45% Notes. Upon issuance of the fixed rate debt in August 2002, the rate locks were terminated at a loss that has been deferred in Accumulated Other Comprehensive Loss and is being recognized in income over the life of the debt issued as interest payments on the debt are made. In connection with the purchases of the 6.45% Notes and the 7.45% Notes, PHI accelerated the recognition of $15 million of pre-tax losses attributable to the 6.45% and 7.45% Notes by reclassifying these losses from Accumulated Other Comprehensive Loss to income in the third quarter of 2010. These losses have also been reported as a pre-tax loss on extinguishment of debt.

Income Tax Expense

PHI’s consolidated effective tax rates from continuing operations for the three months ended September 30, 2010 and 2009 were (40.0%) and 32.9%, respectively. The reduction in the effective tax rate is primarily due to the recording of current state tax benefits resulting from the restructuring of certain PHI subsidiaries which has subjected PHI to state income taxes in new jurisdictions. On April 1, 2010, as part of an ongoing effort to simplify PHI’s organizational structure, certain of PHI’s subsidiaries were converted from corporations to single member limited liability companies. In addition to increased organizational flexibility and reduced administrative costs, converting these entities to limited liability companies allows PHI to include income or losses in the former corporations in a single state income tax return, thus increasing the utilization of state income tax attributes. As a result of the increase in the current state tax benefits discussed above, PHI recorded a $2 million reduction to the $8 million benefit recorded in the second quarter by establishing a valuation allowance on certain state net operating losses.

The consolidated effective tax rate from continuing operations for the three months ended September 30, 2010 is further reduced as a result of a $2 million adjustment to eliminate deferred tax liabilities associated with a goodwill impairment charge recorded in 2005, and the recording of a $2 million benefit related to deferred tax attributes. The decrease in the effective rate was partially offset by a $13 million (after-tax) benefit recorded in 2009 related to a change in tax reporting for certain asset dispositions occurring in prior years.

Discontinued Operations

For the three months ended September 30, 2010, the $4 million loss from discontinued operations, net of income taxes, includes an after-tax loss from operations of $6 million and after-tax net gains of $2 million from dispositions of assets and businesses. The after-tax loss from operations includes an adjustment of $7 million ($4 million after tax) to reverse revenue erroneously recognized in the second quarter of 2010 related to load service contract settlements. The after-tax net gains from dispositions of assets and businesses primarily includes net gains of $15 million realized in the third quarter on ongoing dispositions of load service supply contracts, the energy hedging portfolio, certain tolling agreements and other non-generation assets, partially offset by an additional $13 million loss from the sale of the wholesale power generation business to Calpine. The additional loss on the sale to Calpine includes an after-tax $6 million post-closing working capital adjustment and $7 million of additional state income tax charges.

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

Continuing Operations

Operating Revenue

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

	2010			2009			Change
Power Delivery	$	4,011		$	3,895		$	116
Pepco Energy Services		1,480			1,828			(348	)
Other Non-Regulated		41			40			1
Corporate and Other		(10	)		(10	)		—
Total Operating Revenue	$	5,522		$	5,753		$	(231	)

Power Delivery Business

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

	2010		2009		Change
Regulated T&D Electric Revenue	$	1,413	$	1,263	$	150
Default Electricity Supply Revenue		2,380		2,379		1
Other Electric Revenue		52		54		(2	)
Total Electric Operating Revenue		3,845		3,696		149
Regulated Gas Revenue		127		169		(42	)
Other Gas Revenue		39		30		9
Total Gas Operating Revenue		166		199		(33	)
Total Power Delivery Operating Revenue	$	4,011	$	3,895	$	116

Regulated T&D Electric

Regulated T&D Electric Revenue	2010		2009		Change
Residential	$	529	$	464	$	65
Commercial and industrial		668		611		57
Other		216		188		28
Total Regulated T&D Electric Revenue	$	1,413	$	1,263	$	150

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Regulated T&D Electric Sales (GWh)	2010		2009		Change
Residential		14,521		13,219		1,302
Commercial and industrial		24,315		23,965		350
Other		182		185		(3	)
Total Regulated T&D Electric Sales		39,018		37,369		1,649

Other Regulated T&D Electric Revenue consists primarily of transmission service revenue.
Regulated T&D Electric Customers (in thousands)	2010		2009		Change
Residential		1,631		1,614		17
Commercial and industrial		198		197		1
Other		2		2		—
Total Regulated T&D Electric Customers		1,831		1,813		18

Regulated T&D Electric Revenue increased by $150 million primarily due to:

• An increase of $43 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 $29 million due to distribution rate increases (Pepco in the District of Columbia effective November 2009, March 2010 and July 2010; DPL in Maryland effective December 2009; DPL in Delaware effective April 2010; and ACE in New Jersey effective June 2010).

• An increase of $26 million in transmission revenue primarily attributable to (i) the accrual of true-ups to reflect costs incurred in the June 2009 through May 2010 service period that were included in the final determination of network service transmission rates effective June 1, 2010 through May 31, 2011, which include rate adjustments for such true-ups and (ii) other transmission rate increases.

• An increase of $26 million due to higher sales in the District of Columbia, Delaware and New Jersey service territories as a result of warmer weather during the 2010 spring and summer months as compared to 2009. Distribution revenue in Maryland is decoupled from consumption in the first nine months of both 2009 and 2010 and, therefore, the period-to-period comparison is not affected by weather. Distribution revenue in the District of Columbia is not decoupled from consumption in the first nine months of 2009 and, therefore, the period-to-period comparison is affected by weather.

• An increase of $11 million due to the implementation of the EmPower Maryland (demand side management program for Pepco and DPL) surcharge rate in March 2010 (which is substantially offset by a corresponding increase in Depreciation and Amortization).

• An increase of $7 million due to customer growth of 1% primarily in the residential class in 2010.

• An increase of $7 million due to higher non-weather related average customer usage.

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Default Electricity Supply

Default Electricity Supply Revenue	2010		2009		Change
Residential	$	1,644	$	1,519	$	125
Commercial and industrial		581		739		(158	)
Other		155		121		34
Total Default Electricity Supply Revenue	$	2,380	$	2,379	$	1
Other Default Electricity Supply Revenue consists primarily of (i) revenue from the resale by ACE in the PJM Regional Transmission Organization market of energy and capacity purchased under contracts with unaffiliated NUGs, and (ii) revenue from transmission enhancement credits.
Default Electricity Supply Sales (GWh)	2010		2009		Change
Residential		13,819		12,770		1,049
Commercial and industrial		5,492		6,764		(1,272	)
Other		68		71		(3	)
Total Default Electricity Supply Sales		19,379		19,605		(226	)
Default Electricity Supply Customers (in thousands)	2010		2009		Change
Residential		1,554		1,563		(9	)
Commercial and industrial		152		159		(7	)
Other		2		2		—
Total Default Electricity Supply Customers		1,708		1,724		(16	)

Default Electricity Supply Revenue increased by $1 million primarily due to:

• An increase of $123 million due to higher sales as a result of warmer weather during the 2010 spring and summer months as compared to 2009.

• An increase of $37 million due to higher non-weather related average customer usage.

• An increase of $24 million in wholesale energy and capacity revenues primarily due to higher market prices for the sale of electricity purchased from NUGs.

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

The aggregate amount of these increases was partially offset by:

• A decrease of $164 million due to lower sales, primarily as a result of commercial customer migration to competitive suppliers.

• A decrease of $26 million as a result of lower Default Electricity Supply rates.

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The increase in total Default Electricity Supply Revenue includes an increase of $14 million in unbilled revenue attributable to ACE’s BGS. Under the BGS terms approved by the New Jersey Board of Public Utilities (NJBPU), ACE is entitled to recover from its customers all of its costs of providing BGS. If the costs of providing BGS exceed the BGS revenue, then the excess costs are deferred in Deferred Electric Service Costs. ACE’s BGS unbilled revenue is not included in the deferral calculation, and therefore has an impact on the results of operations in the period during which it is accrued. While the change in the amount of unbilled revenue from year to year typically is not significant, for the nine months ended September 30, 2010, BGS unbilled revenue increased by $14 million as compared to the nine months ended September 30, 2009, which resulted in a $8 million increase in PHI’s net income. The increase was primarily due to higher Default Electricity Supply rates and warmer weather during the unbilled revenue period at the end of the nine months ended September 30, 2010 as compared to the corresponding period in 2009.

Regulated Gas

Regulated Gas Revenue	2010		2009		Change
Residential	$	78	$	103	$	(25	)
Commercial and industrial		44		60		(16	)
Transportation and other		5		6		(1	)
Total Regulated Gas Revenue	$	127	$	169	$	(42	)
Regulated Gas Sales (billion cubic feet)	2010		2009		Change
Residential		5		6		(1	)
Commercial and industrial		3		4		(1	)
Transportation and other		5		4		1
Total Regulated Gas Sales		13		14		(1	)
Regulated Gas Customers (in thousands)	2010		2009		Change
Residential		113		113		—
Commercial and industrial		10		9		1
Transportation and other		—		—		—
Total Regulated Gas Customers		123		122		1

Regulated Gas Revenue decreased by $42 million primarily due to:

• A decrease of $32 million due to lower sales as a result of milder weather during the 2010 winter months as compared to 2009.

• A decrease of $22 million due to Gas Cost Rate decreases effective March 2009 and November 2009.

The aggregate amount of these decreases was partially offset by:

• An increase of $11 million due to higher non-weather related average customer usage.

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Other Gas Revenue

Other Gas Revenue increased by $9 million primarily due to higher revenue from off-system sales resulting from:

• An increase of $5 million due to higher demand from electric generators and gas marketers.

• An increase of $3 million due to higher market prices.

Pepco Energy Services

Pepco Energy Services’ operating revenue decreased $348 million primarily due to:

• A decrease of $489 million due to lower retail electricity sales volume primarily attributable to the ongoing wind down of the retail energy supply business.

The decrease is partially offset by:

• An increase of $87 million due to higher electricity generation output that resulted from completed transmission construction projects and operations associated with warmer than normal weather, and lower Reliability Pricing Model charges associated with the generation facilities.

• An increase of $32 million due to higher retail gas supply load from customer acquisitions in 2009 prior to the commencement of the wind down of the business, partially offset by lower retail natural gas prices.

• An increase of $21 million increase due to increased high voltage and energy services construction activities.

Operating Expenses

Fuel and Purchased Energy and Other Services Cost of Sales

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

	2010			2009			Change
Power Delivery	$	2,453		$	2,560		$	(107	)
Pepco Energy Services		1,333			1,674			(341	)
Corporate and Other		(5	)		(7	)		2
Total	$	3,781		$	4,227		$	(446	)

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Power Delivery Business

Power Delivery’s Fuel and Purchased Energy consists of the cost of electricity and gas purchased by its utility subsidiaries to fulfill their respective Default Electricity Supply and Regulated Gas obligations and, as such, is recoverable from customers in accordance with the terms of public service commission orders. It also includes the cost of gas purchased for off-system sales. Fuel and Purchased Energy expense decreased by $107 million primarily due to:

• A decrease of $155 million primarily due to commercial customer migration to competitive suppliers.

• A decrease of $49 million in deferred electricity expense as a result of both (i) a lower rate of recovery due to lower Default Electricity Supply revenue rates and (ii) an increase in costs due to higher average electricity costs under Default Electricity Supply contracts.

• A decrease of $21 million in deferred gas expense as a result of a lower rate of recovery of natural gas supply costs.

The aggregate amount of these decreases was partially offset by:

• An increase of $119 million due to higher electricity sales as a result of warmer weather during the 2010 spring and summer months as compared to 2009.

Pepco Energy Services

Pepco Energy Services’ Fuel and Purchased Energy and Other Services Cost of Sales decreased $341 million primarily due to:

• A decrease of $427 million due to lower volumes of electricity purchased to serve decreased retail customer load as a result of the ongoing wind down of the retail energy supply business.

The decreased is partially offset by:

• An increase of $36 million due to higher retail gas supply load from 2009 customer acquisitions partially offset by lower wholesale natural gas prices.

• An increase of $27 million due to higher fuel usage associated with the generating facilities.

• An increase of $24 million due to increased high voltage and energy services construction activities.

Other Operation and Maintenance

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

	2010			2009			Change
Power Delivery	$	590		$	569		$	21
Pepco Energy Services		68			68			—
Other Non-Regulated		2			2			—
Corporate and Other		(24	)		(21	)		(3	)
Total	$	636		$	618		$	18

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Other Operation and Maintenance expense for Power Delivery increased by $21 million; however, excluding an increase of $11 million primarily related to bad debt and administrative expenses that are deferred and recoverable in Default Electricity Supply Revenue, Other Operation and Maintenance expense increased by $10 million. The $10 million increase was primarily due to:

• An increase of $32 million in emergency restoration costs primarily due to severe storms in February, July and August 2010. A portion of the costs of the restoration work for the summer storms relates to services provided by outside contractors and other utilities that were not billed as of September 30, 2010, and accordingly have been estimated. These estimates are subject to adjustment when the actual billings are received in the fourth quarter of 2010. The actual billings may vary from the estimates of such billings.

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

The aggregate amount of these increases was partially offset by:

• A decrease of $15 million in employee-related costs, primarily due to lower pension and other postretirement benefit expenses.

• A decrease of $9 million primarily due to Pepco adjustments for (i) February 2010 severe winter storm costs and (ii) distribution rate case costs that previously were charged to other operation and maintenance expense. The adjustments were recorded in accordance with a MPSC rate order issued in August 2010 and a DCPSC rate order issued in February 2010, respectively, allowing for the recovery of the costs.

Restructuring Charge

With the ongoing wind down of the retail energy supply business of Pepco Energy Services and the disposition of Conectiv Energy, PHI is repositioning itself as a regulated transmission and distribution company. In connection with this repositioning, PHI commenced a comprehensive organizational review in the second quarter of 2010 to identify opportunities to streamline the organization and to achieve certain reductions in corporate overhead costs that are allocated to its operating segments. This review has resulted in the adoption of a phased restructuring plan (the plan). PHI began implementing the initial phase of the plan during the third quarter, identifying 165 positions that will be eliminated during the fourth quarter of 2010. The second phase of the plan has also commenced, which will focus on identifying additional cost reduction opportunities through process improvements and operational efficiencies. PHI currently estimates that the implementation of the plan will result in an annual reduction of at least $20 million in corporate overhead costs.

Pursuant to the plan, PHI recorded a pre-tax restructuring charge of $14 million for the nine months ended September 30, 2010, related to severance and health and welfare benefits to be provided to terminated employees.

Under FASB guidance on exit or disposal cost obligations (ASC 420), certain severance costs are being recognized over the remaining service periods for certain employees to be terminated under the restructuring plan. Generally, the remaining service periods are expected to end by December 31, 2010 and, accordingly, PHI expects to record an additional $4 million of employee severance and health and welfare benefits in the fourth quarter of 2010. PHI may incur further severance costs if additional positions are identified for elimination. PHI may incur other restructuring charges for employee termination benefits and other cost reduction efforts as part of the implementation of the plan.

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Depreciation and Amortization

Depreciation and Amortization expenses increased by $21 million to $286 million in 2010 from $265 million in 2009 primarily due to:

• An increase of $9 million in amortization of regulatory assets primarily due to the EmPower Maryland surcharge rate that became effective in March 2010 (which is substantially offset by a corresponding increase in Regulated T&D Electric Revenue).

• An increase of $8 million due to utility plant additions.

Other Taxes

Other Taxes increased by $48 million to $327 million in 2010 from $279 million in 2009. The increase was primarily due to increased pass-throughs experienced by Power Delivery (which are substantially offset by a corresponding increase in Regulated T&D Electric Revenue) primarily resulting from rate increases in utility taxes imposed by Montgomery County, Maryland.

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 $47 million, to an expense reduction of $69 million in 2010 as compared to an expense reduction of $116 million in 2009, primarily due to an increase in deferred electricity expense as a result of lower electricity supply costs.

Effects of Pepco Divestiture-Related Claims

District of Columbia Divestiture Case

As further described in Note (14), “Commitments and Contingencies,” the DCPSC on May 18, 2010 issued an order addressing all of the outstanding issues relating to Pepco’s obligation 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 order disallowed certain items that Pepco had included in the costs it deducted in calculating the net proceeds of the sale. The disallowance of these costs, together with interest, increased the aggregate amount Pepco is required to distribute to customers by approximately $11 million. While Pepco has filed an appeal of the DCPSC’s decision with the District of Columbia Court of Appeals, in view of the DCPSC order, PHI recognized a pre-tax expense of $11 million for the nine months ended September 30, 2010. PHI intends to continue to pursue its appeal.

Settlement of Mirant Bankruptcy Claims

As further described in Note (14), “Commitments and Contingencies,” in March 2009, the DCPSC approved an allocation between Pepco and its District of Columbia customers of the District of Columbia portion of the Mirant bankruptcy settlement proceeds. As a result, Pepco recorded a pre-tax gain of $14 million in the first quarter of 2009 reflecting the District of Columbia proceeds retained by Pepco. In July

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2009, the MPSC approved an allocation between Pepco and its Maryland customers of the Maryland portion of the Mirant bankruptcy settlement proceeds. As a result, Pepco recorded a pre-tax gain of $26 million in the third quarter of 2009 reflecting the Maryland proceeds retained by Pepco.

Other Income (Expenses)

Other Expenses (which are net of Other Income) increased by $120 million primarily due to the loss on extinguishment of debt that was recorded during the third quarter of 2010, partially offset by lower interest expense of $14 million.

Loss on Extinguishment of Debt

During the nine months ended September 30, 2010, PHI recorded a loss on extinguishment of debt of $135 million which is further discussed below.

In July 2010, PHI purchased, pursuant to a cash tender offer, $640 million in principal amount of its 6.45% Notes, redeemed the remaining $110 million of outstanding 6.45% Notes, and purchased pursuant to a cash tender offer $129 million of its 6.125% Notes and $65 million of 7.45% Notes. In connection with these transactions, PHI recorded a pre-tax loss on extinguishment of debt of $120 million in the third quarter of 2010.

On October 13, 2010, PHI purchased pursuant to a cash tender offer an additional $40 million of outstanding 6.125% Notes. PHI expects to record an after-tax loss on extinguishment of debt of approximately $33 million in the fourth quarter of 2010 in connection with this transaction.

In June 2002, PHI entered into several treasury rate lock transactions to hedge changes in interest rates related to the anticipated issuance in August 2002 of several series of Senior Notes, including the 6.45% Notes and the 7.45% Notes. Upon issuance of the fixed rate debt in August 2002, the rate locks were terminated at a loss that has been deferred in Accumulated Other Comprehensive Loss and is being recognized in income over the life of the debt issued as interest payments on the debt are made. In connection with the purchases of the 6.45% Notes and the 7.45% Notes, PHI accelerated the recognition of $15 million of pre-tax losses attributable to the 6.45% and 7.45% Notes by reclassifying these losses from Accumulated Other Comprehensive Loss to income in the third quarter of 2010. These losses have also been reported as a pre-tax loss on extinguishment of debt.

Income Tax Expense

PHI’s consolidated effective tax rates from continuing operations for the nine months ended September 30, 2010 and 2009 were 29.4% and 34.5%, respectively. The reduction in the effective tax rate is primarily due to the restructuring of PHI subsidiaries. As a consequence of the restructuring, PHI recorded current state tax benefits that result from subjecting PHI to state income taxes in new jurisdictions; and the release of a net $6 million valuation allowance on deferred tax assets related to state net operating losses recognized in 2010.

The reduction in the consolidated effective tax rate in the nine months ended September 30, 2010 was partially offset by changes in estimates and interest related to uncertain and effectively settled tax positions. These were primarily related to a $2 million reversal of accrued interest income on state income tax positions that PHI no longer believes is more likely than not to be realized, and the reversal of $6 million of erroneously accrued interest income on uncertain and effectively settled state income tax positions. The decrease in the effective rate was further offset by a $13 million (after-tax) benefit recorded in 2009 related to a change in tax reporting for certain asset dispositions occurring in prior years.

PHI’s consolidated effective tax rate from continuing operations for the nine months ended September 30, 2010 also reflects a deferred tax basis adjustment related to change in taxation of the Medicare Part D subsidy enacted by the Patient Protection and Affordable Care Act. Under this legislation, PHI receives a tax-free federal subsidy for the costs it incurs for certain prescription drugs covered under its post-employment benefit plan. Prior to the legislation, the costs incurred for those prescription drugs were tax deductible. The legislation includes a provision, effective beginning in 2013, which eliminates the tax deductibility of the prescription drug costs. As a result, in the first quarter of 2010, PHI wrote off $5 million of deferred tax assets. Of this amount, $3 million was established as a regulatory asset, which PHI

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anticipates will be recoverable from its utility customers in the future. This change increased PHI’s 2010 tax expense by $4 million, which was partially offset through a reduction in Operating Expenses, resulting in a $2 million decrease to net income.

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

Discontinued Operations

For the nine months ended September 30, 2010, the $126 million loss from discontinued operations, net of income taxes, includes after-tax income from operations of $2 million and after-tax net losses of $128 million from dispositions of assets and businesses. The after-tax loss from operations 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 $12 million. The after-tax net losses from dispositions of assets and businesses primarily includes (i) an after-tax loss of $73 million from the sale of the wholesale power generation business to Calpine, which is inclusive of the after-tax writedown of $67 million recorded in the second quarter of 2010 and is subject to final post-closing adjustments, (ii) after-tax net losses on sales of assets and businesses not sold to Calpine of $27 million, which is 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 $28 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 September 30, 2010, Pepco Holdings’ current assets on a consolidated basis totaled $1.7 billion and its current liabilities totaled $1.8 billion. At December 31, 2009, Pepco Holdings’ current assets on a consolidated basis totaled $1.9 billion and its current liabilities totaled $2.3 billion. The $0.3 billion increase in working capital from December 31, 2009 to September 30, 2010 was due primarily to the decrease in the current portion of long-term debt.

At September 30, 2010, Pepco Holdings’ cash and current cash equivalents totaled $44 million, of which $16 million is reflected on the Balance Sheet in Conectiv Energy assets held for sale, $1 million was invested in money market funds that invest in U.S. Treasury obligations, and the balance was held as cash and uncollected funds. Current restricted cash equivalents (cash that is available to be used only for designated purposes) totaled $14 million. At December 31, 2009, Pepco Holdings’ cash and current cash equivalents totaled $46 million, of which $2 million is reflected on the Balance Sheet in Conectiv Energy assets held for sale, and its current restricted cash equivalents totaled $11 million.

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PHI expects the working capital deficit will be funded during 2010 through cash flow from operations. Additional working capital will be provided by reduced collateral requirements of the Pepco Energy Services business and the disposition of the Conectiv Energy business.

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

	As of September 30, 2010 (millions of dollars)
Type	PHI Parent		Pepco		DPL		ACE		ACE Funding		Pepco Energy Services		PHI Consolidated
Variable Rate Demand Bonds	$	—	$	—	$	105	$	23	$	—	$	18	$	146
Commercial Paper		268		—		3		123		—		—		394
Total Short-Term Debt	$	268	$	—	$	108	$	146	$	—	$	18	$	540
Current Maturities of Long-Term Debt and Project Funding	$	—	$	—	$	35	$	—	$	35	$	5	$	75
	As of December 31, 2009 (millions of dollars)
Type	PHI Parent		Pepco		DPL		ACE		ACE Funding		Pepco Energy Services		PHI Consolidated
Variable Rate Demand Bonds	$	—	$	—	$	105	$	23	$	—	$	18	$	146
Commercial Paper		324		—		—		60		—		—		384
Total Short-Term Debt	$	324	$	—	$	105	$	83	$	—	$	18	$	530
Current Maturities of Long-Term Debt and Project Funding	$	450	$	16	$	31	$	1	$	34	$	4	$	536

Financing Activity During the Three Months Ended September 30, 2010

On July 1, 2010, DPL purchased $31 million of unsecured tax-exempt bonds issued for the benefit of DPL by The Delaware Economic Development Authority that in accordance with the terms of the bonds were subject to mandatory tender. DPL intends to remarket these bonds during the fourth quarter of 2010.

In July 2010, ACE Funding made principal payments of $5.5 million on Series 2002-1 Bonds, Class A-2, and $2.1 million on Series 2003-1 Bonds, Class A-2.

On August 30, 2010, ACE redeemed $1 million of 7.25% secured medium-term notes at maturity.

Debt Tender Offers

On July 2, 2010, PHI purchased, pursuant to a cash tender offer, $640 million in principal amount of its 6.45% Notes for an aggregate purchase price of $713 million, plus accrued and unpaid interest. The tender offer for the 6.45% Notes also constituted a solicitation of the consent of the holders of the 6.45% Notes to an amendment of the terms of the 6.45% Notes to reduce the notice period for the redemption from not less than 30 days and not more than 60 days to three business days. This amendment, which required the consent of the holders of a majority of the outstanding 6.45% Notes, was approved upon the repurchase of

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the 6.45% Notes pursuant to the tender offer. On July 2, 2010, PHI terminated the tender offer and issued a notice of redemption for the balance of the 6.45% Notes. On July 8, 2010, PHI redeemed the remaining $110 million of outstanding 6.45% Notes at an aggregate redemption price of $122 million, plus accrued and unpaid interest.

On July 20, 2010, PHI purchased, pursuant to a cash tender offer, (i) $129 million of its 6.125% Notes at an aggregate purchase price of $145 million, plus accrued and unpaid interest, and (ii) $65 million of 7.45% Notes at an aggregate purchase price of $78 million, plus accrued and unpaid interest.

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

As a result of the aforementioned purchases of debt, PHI recorded a pre-tax loss on extinguishment of debt of $120 million ($72 million after-tax) in the third quarter of 2010.

Treasury Rate Locks

In June 2002, PHI entered into several treasury rate lock transactions to hedge changes in interest rates related to the anticipated issuance in August 2002 of several series of senior notes, including the 6.45% Notes and the 7.45% Notes. Upon issuance of the fixed rate debt, the treasury rate locks were terminated at a loss that has been deferred in Accumulated Other Comprehensive Loss and is being recognized in income over the life of the debt issued as interest payments on the debt are made. In connection with the purchases of the 6.45% Notes and the 7.45% Notes, PHI accelerated the recognition of $15 million of pre-tax losses attributable to the 6.45% Notes and the 7.45% Notes by reclassifying these losses from Accumulated Other Comprehensive Loss to the income statement in the third quarter of 2010. These losses have also been reported as a pre-tax loss on extinguishment of debt.

Financing Activity Subsequent to September 30, 2010

On October 1, 2010, PHI issued $250 million of its 2.70% Senior Notes due October 1, 2015 (2.70% Notes).

On October 13, 2010, PHI:

• purchased, pursuant to a cash tender offer, an additional $40 million in principal amount of the 6.125% Notes for an aggregate purchase price of $48 million, plus accrued and unpaid interest. PHI used proceeds from the issuance of the 2.70% Notes to pay the purchase price of the 6.125% Notes; and

• issued notices of redemption of (i) $200 million in principal amount of its 6.0% Senior Notes due 2019 (6.0% Notes), and (ii) $10 million in principal amount of its 5.9% Senior Notes due 2016 (5.9% Notes). PHI will use proceeds from the issuance of the 2.70% Notes to pay the redemption price. The redemption date is November 15, 2010. The redemption price will be determined three business days prior to the redemption date.

PHI expects to record after-tax losses on extinguishment of debt of approximately $33 million in the fourth quarter of 2010 associated with the October 13, 2010 tender offer for the 6.125% Notes and the redemptions of the 6.0% Notes and the 5.9% Notes.

Credit Facilities

PHI, Pepco, DPL and ACE maintain an unsecured credit facility to provide for their respective short-term liquidity needs. The aggregate borrowing limit under this credit facility is $1.5 billion, all or any portion of which may be used to obtain loans or to issue letters of credit. PHI’s credit limit under the facility is $875 million. The credit limit of each of Pepco, DPL and ACE is the lesser of $500 million and the maximum amount of debt the company is permitted to have outstanding by its regulatory authorities, except that the

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aggregate amount of credit used by Pepco, DPL and ACE at any given time collectively may not exceed $625 million. The interest rate payable by each company on utilized funds is, at the borrowing company’s election, (i) the greater of the prevailing prime rate and the federal funds effective rate plus 0.5% or (ii) the prevailing Eurodollar rate, plus a margin that varies according to the credit rating of the borrower. The facility also includes a “swingline loan sub-facility” pursuant to which each company may make same day borrowings in an aggregate amount not to exceed $150 million. Any swingline loan must be repaid by the borrower within seven days of receipt thereof.

The facility commitment expiration date is May 5, 2012, with each company having the right to elect to have 100% of the principal balance of the loans outstanding on the expiration date continued as non-revolving term loans for a period of one year from such expiration date. The facility is intended to serve primarily as a source of liquidity to support the commercial paper programs of the respective companies. The companies also are permitted to use the facility to borrow funds for general corporate purposes and issue letters of credit. In order for a borrower to use the facility, certain representations and warranties must be true and correct, and the borrower must be in compliance with specified covenants, including (i) the requirement that each borrowing company maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the credit agreement, which calculation excludes from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) a restriction on sales or other dispositions of assets, other than certain sales and dispositions, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than permitted liens.

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

PHI also has a $50 million bi-lateral credit agreement with The Bank of Nova Scotia that expires on November 2, 2010, which only can be used for the purpose of obtaining letters of credit. In addition, PHI had a $400 million unsecured credit facility that terminated on October 15, 2010. As of September 30, 2010, no letters of credit were outstanding under these agreements.

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

In April 2010, PHI entered into a $450 million unsecured bridge facility with Morgan Stanley Bank, N.A. and Credit Suisse AG. PHI used the proceeds of the loans drawn under the facility to repay (i) $200 million in aggregate principal amount of its 4.0% Senior Notes due May 15, 2010 and (ii) $250 million in aggregate principal amount of its Floating Rate Notes due June 1, 2010. On July 1, 2010, PHI repaid all amounts outstanding under this facility with a portion of the proceeds from the sale of the Conectiv Energy wholesale power generation business, thereby terminating the facility.

Credit Facilities Activity Subsequent to September 30, 2010

On October 15, 2010, a $400 million unsecured credit facility maintained by PHI expired. To replace this facility, PHI, on October 27, 2010, entered into two bi-lateral 364 day unsecured credit agreements totaling $200 million. Under each of the credit agreements, PHI has access to revolving and floating rate loans over the terms of the agreements. Neither agreement provides for the issuance of letters of credit. The interest rate payable on funds borrowed is, at PHI’s election, based on either (a) the prevailing Eurodollar rate or (b) the highest of (i) the prevailing prime rate, (ii) the federal funds effective rate plus 0.5% or (iii) the one-month Eurodollar rate plus 1.0%, plus a margin 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, and results of operations or financial condition is not a condition to the availability of credit under the agreements. Neither agreement includes any rating triggers.

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PHI does not plan to renew its $50 million bi-lateral credit agreement with The Bank of Nova Scotia that expires on November 2, 2010.

The two expiring credit facilities were established to provide additional liquidity and collateral support for Pepco Energy Services’ retail energy supply business and for Conectiv Energy. Based on the progress toward winding down the retail energy supply business and disposing of the Conectiv Energy segment, the level of liquidity and collateral needed to support these businesses has decreased. As a result, PHI has been able to reduce the total amount of its credit facility needs by $250 million.

Cash and Credit Facilities Available as of September 30, 2010

	Consolidated PHI		PHI Parent		Utility Subsidiaries
	(millions of dollars)
Credit Facilities (Total Capacity) (a)	$	1,950	$	1,325	$	625
Less: Letters of Credit issued		151		146		5
Commercial Paper outstanding		394		268		126
Remaining Credit Facilities Available		1,405		911		494
Cash Invested in Money Market Funds (b)		1		1		—
Total Cash and Credit Facilities Available	$	1,406	$	912	$	494

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

(b) Cash and cash equivalents reported on the Balance Sheet total $28 million, which includes the $1 million invested in money market funds and $27 million held in cash and uncollected funds.

At September 30, 2010, the amount of cash, plus borrowing capacity under PHI credit facilities available to meet the future liquidity needs of PHI and its utility subsidiaries on a consolidated basis totaled $1.4 billion, of which $494 million consisted of the combined cash and borrowing capacity of PHI’s utility subsidiaries. On October 15, 2010, the $400 million unsecured credit facility maintained by PHI expired and was replaced by two bi-lateral 364-day unsecured credit agreements in the aggregate amount of $200 million. The PHI $50 million bi-lateral credit agreement will expire on November 2, 2010.

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

Collateral Requirements

At September 30, 2010 and December 31, 2009, the aggregate amount of cash, plus borrowing capacity under the credit facilities available to meet the combined future liquidity needs of Pepco Energy Services and Conectiv Energy totaled $912 million and $820 million, respectively. At September 30, 2010, the aggregate amount of cash, plus borrowing capacity under the credit facilities available to meet the future liquidity needs of Pepco Energy Services and Conectiv Energy totaled $912 million, and would have been $712 million had the October expiration of PHI’s $400 million unsecured credit facility and the entry by PHI into the two bi-lateral 364-day unsecured credit agreements in the aggregate amount of $200 million occurred prior to September 30, 2010.

Collateral Requirements of Pepco Energy Services

In conducting its retail energy supply business, Pepco Energy Services, during periods of declining energy prices, has been exposed to the asymmetrical risk of having to post collateral under its wholesale purchase

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contracts without receiving a corresponding amount of collateral from its retail customers. To partially address these asymmetrical collateral obligations, Pepco Energy Services, in the first quarter of 2009, entered into a credit intermediation arrangement with Morgan Stanley Capital Group, Inc. (MSCG). Under this arrangement, MSCG, in consideration for the payment to MSCG of certain fees, (i) has assumed by novation the electricity purchase obligations of Pepco Energy Services in years 2009 through 2011 under several wholesale purchase contracts and (ii) has agreed to supply electricity to Pepco Energy Services on the same terms as the novated transactions, but without imposing on Pepco Energy Services any obligation to post collateral based on changes in electricity prices. As of September 30, 2010, approximately 3% of Pepco Energy Services’ wholesale electricity purchase obligations (measured in megawatt hours) was covered by this credit intermediation arrangement with MSCG. The upfront fees incurred by Pepco Energy Services in the amount of $25 million are being amortized into expense in declining amounts over the life of the arrangement based on the fair value of the underlying contracts at the time of the novation. For the three months ended September 30, 2010 and 2009, approximately $1 million and $4 million, respectively, of the fees have been amortized and reflected in interest expense. For the nine months ended September 30, 2010 and 2009, approximately $6 million and $12 million, respectively, of the fees have been amortized and reflected in interest expense.

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

Depending on the contract terms, the collateral required to be posted by Pepco Energy Services can be of varying forms, including cash and letters of credit. As of September 30, 2010, Pepco Energy Services had posted net cash collateral of $150 million and letters of credit of $140 million. At December 31, 2009, Pepco Energy Services had posted net cash collateral of $123 million and letters of credit of $157 million.

Remaining Collateral Requirements of Conectiv Energy

Depending on the contract terms, the collateral required to be posted by Conectiv Energy is of varying forms, including cash and letters of credit. As of September 30, 2010, Conectiv Energy had posted net cash collateral of $172 million and letters of credit of $2 million. At December 31, 2009, Conectiv Energy had posted net cash collateral of $240 million and letters of credit of $22 million.

Pension and Postretirement Benefit Plans

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

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

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Under the Pension Protection Act, if a plan incurs a funding shortfall in the preceding plan year, there can be required minimum quarterly contributions in the current and following plan years. PHI satisfied the minimum required contribution rules in 2008, 2009 and 2010. Although PHI currently has no minimum funding requirement under the Pension Protection Act guidelines in 2010, PHI Service Company has made discretionary tax-deductible contributions to the PHI Retirement Plan of $35 million on each of July 1, 2010 and August 2, 2010 and $30 million on September 1, 2010. These contributions in the aggregate amount of $100 million brought the PHI Retirement Plan assets to the funding target level for 2010 under the Pension Protection Act.

Based on the results of the 2009 actuarial valuation, PHI’s net periodic pension and other postretirement benefit costs were approximately $149 million. The current estimate of benefit cost for 2010 is $113 million. This includes one time charges of $6 million related to sale of the Conectiv Energy wholesale power generation business. The utility subsidiaries are responsible for substantially all of the total PHI net periodic pension and other postretirement benefit costs. Historically, on an annual basis, approximately 30% of net periodic pension and other postretirement benefit costs are capitalized. PHI estimates that its net periodic pension and other postretirement benefit expense will be approximately $79 million in 2010, as compared to $103 million in 2009 and $44 million in 2008.

Cash Flow Activity

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

	Cash (Use) Source
	2010			2009			Change
	(millions of dollars)
Operating Activities	$	560		$	308		$	252
Investing Activities		949			(590	)		1,539
Financing Activities		(1,511	)		(82	)		(1,429	)
Net decrease in cash and cash equivalents	$	(2	)	$	(364	)	$	362

Operating Activities

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

	Cash (Use) Source
	2010			2009			Change
	(millions of dollars)
Net income from continuing operations	$	125		$	184		$	(59	)
Non-cash adjustments to net income		258			183			75
Pension contributions		(100	)		(300	)		200
Changes in cash collateral related to derivative activities		(23	)		13			(36	)
Changes in other assets and liabilities		116			104			12
Changes in Conectiv Energy net assets held for sale		184			124			60
Net cash from operating activities	$	560		$	308		$	252

Net cash from operating activities was $252 million higher for the nine months ended September 30, 2010, compared to the same period in 2009. Portions of the increase are attributable to a 2010 decrease in pension plan contributions compared to 2009 and a decrease in regulatory liabilities during the nine months ended September 30, 2009 as the result of a lower rate of recovery by ACE of costs associated with energy and capacity purchased under the NUG contracts. Changes in Conectiv Energy net assets held for sale represent the fluctuations in Conectiv Energy assets and liabilities included in discontinued operations, including a decrease in collateral requirements as a result of the liquidation of derivative instruments as further described in Note (15), “Discontinued Operations.”

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Investing Activities

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

	Cash (Use) Source
	2010			2009			Change
	(millions of dollars)
Investment in property, plant and equipment	$	(548	)	$	(446	)	$	(102	)
Proceeds from sale of Conectiv Energy wholesale power generation business		1,635			—			1,635
Changes in restricted cash equivalents		(2	)		(1	)		(1	)
Net other investing activities		2			5			(3	)
Investment in property, plant and equipment associated with Conectiv Energy assets held for sale		(138	)		(148	)		10
Net cash from (used by) investing activities	$	949		$	(590	)	$	1,539

Net cash from investing activities increased $1,539 million for the nine months ended September 30, 2010 compared to the same period in 2009. The increase was due primarily to the July 1, 2010 sale of the Conectiv Energy wholesale power generation business, offset by a $104 million increase in Power Delivery capital expenditures.

Financing Activities

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

	Cash (Use) Source
	2010			2009			Change
	(millions of dollars)
Dividends paid on common stock	$	(181	)	$	(178	)	$	(3	)
Common stock issued for the Dividend Reinvestment Plan		23			23			—
Issuance of common stock		13			14			(1	)
Issuances of long-term debt		102			110			(8	)
Reacquisition of long-term debt		(1,466	)		(75	)		(1,391	)
Issuances of short-term debt, net		10			28			(18	)
Net other financing activities		(2	)		(9	)		7
Net financing activities associated with Conectiv Energy assets held for sale		(10	)		5			(15	)
Net cash used by financing activities	$	(1,511	)	$	(82	)	$	(1,429	)

Net cash related to financing activities decreased $1,429 million for the nine months ended September 30, 2010, compared to the same period in 2009 primarily due to reacquisitions of long-term debt using the proceeds from the sale of the Conectiv Energy wholesale power generation business.

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Changes in Outstanding Long-Term Debt

Cash flows from the issuance and reacquisitions of long-term debt for the nine months ended September 30, 2010 and for the nine months ended September 30, 2009 are summarized in the charts below:

	2010		2009
Issuances	(millions of dollars)
Pepco
6.2% Tax-exempt bonds due 2022 (a)	$	—	$	110
DPL
5.4% Tax-exempt bonds due 2031		78		—
ACE
4.875% Tax-exempt bonds due 2029 (b)		23		—
Pepco Energy Services		1		—
Total issuances of long-term debt	$	102	$	110

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

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

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	2010		2009
Reacquisitions	(millions of dollars)
Pepco
5.75% Tax-exempt bonds due 2010 (a)	$	16	$	—
6.25% Medium-term notes due 2009		—		50
		16		50
DPL
5.5% Tax-exempt bonds due 2025		15		—
5.65% Tax-exempt bonds due 2028		16		—
		31		—
ACE
Securitization bonds due 2009-2010		24		23
7.25% Medium-term notes due 2010		1		—
		25		23
PHI
4.00% Notes due 2010		200		—
Floating Rate Notes due 2010		250		—
6.45% Senior Notes due 2012		750		—
6.125% Senior Notes due 2017		129		—
7.45% Senior Notes due 2032		65		—
		1,394		—
Pepco Energy Services		—		2
Total reacquisition of long-term debt	$	1,466	$	75

(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.

Capital Requirements

Capital Expenditures

Pepco Holdings’ total capital expenditures for the nine months ended September 30, 2010 totaled $548 million, of which $222 million was incurred by Pepco, $191 million was incurred by DPL and $110 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 the December 31, 2009 Form 10-K, PHI presented the projected capital expenditures for each of PHI’s financial reporting segments for the five-year period 2010-2014. The following changes have occurred since the December 31, 2009 Form 10-K:

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• The MAPP in-service date has been revised to June 1, 2015, and accordingly the capital expenditures for MAPP of $24 million for 2010, $246 million for 2011, $317 million for 2012, $297 million for 2013, and $246 million for 2014, have been revised to $30 million for 2010, $163 million for 2011, $362 million for 2012, $304 million for 2013, and $213 million for 2014.

• Future capital expenditures for Conectiv Energy will no longer be incurred due to the sale of the Conectiv Energy wholesale power generation business.

During 2010, Pepco announced its Comprehensive Reliability Enhancement Plans for Maryland and the District of Columbia. The six point reliability plan advances work on existing programs and initiates new activities for customers in Maryland and the District of Columbia. These programs include enhanced vegetation management, priority feeder upgrades, load growth, distribution automation, underground residential cable replacement and selective undergrounding. By focusing on these six areas, Pepco plans to increase the reliability of the distribution system by reducing both the frequency and the duration of power outages. The incremental cost of these reliability improvements throughout Pepco’s Maryland service area is estimated at $100 million, and $90 million within the District of Columbia, over the next five years. However, PHI is in the process of updating its capital plan for 2011-2015, and is determining the impact that these additional reliability improvements may have on the total capital budget over the 2011-2015 period.

Stimulus Funds Related to Blueprint for the Future

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

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

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

In April 2010, PHI and the DOE signed agreements formalizing the $168 million in awards. Of the $168 million, $130 million will offset Blueprint for the Future and other capital expenditures that the PHI subsidiaries are projected to incur. The remaining $38 million will be used to help offset ongoing expenses associated with direct load control and other Power Delivery programs.

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

Smart Grid Workforce Training Grant

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

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

For a discussion of PHI’s third party guarantees, indemnifications, obligations and off-balance sheet arrangements, see Note (14), “Commitments and Contingencies,” to the consolidated financial statements of PHI included as Part I, Item 1, in this Form 10-Q.

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Dividends

On October 28, 2010, Pepco Holdings’ Board of Directors declared a dividend on common stock of 27 cents per share payable December 31, 2010, to shareholders of record on December 10, 2010. PHI had approximately $1,086 million and $1,268 million of retained earnings free of restrictions at September 30, 2010 and December 31, 2009, respectively.

Energy Contract Net Asset Activity

The following table provides detail on changes in the net asset or liability position of the Competitive Energy business (consisting of both the Pepco Energy Services segment and the former Conectiv Energy segment) with respect to energy commodity contracts for the nine months ended September 30, 2010. The balances in the table are pre-tax and the derivative assets and liabilities reflect netting by counterparty before the impact of collateral.

	Energy Commodity Activities (a)
	(millions of dollars)
Total Fair Value of Energy Contract Net Liabilities at December 31, 2009	$	(328	)
Current period unrealized gains		—
Effective portion of changes in fair value – recorded in Accumulated Other Comprehensive Loss		(114	)
Cash flow hedge ineffectiveness – recorded in income		(2	)
Recognition of realized gains (losses) on settlement of contracts		110
Derivative activity associated with Conectiv Energy		27
Total Fair Value of Energy Contract Net Liabilities at September 30, 2010	$	(307	)
	Total
Detail of Fair Value of Energy Contract Net Liabilities at September 30, 2010 (see above)
Derivative assets (current assets)	$	24
Derivative assets (non-current assets)		7
Derivative assets held for sale		16
Total Fair Value of Energy Contract Assets		47
Derivative liabilities (current liabilities)		(184	)
Derivative liabilities (non-current liabilities)		(22	)
Derivative liabilities held for sale		(148	)
Total Fair Value of Energy Contract Liabilities		(354	)
Total Fair Value of Energy Contract Net Liabilities	$	(307	)

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

The $307 million net liability on energy contracts at September 30, 2010 was primarily attributable to losses on power swaps and natural gas futures and swaps designated as hedges of future energy purchases or production under FASB guidance on derivatives and hedging (ASC 815). Prices of electricity and natural gas declined during the first nine months of 2010, which resulted in unrealized losses on the energy contracts of the Competitive Energy business. Competitive Energy recorded unrealized losses of $114 million on energy contracts in Accumulated Other Comprehensive Loss as these energy contracts were effective hedges under the guidance. When these energy contracts settle, the related realized gains or losses are expected to be largely offset by the realized loss or gain on future energy purchases or production that will be used to settle the sales obligations of the Competitive Energy business with their customers.

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PHI uses its best estimates to determine the fair value of the commodity and derivative contracts that are held and sold by its Competitive Energy business. The fair values in each category presented below reflect forward prices and volatility factors as of September 30, 2010 and are subject to change as a result of changes in these factors.

	Fair Value of Contracts at September 30, 2010 Maturities
Source of Fair Value	2010			2011			2012			2013 and Beyond			Total Fair Value
	(millions of dollars)
Energy Commodity Activities, net (a)
Actively Quoted (i.e., exchange-traded) prices	$	(34	)	$	(57	)	$	(21	)	$	(7	)	$	(119	)
Prices provided by other external sources (b)		(56	)		(92	)		(43	)		(5	)		(196	)
Modeled (c)		6			—			—			2			8
Total	$	(84	)	$	(149	)	$	(64	)	$	(10	)	$	(307	)

Notes:

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

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

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

Contractual Arrangements with Credit Rating Triggers or Margining Rights

Under certain contractual arrangements entered into by PHI’s subsidiaries in connection with the Competitive Energy business (consisting of both the Pepco Energy Services segment and the former Conectiv Energy segment) and other transactions, the subsidiary may be required to provide cash collateral or letters of credit as security for its contractual obligations if the credit ratings of the subsidiary are downgraded. In the event of a downgrade, the amount required to be posted would depend on the amount of the underlying contractual obligation existing at the time of the downgrade. Based on contractual provisions in effect at September 30, 2010, a downgrade in the unsecured debt credit ratings of PHI and each of its rated subsidiaries to below “investment grade” would increase the collateral obligation of PHI and its subsidiaries by up to $397 million, $69 million of which is related to discontinued operations, and $213 million of which is the net settlement amount attributable to derivatives, normal purchase and normal sale contracts, collateral, and other contracts under master netting agreements as described in Note (12), “Derivative Instruments and Hedging Activities” to the consolidated financial statements of PHI set forth in Part I, Item 1 of this Form 10-Q. The remaining $115 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

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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 September 30, 2010, Pepco Holdings’ subsidiaries engaged in Competitive Energy activities and Default Electricity Supply activities provided net cash collateral in the amount of $322 million in connection with these activities.

Regulatory And Other Matters

For a discussion of material pending matters such as regulatory and legal proceedings, and other commitments and contingencies, see Note (14), “Commitments and Contingencies,” to the consolidated financial statements of PHI set forth in Part I, Item 1 of this Form 10-Q.

Critical Accounting Policies

For a discussion of Pepco Holdings’ critical accounting policies, please refer to Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations in Pepco Holdings’ Annual Report on Form 10-K for the year ended December 31, 2009, as revised and superseded by PHI’s Form 8-K filed on September 17, 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:

• Prevailing governmental policies and regulatory actions affecting the energy industry, including allowed rates of return, industry and rate structure, acquisition and disposal of assets and facilities, operation and construction of transmission and distribution facilities, and the recovery of purchased power expenses;

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

• Weather conditions;

• Population growth rates and demographic patterns;

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

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

• Changes in accounting standards or practices;

• Changes in project costs;

• Unanticipated changes in operating expenses and capital expenditures;

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

• Rules and regulations imposed by Federal and/or state regulatory commissions, PJM, the North American Electric Reliability Corporation and other applicable electric reliability organizations;

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

• Pace of entry into new markets;

• Volatility in customer demand for electricity and natural gas;

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

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

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

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

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

Potomac Electric Power Company

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

General Overview

Pepco is engaged in the transmission and distribution of electricity in the District of Columbia and major portions of Montgomery County and Prince George’s County in suburban Maryland. Pepco also provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its service territories who do not elect to purchase electricity from a competitive energy supplier. Default Electricity Supply is known as Standard Offer Service in both the District of Columbia and Maryland. Pepco’s service territory covers approximately 640 square miles and has a population of approximately 2.2 million. As of September 30, 2010, approximately 57% of delivered electricity sales were to Maryland customers and approximately 43% were to District of Columbia customers.

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

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

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

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Results Of Operations

The following results of operations discussion compares the nine months ended September 30, 2010 to the nine months ended September 30, 2009. All amounts in the tables (except sales and customers) are in millions of dollars.

Operating Revenue

	2010		2009		Change
Regulated T&D Electric Revenue	$	812	$	725	$	87
Default Electricity Supply Revenue		958		993		(35	)
Other Electric Revenue		27		25		2
Total Operating Revenue	$	1,797	$	1,743	$	54

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

Regulated T&D Electric Revenue includes revenue from the delivery of electricity, including the delivery of Default Electricity Supply, to Pepco’s customers within its service territory at regulated rates. Regulated T&D Electric Revenue also includes transmission service revenue that Pepco receives as a transmission owner from PJM Interconnection, LLC (PJM) at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.

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

Regulated T&D Electric Revenue	2010		2009		Change
Residential	$	242	$	212	$	30
Commercial and industrial		480		435		45
Other		90		78		12
Total Regulated T&D Electric Revenue	$	812	$	725	$	87

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

Regulated T&D Electric Sales (Gigawatt hours (GWh))	2010		2009		Change
Residential		6,572		5,995		577
Commercial and industrial		14,564		14,229		335
Other		113		114		(1	)
Total Regulated T&D Electric Sales		21,249		20,338		911
Regulated T&D Electric Customers (in thousands)	2010		2009		Change
Residential		709		695		14
Commercial and industrial		74		73		1
Other		—		—		—
Total Regulated T&D Electric Customers		783		768		15

Regulated T&D Electric Revenue increased by $87 million primarily due to:

• An increase of $42 million due to higher pass-through revenue (which is substantially offset by a corresponding increase in Other Taxes) primarily the result of rate increases in Montgomery County, Maryland utility taxes that are collected by Pepco on behalf of the county.

• An increase of $11 million in transmission revenue primarily attributable to (i) the accrual of a true-up to reflect costs incurred in the June 2009 through May 2010 service period that were included in the final determination of the network service transmission rate effective June 1, 2010 through May 31, 2011, which includes rate adjustments for the true-up and (ii) other transmission rate increases.

• An increase of $9 million due to higher sales in the District of Columbia service territory as a result of warmer weather during the 2010 spring and summer months as compared to 2009. The BSA was not implemented in the District of Columbia until November 2009; therefore, a change in weather was a factor when comparing revenue from period to period.

• An increase of $8 million due to distribution rate increases in the District of Columbia that became effective in November 2009, March 2010 and July 2010.

• An increase of $7 million due to customer growth of 2% primarily in the residential class in 2010.

• An increase of $7 million due to the implementation of the EmPower Maryland (demand side management program) surcharge rate in March 2010 (which is substantially offset by a corresponding increase in Depreciation and Amortization).

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Default Electricity Supply

Default Electricity Supply Revenue	2010		2009		Change
Residential	$	702	$	670	$	32
Commercial and industrial		246		316		(70	)
Other		10		7		3
Total Default Electricity Supply Revenue	$	958	$	993	$	(35	)
Default Electricity Supply Sales (GWh)	2010		2009		Change
Residential		6,002		5,623		379
Commercial and industrial		2,435		2,996		(561	)
Other		7		7		—
Total Default Electricity Supply Sales		8,444		8,626		(182	)
Default Electricity Supply Customers (in thousands)	2010		2009		Change
Residential		652		652		—
Commercial and industrial		49		50		(1	)
Other		—		—		—
Total Default Electricity Supply Customers		701		702		(1	)

Default Electricity Supply Revenue decreased by $35 million primarily due to:

• A decrease of $69 million due to lower sales, primarily as a result of commercial customer migration to competitive suppliers.

• A decrease of $22 million as a result of lower Default Electricity Supply rates.

The aggregate amount of these decreases was partially offset by:

• An increase of $60 million due to higher sales as a result of warmer weather during the 2010 spring and summer months as compared to 2009.

The following table shows the percentages of Pepco’s total distribution sales by jurisdictions that are derived from customers receiving Default Electricity Supply from Pepco. Amounts are for the nine months ended September 30.

	2010			2009
Sales to District of Columbia customers		30	%		33	%
Sales to Maryland customers		48	%		50	%

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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 $40 million to $932 million in 2010 from $972 million in 2009 primarily due to:

• A decrease of $73 million primarily due to commercial customer migration to competitive suppliers.

• A decrease of $31 million in deferred electricity expense as a result of both (i) a lower rate of recovery due to lower Default Electricity Supply revenue rates and (ii) an increase in costs due to higher average electricity costs under Default Electricity Supply contracts.

The aggregate amount of these decreases was partially offset by:

• An increase of $53 million due to higher sales as a result of warmer weather during the 2010 spring and summer months as compared to 2009.

• An increase of $12 million due to higher average electricity costs under Default Electricity Supply contracts.

Other Operation and Maintenance

Other Operation and Maintenance increased by $8 million to $252 million in 2010 from $244 million in 2009. Excluding an increase of $3 million primarily related to bad debt expenses that are deferred and recoverable in Default Electricity Supply Revenue, Other Operation and Maintenance expense increased by $5 million. The $5 million increase was primarily due to:

• An increase of $22 million in emergency restoration costs primarily due to severe storms in February, July and August 2010. A portion of the costs of the restoration work for the summer storms relates to services provided by outside contractors and other utilities that were not billed as of September 30, 2010, and accordingly have been estimated. These estimates are subject to adjustment when the actual billings are received in the fourth quarter of 2010. The actual billings may vary from the estimates of such billings.

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

The aggregate amount of these increases was partially offset by:

• A decrease of $11 million primarily due to adjustments for (i) February 2010 severe winter storm costs and (ii) distribution rate case costs that previously were charged to other operation and maintenance expense. The adjustments were recorded in accordance with a MPSC rate order issued in August 2010 and a DCPSC rate order issued in February 2010, respectively, allowing for the recovery of the costs.

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

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Restructuring Charge

With the ongoing wind down of the retail energy supply business of Pepco Energy Services and the disposition of Conectiv Energy, PHI is repositioning itself as a regulated transmission and distribution company. In connection with this repositioning, PHI commenced a comprehensive organizational review in the second quarter of 2010 to identify opportunities to streamline the organization and to achieve certain reductions in corporate overhead costs that are allocated to its operating segments. This review has resulted in the adoption of a phased restructuring plan (the plan). PHI began implementing the initial phase of the plan during the third quarter, identifying 165 positions that will be eliminated during the fourth quarter of 2010. The second phase of the plan has also commenced, which will focus on identifying additional cost reduction opportunities through process improvements and operational efficiencies. PHI currently estimates that the implementation of the plan will result in an annual reduction of at least $20 million in corporate overhead costs.

Pursuant to the plan, Pepco recorded a pre-tax restructuring charge of $6 million for the three and nine months ended September 30, 2010, related to severance and health and welfare benefits to be provided to terminated employees.

Under Financial Accounting Standards Board guidance on exit or disposal cost obligations (Accounting Standards Codification 420), certain severance costs are being recognized over the remaining service periods for certain employees to be terminated under the restructuring plan. Generally, the remaining service periods are expected to end by December 31, 2010 and, accordingly, Pepco expects to record an additional $2 million of employee severance and health and welfare benefits in the fourth quarter of 2010. Pepco may incur further severance costs if additional positions are identified for elimination. Pepco may incur other restructuring charges for employee termination benefits and other cost reduction efforts as part of the implementation of the plan.

Depreciation and Amortization

Depreciation and Amortization expenses increased by $13 million to $121 million in 2010 from $108 million in 2009 primarily due to:

• An increase of $6 million in amortization of regulatory assets primarily due to the EmPower Maryland surcharge rate that became effective in March 2010 (which is substantially offset by a corresponding increase in Regulated T&D Electric Revenue).

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

Other Taxes

Other Taxes increased by $43 million to $273 million in 2010 from $230 million in 2009. The increase (which is substantially offset by a corresponding increase in Regulated T&D Electric Revenue) was primarily due to increased pass-throughs resulting from rate increases in utility taxes imposed by Montgomery County, Maryland.

Effects of Pepco Divestiture-Related Claims

District of Columbia Divestiture Case

As further described in Note (10), “Commitments and Contingencies,” the DCPSC on May 18, 2010 issued an order addressing all of the outstanding issues relating to Pepco’s obligation 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 order disallowed certain items that Pepco had included in the costs it deducted in calculating the net proceeds of the sale. The disallowance of these costs, together with interest, increased

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the aggregate amount Pepco is required to distribute to customers by approximately $11 million. While Pepco has filed an appeal of the DCPSC’s decision with the District of Columbia Court of Appeals, in view of the DCPSC order, PHI recognized a pre-tax expense of $11 million for the nine months ended September 30, 2010. PHI intends to continue to pursue its appeal.

Settlement of Mirant Bankruptcy Claims

As further described in Note (10), “Commitments and Contingencies,” in March 2009, the DCPSC approved an allocation between Pepco and its District of Columbia customers of the District of Columbia portion of the Mirant Corporation (Mirant) bankruptcy settlement proceeds. As a result, Pepco recorded a pre-tax gain of $14 million in the first quarter of 2009 reflecting the District of Columbia proceeds retained by Pepco. In July 2009, the MPSC approved an allocation between Pepco and its Maryland customers of the Maryland portion of the Mirant bankruptcy settlement proceeds. As a result, Pepco recorded a pre-tax gain of $26 million in the third quarter of 2009 reflecting the Maryland proceeds retained by Pepco.

Other Income (Expenses)

Other Expenses (which are net of Other Income) decreased by $5 million to a net expense of $63 million in 2010 from a net expense of $68 million in 2009. The decrease was primarily due to:

• An increase of $3 million in other income due to gains on the sale of four parcels of land in 2010.

• An increase of $2 million in income related to Allowance for Funds Used During Construction that is applied to capital projects.

Income Tax Expense

Pepco’s effective tax rates for the nine months ended September 30, 2010 and 2009 were 44.6% and 41.6%, respectively. The increase in the effective tax rate primarily results from the reversal of $2 million of previously recorded tax benefits related to changes in estimates and interest related to uncertain and effectively settled tax positions.

Capital Requirements

Capital Expenditures

Pepco’s capital expenditures for the nine months ended September 30, 2010, totaled $222 million. These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission.

Reliability Enhancement Plans

During 2010, Pepco announced its Comprehensive Reliability Enhancement Plans for Maryland and the District of Columbia. The six point reliability plan advances work on existing programs and initiates new activities for customers in Maryland and the District of Columbia. These programs include enhanced vegetation management, priority feeder upgrades, load growth, distribution automation, underground residential cable replacement and selective undergrounding. By focusing on these six areas, Pepco plans to increase the reliability of the distribution system by reducing both the frequency and the duration of power outages. The incremental cost of these reliability improvements throughout Pepco’s Maryland service area is estimated at $100 million, and $90 million within the District of Columbia, over the next five years. However, PHI is in the process of updating its capital plan for 2011-2015, and is determining the impact that these additional reliability improvements may have on the total capital budget over the 2011-2015 period.

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Stimulus Funds Related to Blueprint for the Future

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

In April 2010, PHI and the DOE signed agreements formalizing Pepco’s $149 million share of the $168 million award. Of the $149 million, $118 million will offset Blueprint for the Future and other capital expenditures that Pepco is projected to incur. The remaining $31 million will be used to help offset ongoing expenses associated with direct load control and other programs.

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

Forward-Looking Statements

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

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

• Prevailing governmental policies and regulatory actions affecting the energy industry, including allowed rates of return, industry and rate structure, acquisition and disposal of assets and facilities, operation and construction of transmission and distribution facilities, and the recovery of purchased power expenses;

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

• Weather conditions;

• Population growth rates and demographic patterns;

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

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

• Changes in accounting standards or practices;

• Changes in project costs;

• Unanticipated changes in operating expenses and capital expenditures;

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

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• Rules and regulations imposed by federal and/or state regulatory commissions, PJM, the North American Electric Reliability Corporation and other applicable electric reliability organizations;

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

• Volatility in customer demand for electricity;

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

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

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

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

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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 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 September 30, 2010, approximately 66% of delivered electricity sales were to Delaware customers and approximately 34% were to Maryland customers. In northern Delaware, DPL also supplies and distributes natural gas to retail customers and provides transportation-only services to retail customers that purchase natural gas from other suppliers. DPL’s natural gas distribution service territory covers approximately 275 square miles and has a population of approximately 500,000.

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

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

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Results Of Operations

The following results of operations discussion compares the nine months ended September 30, 2010 to the nine months ended September 30, 2009. All amounts in the tables (except sales and customers) are in millions of dollars.

Electric Operating Revenue

	2010		2009		Change
Regulated T&D Electric Revenue	$	279	$	259	$	20
Default Electricity Supply Revenue		607		606		1
Other Electric Revenue		15		18		(3	)
Total Electric Operating Revenue	$	901	$	883	$	18

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

Regulated T&D Electric Revenue includes revenue from the delivery of electricity, including the delivery of Default Electricity Supply, to DPL’s customers within its service territory at regulated rates. Regulated T&D Electric Revenue also includes transmission service revenue that DPL receives as a transmission owner from PJM Interconnection, LLC (PJM) at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.

Default Electricity Supply Revenue is the revenue received from the supply of electricity by DPL at regulated rates to retail customers who do not elect to purchase electricity from a competitive energy supplier, and which is also known as Standard Offer Service. 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

Regulated T&D Electric Revenue	2010		2009		Change
Residential	$	139	$	125	$	14
Commercial and industrial		81		76		5
Other		59		58		1
Total Regulated T&D Electric Revenue	$	279	$	259	$	20

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

Regulated T&D Electric Sales (Gigawatt hours (GWh))	2010		2009		Change
Residential		4,186		3,848		338
Commercial and industrial		5,615		5,693		(78	)
Other		37		38		(1	)
Total Regulated T&D Electric Sales		9,838		9,579		259
Regulated T&D Electric Customers (in thousands)	2010		2009		Change
Residential		440		438		2
Commercial and industrial		59		59		—
Other		1		1		—
Total Regulated T&D Electric Customers		500		498		2

Regulated T&D Electric Revenue increased by $20 million primarily due to:

• An increase of $10 million due to distribution rate increases in Maryland effective December 2009 and in Delaware effective April 2010.

• An increase of $6 million due to higher sales as a result of warmer weather during the 2010 spring and summer months as compared to 2009.

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

Default Electricity Supply

Default Electricity Supply Revenue	2010		2009		Change
Residential	$	459	$	434	$	25
Commercial and industrial		140		166		(26	)
Other		8		6		2
Total Default Electricity Supply Revenue	$	607	$	606	$	1
Default Electricity Supply Sales (GWh)	2010		2009		Change
Residential		4,081		3,771		310
Commercial and industrial		1,482		1,585		(103	)
Other		29		31		(2	)
Total Default Electricity Supply Sales		5,592		5,387		205

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Default Electricity Supply Customers (in thousands)	2010		2009		Change
Residential		429		430		(1	)
Commercial and industrial		46		47		(1	)
Other		1		1		—
Total Default Electricity Supply Customers		476		478		(2	)

Default Electricity Supply Revenue increased by $1 million primarily due to:

• An increase of $29 million due to higher sales as a result of warmer weather during the 2010 spring and summer months as compared to 2009.

• An increase of $18 million due to higher non-weather related average customer usage.

The aggregate amount of these increases was partially offset by:

• A decrease of $24 million due to lower sales, primarily as a result of Delaware commercial and Maryland residential customer migration to competitive suppliers.

• A decrease of $23 million as a result of lower Default Electricity Supply rates.

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 nine months ended September 30:

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

Natural Gas Operating Revenue

	2010		2009		Change
Regulated Gas Revenue	$	127	$	169	$	(42	)
Other Gas Revenue		39		30		9
Total Natural Gas Operating Revenue	$	166	$	199	$	(33	)

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

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Regulated Gas

Regulated Gas Revenue	2010		2009		Change
Residential	$	78	$	103	$	(25	)
Commercial and industrial		44		60		(16	)
Transportation and other		5		6		(1	)
Total Regulated Gas Revenue	$	127	$	169	$	(42	)
Regulated Gas Sales (billion cubic feet)	2010		2009		Change
Residential		5		6		(1	)
Commercial and industrial		3		4		(1	)
Transportation and other		5		4		1
Total Regulated Gas Sales		13		14		(1	)
Regulated Gas Customers (in thousands)	2010		2009		Change
Residential		113		113		—
Commercial and industrial		10		9		1
Transportation and other		—		—		—
Total Regulated Gas Customers		123		122		1

Regulated Gas Revenue decreased by $42 million primarily due to:

• A decrease of $32 million due to lower sales as a result of milder weather during the 2010 winter months as compared to 2009.

• A decrease of $22 million due to Gas Cost Rate decreases effective March 2009 and November 2009.

The aggregate amount of these decreases was partially offset by:

• An increase of $11 million due to higher non-weather related average customer usage.

Other Gas Revenue

Other Gas Revenue increased by $9 million primarily due to higher revenue from off-system sales resulting from:

• An increase of $5 million due to higher demand from electric generators and gas marketers.

• An increase of $3 million due to higher market prices.

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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 $6 million to $585 million in 2010 from $591 million in 2009 primarily due to:

• A decrease of $18 million in deferred electricity expense primarily as a result of a lower rate of recovery due to lower Default Electricity Supply revenue rates.

• A decrease of $10 million due to lower average electricity costs under Default Electricity Supply contracts.

• A decrease of $4 million primarily due to lower non-weather related average customer usage.

The aggregate amount of these decreases was partially offset by:

• An increase of $26 million due to higher sales as a result of warmer weather during the 2010 spring and summer months as compared to 2009.

Gas Purchased

Gas Purchased consists of the cost of gas purchased by DPL to fulfill its obligation to regulated gas customers and, as such, is recoverable from customers in accordance with the terms of public service commission orders. It also includes the cost of gas purchased for off-system sales. Total Gas Purchased decreased by $30 million to $117 million in 2010 from $147 million in 2009 primarily due to:

• A decrease of $21 million in deferred gas expense as a result of a lower rate of recovery of natural gas supply costs.

• A decrease of $13 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 increased by $9 million to $191 million in 2010 from $182 million in 2009. Excluding an increase of $3 million primarily related to administrative expenses that are deferred and recoverable in Default Electricity Supply Revenue, Other Operation and Maintenance expense increased by $6 million. The $6 million increase was primarily due to:

• An increase of $4 million in emergency restoration costs primarily due to the February 2010 severe winter storms.

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

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• An increase of $2 million due to higher corrective and preventative maintenance costs.

The aggregate amount of these increases was partially offset by:

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

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

Restructuring Charge

With the ongoing wind down of the retail energy supply business of Pepco Energy Services and the disposition of Conectiv Energy, PHI is repositioning itself as a regulated transmission and distribution company. In connection with this repositioning, PHI commenced a comprehensive organizational review in the second quarter of 2010 to identify opportunities to streamline the organization and to achieve certain reductions in corporate overhead costs are previously allocated to its operating segments. This review has resulted in the adoption of a phased restructuring plan (the plan). PHI began implementing the initial phase of the plan during the third quarter, identifying 165 positions that will be eliminated during the fourth quarter of 2010. The second phase of the plan has also commenced, which will focus on identifying additional cost reduction opportunities through process improvements and operational efficiencies. PHI currently estimates that the implementation of the plan will result in an annual reduction of at least $20 million in corporate overhead costs.

Pursuant to the plan, DPL recorded a pre-tax restructuring charge of $4 million for the three and nine months ended September 30, 2010, related to severance and health and welfare benefits to be provided to terminated employees.

Under Financial Accounting Standards Board guidance on exit or disposal cost obligations (Accounting Standards Codification 420), certain severance costs are being recognized over the remaining service periods for certain employees to be terminated under the restructuring plan. Generally, the remaining service periods are expected to end by December 31, 2010 and, accordingly, DPL expects to record an additional $1 million of employee severance and health and welfare benefits in the fourth quarter of 2010. DPL may incur further severance costs if additional positions are identified for elimination. DPL may incur other restructuring charges for employee termination benefits and other cost reduction efforts as part of the implementation of the plan.

Depreciation and Amortization

Depreciation and Amortization expenses increased by $6 million to $62 million in 2010 from $56 million in 2009 primarily due to:

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

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

Other Income (Expenses)

Other Expenses (which are net of Other Income) decreased by $4 million to a net expense of $28 million in 2010 from a net expense of $32 million in 2009. The decrease was primarily due to an increase of $3 million in income related to Allowance for Funds Used During Construction that is applied to capital projects.

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Income Tax Expense

DPL’s effective tax rates for the nine months ended September 30, 2010 and 2009 were 44.2% and 14.9%, respectively. The increase in the rate resulted from the change in estimates and interest related to uncertain and effectively settled tax positions, primarily related to the $2 million reversal of accrued interest income on state income tax positions in 2010 that DPL no longer believes is more likely than not to be realized and the tax benefits related to the filing of the amended state income tax returns recorded in 2009.

Capital Requirements

Capital Expenditures

DPL’s capital expenditures for the nine months ended September 30, 2010, totaled $191 million. These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission.

Forward-Looking Statements

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

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

• Prevailing governmental policies and regulatory actions affecting the energy industry, including allowed rates of return, industry and rate structure, acquisition and disposal of assets and facilities, operation and construction of transmission and distribution facilities, and the recovery of purchased power expenses;

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

• Weather conditions;

• Population growth rates and demographic patterns;

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

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

• Changes in accounting standards or practices;

• Changes in project costs;

• Unanticipated changes in operating expenses and capital expenditures;

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

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• Rules and regulations imposed by federal and/or state regulatory commissions, PJM, the North American Electric Reliability Corporation and other applicable electric reliability organizations;

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

• Volatility in customer demand for electricity and natural gas;

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

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

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

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

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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 nine months ended September 30, 2010 to the nine months ended September 30, 2009. All amounts in the tables (except sales and customers) are in millions of dollars.

Operating Revenue

	2010		2009		Change
Regulated T&D Electric Revenue	$	322	$	279	$	43
Default Electricity Supply Revenue		815		780		35
Other Electric Revenue		13		13		—
Total Operating Revenue	$	1,150	$	1,072	$	78

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

Regulated T&D Electric Revenue includes revenue from the delivery of electricity, including the delivery of Default Electricity Supply, to ACE’s customers within its service territory at regulated rates. Regulated T&D Electric Revenue also includes transmission service revenue that ACE receives as a transmission owner from PJM Interconnection, LLC (PJM) at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.

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

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Charges (revenue ACE receives, and pays to Atlantic City Electric Transition Funding LLC (ACE Funding)), to fund the principal and interest payments on Transition Bonds issued by ACE Funding (and related taxes, expenses and fees), other restructuring related revenues, and transmission enhancement credits that ACE receives as a transmission owner from PJM for approved regional transmission expansion plan costs.

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

Regulated T&D Electric

Regulated T&D Electric Revenue	2010		2009		Change
Residential	$	148	$	127	$	21
Commercial and industrial		107		100		7
Other		67		52		15
Total Regulated T&D Electric Revenue	$	322	$	279	$	43
Other Regulated T&D Electric Revenue consists primarily of transmission service revenue.
Regulated T&D Electric Sales (Gigawatt hours (GWh))	2010		2009		Change
Residential		3,763		3,376		387
Commercial and industrial		4,136		4,043		93
Other		32		33		(1	)
Total Regulated T&D Electric Sales		7,931		7,452		479
Regulated T&D Electric Customers (in thousands)	2010		2009		Change
Residential		482		481		1
Commercial and industrial		65		65		—
Other		1		1		—
Total Regulated T&D Electric Customers		548		547		1

Regulated T&D Electric Revenue increased by $43 million primarily due to:

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

• An increase of $11 million due to higher sales as a result of warmer weather during the 2010 spring and summer months as compared to 2009.

• An increase of $11 million due to a distribution rate increase that became effective in June 2010.

• An increase of $6 million due to higher non-weather related average customer usage.

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Default Electricity Supply

Default Electricity Supply Revenue	2010		2009		Change
Residential	$	483	$	415	$	68
Commercial and industrial		195		257		(62	)
Other		137		108		29
Total Default Electricity Supply Revenue	$	815	$	780	$	35

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

Default Electricity Supply Sales (GWh)	2010		2009		Change
Residential		3,736		3,376		360
Commercial and industrial		1,575		2,183		(608	)
Other		32		33		(1	)
Total Default Electricity Supply Sales		5,343		5,592		(249	)
Default Electricity Supply Customers (in thousands)	2010		2009		Change
Residential		473		481		(8	)
Commercial and industrial		57		62		(5	)
Other		1		1		—
Total Default Electricity Supply Customers		531		544		(13	)

Default Electricity Supply Revenue increased by $35 million primarily due to:

• An increase of $34 million due to higher sales as a result of warmer weather during the 2010 spring and summer months as compared to 2009.

• An increase of $24 million in wholesale energy and capacity revenues primarily due to higher market prices for the sale of electricity purchased from NUGs.

• An increase of $24 million due to higher non-weather related average customer usage.

• An increase of $19 million as a result of higher Default Electricity Supply rates.

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

The aggregate amount of these increases was partially offset by:

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

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The increase in total Default Electricity Supply Revenue includes an increase of $14 million in unbilled revenue attributable to ACE’s BGS. Under the BGS terms approved by the New Jersey Board of Public Utilities, ACE is entitled to recover from its customers all of its costs of providing BGS. If the costs of providing BGS exceed the BGS revenue, then the excess costs are deferred in Deferred Electric Service Costs. ACE’s BGS unbilled revenue is not included in the deferral calculation, and therefore has an impact on the results of operations in the period during which it is accrued. While the change in the amount of unbilled revenue from year to year typically is not significant, for the nine months ended September 30, 2010, BGS unbilled revenue increased by $14 million as compared to the nine months ended September 30, 2009, which resulted in a $8 million increase in ACE’s net income. The increase was primarily due to higher Default Electricity Supply rates and warmer weather during the unbilled revenue period at the end of the nine months ended September 30, 2010 as compared to the corresponding period in 2009.

For the nine months ended September 30, 2010 and 2009, the percentages of ACE’s total distribution sales that are derived from customers receiving Default Electricity Supply are 67% and 75%, 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 $31 million to $819 million in 2010 from $850 million in 2009 primarily due to:

• A decrease of $78 million due to lower sales, primarily due to commercial and industrial customer migration to competitive suppliers.

The decrease was partially offset by:

• An increase of $40 million due to higher sales as a result of warmer weather during the 2010 spring and summer months as compared to 2009.

• An increase of $6 million due to higher average electricity costs under Default Electricity Supply contracts.

Other Operation and Maintenance

Other Operation and Maintenance increased by $6 million to $151 million in 2010 from $145 million in 2009. Excluding an increase of $5 million primarily related to bad debt expenses and New Jersey Societal Benefit Program costs that are deferred and recoverable, Other Operation and Maintenance expense increased by $1 million. The $1 million increase was primarily due to:

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

• An increase of $2 million due to an adjustment for non-recoverable litigation costs related to ACE’s former interests in certain nuclear power plants in accordance with a May 2010 settlement approved by the New Jersey Board of Public Utilities.

The aggregate amount of these increases was partially offset by:

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

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ACE

Restructuring Charge

With the ongoing wind down of the retail energy supply business of Pepco Energy Services and the disposition of Conectiv Energy, PHI is repositioning itself as a regulated transmission and distribution company. In connection with this repositioning, PHI commenced a comprehensive organizational review in the second quarter of 2010 to identify opportunities to streamline the organization and to achieve certain reductions in corporate overhead costs that are allocated to its operating segments. This review has resulted in the adoption of a phased restructuring plan (the plan). PHI began implementing the initial phase of the plan during the third quarter, identifying 165 positions that will be eliminated during the fourth quarter of 2010. The second phase of the plan has also commenced, which will focus on identifying additional cost reduction opportunities through process improvements and operational efficiencies. PHI currently estimates that the implementation of the plan will result in an annual reduction of at least $20 million in corporate overhead costs.

Pursuant to the plan, ACE recorded a pre-tax restructuring charge of $3 million for the three and nine months ended September 30, 2010, related to severance and health and welfare benefits to be provided to terminated employees.

Under Financial Accounting Standards Board guidance on exit or disposal cost obligations (Accounting Standards Codification 420), certain severance costs are being recognized over the remaining service periods for certain employees to be terminated under the restructuring plan. Generally, the remaining service periods are expected to end by December 31, 2010 and, accordingly, ACE expects to record an additional $1 million of employee severance and health and welfare benefits in the fourth quarter of 2010. ACE may incur further severance costs if additional positions are identified for elimination. ACE may incur other restructuring charges for employee termination benefits and other cost reduction efforts as part of the implementation of the plan.

Deferred Electric Service Costs

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

Deferred Electric Service Costs increased by $47 million, to an expense reduction of $69 million in 2010 as compared to an expense reduction of $116 million in 2009, primarily due to an increase in deferred electricity expense as a result of lower electricity supply costs.

Income Tax Expense

ACE’s consolidated effective tax rates for the nine months ended September 30, 2010 and 2009 were 44.3% and 34.0% respectively. The increase in the rate resulted from the reversal of $6 million of accrued interest income on uncertain and effectively settled state income tax positions in 2010 and the $1 million non-recurring adjustment in 2009 to prior year taxes. This increase is partially offset by the impact of certain permanent state tax differences.

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Capital Requirements

Capital Expenditures

ACE’s capital expenditures for the nine months ended September 30, 2010, totaled $110 million. These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission.

Stimulus Funds Related to Blueprint for the Future

In 2009, the U.S. Department of Energy (DOE) announced a $168 million award to PHI under the American Recovery and Reinvestment Act of 2009 for the implementation of direct load control, distribution automation, and communications infrastructure, of which $19 million was for ACE’s service territory.

In April 2010, PHI and the DOE signed agreements formalizing ACE’s $19 million share of the $168 million award. Of the $19 million, $12 million will offset Blueprint for the Future and other capital expenditures that ACE is projected to incur. The remaining $7 million will be used to help offset ongoing expenses associated with direct load control and other programs.

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

Forward-Looking Statements

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

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

• Prevailing governmental policies and regulatory actions affecting the energy industry, including allowed rates of return, industry and rate structure, acquisition and disposal of assets and facilities, operation and construction of transmission and distribution facilities, and the recovery of purchased power expenses;

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

• Weather conditions;

• Population growth rates and demographic patterns;

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

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

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ACE

• Changes in accounting standards or practices;

• Changes in project costs;

• Unanticipated changes in operating expenses and capital expenditures;

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

• Rules and regulations imposed by federal and/or state regulatory commissions, PJM, the North American Electric Reliability Corporation and other applicable electric reliability organizations;

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

• Volatility in customer demand for electricity;

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

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

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

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

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Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Risk management policies for PHI and its subsidiaries are determined by PHI’s Corporate Risk Management Committee, the members of which are PHI’s Chief Risk Officer, Chief Operating Officer, Chief Financial Officer, General Counsel, Chief Information Officer and other senior executives. The Corporate Risk Management Committee monitors interest rate fluctuation, commodity price fluctuation, and credit risk exposure, and sets risk management policies that establish limits on unhedged risk and determine risk reporting requirements. For information about PHI’s derivative activities, other than the information disclosed herein, refer to Note (2), “Significant Accounting Policies – Accounting For Derivatives,” 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, 2009, as revised and superseded by PHI’s Form 8-K filed on September 17, 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, 2009.

Pepco Holdings, Inc.

Commodity Price Risk

The Competitive Energy business (consisting of both the Pepco Energy Services segment and the former Conectiv Energy segment) engages in commodity risk management activities to reduce their financial exposure to changes in the value of their assets and obligations due to commodity price fluctuations. Certain of these risk management activities are conducted using instruments classified as derivatives based on Financial Accounting Standards Board (FASB) guidance on derivatives and hedging (Accounting Standards Codification (ASC) 815). The Competitive Energy business also manages commodity risk with contracts that are not classified as derivatives. The Competitive Energy business’ primary risk management objective is to manage the spread between wholesale and retail sales commitments and the cost of supply used to service those commitments in order to ensure stable and known cash flows and fix favorable prices and margins. Prior to the sale of the wholesale power generation business on July 1, 2010, the risk management objective of the Conectiv Energy segment also included the management of the spread between the cost of fuel used to operate its electric generating facilities and the revenue received from the sale of the power produced by those facilities by selling forward a portion of their projected generating facility output and buying forward a portion of their projected fuel supply requirements.

PHI’s risk management policies place oversight at the senior management level through the Corporate Risk Management Committee, which has the responsibility for establishing corporate compliance requirements for the Competitive Energy business’ energy market participation. PHI collectively refers to these energy market activities, including its commodity risk management activities, as “energy commodity” activities. PHI uses a value-at-risk (VaR) model to assess the market risk of its Competitive Energy business’ energy commodity activities. PHI also uses other measures to limit and monitor risk in its energy commodity activities, including limits on the nominal size of positions and periodic loss limits. VaR represents the potential fair value loss on energy contracts or portfolios due to changes in market prices for a specified time period and confidence level. In January 2009, PHI changed its VaR estimation model from a delta-normal variance / covariance model to a delta-gamma model. The other parameters, a 95 percent, one-tailed confidence level and a one-day holding period, remained the same. Since VaR is an estimate, it is not necessarily indicative of actual results that may occur. The table below provides the VaR associated with energy contracts of both the Pepco Energy Services segment and the former Conectiv Energy segment for the nine months ended September 30, 2010 in millions of dollars:

	VaR for Conectiv Energy Commodity Activities (a)		VaR for Pepco Energy Services Commodity Activities (a)
95% confidence level, one-day holding period, one-tailed
Period end	$	—	$	1
Average for the period	$	1	$	1
High	$	2	$	1
Low	$	—	$	1

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

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Pepco Energy Services purchases electric and natural gas futures, swaps, options and forward contracts to hedge price risk in connection with the purchase of physical natural gas and electricity for delivery to customers. Pepco Energy Services accounts for its futures and swap contracts as cash flow hedges of forecasted transactions. Its options contracts and certain commodity contracts that do not qualify as cash flow hedges are marked-to-market through current earnings. Forward contracts that meet the requirements for normal purchase and normal sale accounting under FASB guidance on derivatives and hedging are accounted for using accrual accounting.

Credit and Nonperformance Risk

The following table provides information on the Competitive Energy business’ credit exposure on competitive wholesale energy contracts, net of collateral, to wholesale counterparties as of September 30, 2010, in millions of dollars:

Rating	Exposure Before Credit Collateral (b)		Credit Collateral (c)		Net Exposure		Number of Counterparties Greater Than 10% (d)		Net Exposure of Counterparties Greater Than 10%
Investment Grade (a)	$	97	$	—	$	97		4	$	58
Non-Investment Grade		—		—		—		—		—
No External Ratings		—		—		—		—		—
Credit reserves						1

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

(b) Exposure before credit collateral - includes the marked-to-market (MTM) energy contract net assets for open/unrealized transactions, the net receivable/payable for realized transactions and net open positions for contracts not subject to MTM. Amounts due from counterparties are offset by liabilities payable to those counterparties to the extent that legally enforceable netting arrangements are in place. Thus, this column presents the net credit exposure to counterparties after reflecting all allowable netting, but before considering collateral held.

(c) Credit collateral - the face amount of cash deposits, letters of credit and performance bonds received from counterparties, not adjusted for probability of default, and, if applicable, property interests (including oil and gas reserves).

(d) Using a percentage of the total exposure.

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For additional information concerning market risk, please refer to Item 3, “Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk” and “Credit and Nonperformance Risk,” and for information regarding “Interest Rate Risk,” please refer to Item 7A, “Quantitative and Qualitative Disclosures About Market Risk,” in Pepco Holdings’ Annual Report on Form 10-K for the year ended December 31, 2009.

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

Item 4. CONTROLS AND PROCEDURES

Pepco Holdings, Inc.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Under the supervision, and with the participation of management, including the chief executive officer and the chief financial officer, Pepco Holdings has evaluated the effectiveness of the design and operation of its disclosure controls and procedures as of September 30, 2010, and, based upon this evaluation, the chief executive officer and the chief financial officer of Pepco Holdings have concluded that these controls and procedures are effective to provide reasonable assurance that material information relating to Pepco Holdings and its subsidiaries that is required to be disclosed in reports filed with, or submitted to, the Securities and Exchange Commission (SEC) under the Securities Exchange Act of 1934, as amended (the Exchange Act) (i) is recorded, processed, summarized and reported within the time periods specified by the SEC rules and forms and (ii) is accumulated and communicated to management, including its chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

During the three months ended September 30, 2010, there was no change in Pepco Holdings’ internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, Pepco Holdings’ internal controls over financial reporting.

Potomac Electric Power Company

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Under the supervision, and with the participation of management, including the chief executive officer and the chief financial officer, Pepco has evaluated the effectiveness of the design and operation of its disclosure controls and procedures as of September 30, 2010, and, based upon this evaluation, the chief executive officer and the chief financial officer of Pepco have concluded that these controls and procedures are effective to provide reasonable assurance that material information relating to Pepco that is required to be disclosed in reports filed with, or submitted to, the SEC under the Exchange Act (i) is recorded, processed, summarized and reported within the time periods specified by the SEC rules and forms and (ii) is accumulated and communicated to management, including its chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

During the three months ended September 30, 2010, there was no change in Pepco’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, Pepco’s internal controls over financial reporting.

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The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act)

The Dodd-Frank Act enacted on July 21, 2010, exempts any company that is not a “large accelerated filer” or an “accelerated filer” (as defined by SEC rules) from the requirement that the company obtain an external audit of the effectiveness of its internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act. As a result, Pepco will be exempt from the requirement that it include in its Annual Report on Form 10-K an attestation report on internal control over financial reporting by an independent registered public accounting firm; however, management’s annual report on internal control over financial reporting, pursuant to Section 404(a) of the Sarbanes-Oxley Act, is still required.

Delmarva Power & Light Company

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Under the supervision, and with the participation of management, including the chief executive officer and the chief financial officer, DPL has evaluated the effectiveness of the design and operation of its disclosure controls and procedures as of September 30, 2010, and, based upon this evaluation, the chief executive officer and the chief financial officer of DPL have concluded that these controls and procedures are effective to provide reasonable assurance that material information relating to DPL that is required to be disclosed in reports filed with, or submitted to, the SEC under the Exchange Act (i) is recorded, processed, summarized and reported within the time periods specified by the SEC rules and forms and (ii) is accumulated and communicated to management, including its chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

During the three months ended September 30, 2010, there was no change in DPL’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, DPL’s internal controls over financial reporting.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act)

The Dodd-Frank Act enacted on July 21, 2010, exempts any company that is not a “large accelerated filer” or an “accelerated filer” (as defined by SEC rules) from the requirement that the company obtain an external audit of the effectiveness of its internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act. As a result, DPL will be exempt from the requirement that it include in its Annual Report on Form 10-K an attestation report on internal control over financial reporting by an independent registered public accounting firm; however, management’s annual report on internal control over financial reporting, pursuant to Section 404(a) of the Sarbanes-Oxley Act, is still required.

Atlantic City Electric Company

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Under the supervision, and with the participation of management, including the chief executive officer and the chief financial officer, ACE has evaluated the effectiveness of the design and operation of its disclosure controls and procedures as of September 30, 2010, and, based upon this evaluation, the chief executive officer and the chief financial officer of ACE have concluded that these controls and procedures are effective to provide reasonable assurance that material information relating to ACE and its subsidiaries that is required to be disclosed in reports filed with, or submitted to, the SEC under the Exchange Act (i) is recorded, processed, summarized and reported within the time periods specified by the SEC rules and forms and (ii) is accumulated and communicated to management, including its chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

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Changes in Internal Control Over Financial Reporting

During the three months ended September 30, 2010, there was no change in ACE’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, ACE’s internal controls over financial reporting.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act)

The Dodd-Frank Act enacted on July 21, 2010, exempts any company that is not a “large accelerated filer” on an “accelerated filer” (as defined by SEC rules) from the requirement that the company obtain an external audit of the effectiveness of its internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act. As a result, ACE will be exempt from the requirement that it include in its Annual Report on Form 10-K an attestation report on internal control over financial reporting by an independent registered public accounting firm; however, management’s annual report on internal control over financial reporting, pursuant to Section 404(a) of the Sarbanes-Oxley Act, is still required.

Part II OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

Pepco Holdings

Other than ordinary routine litigation incidental to its and its subsidiaries’ business, PHI is not a party to, and its subsidiaries’ property is not subject to, any material pending legal proceedings except as described in Note (14), “Commitments and Contingencies—Legal Proceedings,” to the consolidated financial statements of PHI included herein.

Pepco

Other than ordinary routine litigation incidental to its business, Pepco is not a party to, and its property is not subject to, any material pending legal proceedings except as described in Note (10), “Commitments and Contingencies—Legal Proceedings,” to the financial statements of Pepco included herein.

DPL

Other than ordinary routine litigation incidental to its business, DPL is not a party to, and its property is not subject to, any material pending legal proceedings except as described in Note (12), “Commitments and Contingencies—Legal Proceedings,” to the financial statements of DPL included herein.

ACE

Other than ordinary routine litigation incidental to its business, ACE is not a party to, and its property is not subject to, any material pending legal proceedings except as described in Note (10), “Commitments and Contingencies—Legal Proceedings,” to the consolidated financial statements of ACE included herein.

Item 1A. RISK FACTORS

Pepco Holdings

For a discussion of Pepco Holdings’ risk factors, please refer to Item 1A “Risk Factors” in Pepco Holdings’ Annual Report on Form 10-K for the year ended December 31, 2009. There have been no material changes to Pepco Holdings’ risk factors as disclosed in the 10-K, except that:

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

PHI’s Competitive Energy business depends on electric generation and transmission facilities, natural gas pipelines, and natural gas storage facilities owned and operated by others. If the operation of these facilities is disrupted or their capacity is inadequate or unavailable, the ability of the Competitive Energy business to buy and receive and/or sell and deliver wholesale and retail power and natural gas, and

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therefore to fulfill its contractual obligations, could be adversely affected. With the sale of the Conectiv Energy generation assets, upon the completion of the ongoing liquidation of Conectiv Energy’s load supply contracts and hedging portfolio and the completion of the ongoing wind down of Pepco Energy Services’ retail energy supply business, these factors will no longer have the potential for affecting PHI’s results of operations.

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

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

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

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

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

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

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

Historically, both Conectiv Energy and Pepco Energy Services have entered into transactions with numerous counterparties. These include both commercial transactions for the purchase and sale of electricity and natural gas, and derivative and other transactions, to manage the risk of commodity price fluctuations. Under these arrangements, the Competitive Energy business is exposed to the risk that the counterparty may fail to perform its obligation to make or take delivery under the contract, fail to make a required payment or fail to return collateral posted by the Competitive Energy business when no longer required. Under many of these contracts, Conectiv Energy and Pepco Energy Services are entitled to receive collateral or other types of performance assurance from the counterparty, which may be in the form of cash, letters of credit or parent guarantees, to protect against performance and credit risk. Even where collateral is provided, capital market disruptions can prevent the counterparty from meeting its collateral obligations or degrade the value of letters of credit and guarantees as a result of the lowered rating or insolvency of the issuer or guarantor. In the event of a bankruptcy of a counterparty, bankruptcy

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law, in some circumstances, could require Conectiv Energy or Pepco Energy Services to surrender collateral held or payments received. With the sale of Conectiv Energy’s generation assets, upon the completion of the ongoing liquidation of Conectiv Energy’s load supply contracts and hedging portfolio and the deactivation of Pepco Energy Services’ two generating plants (scheduled for May 2012), this risk no longer will be material to the operations of the Competitive Energy business.

Business operations could be adversely affected by terrorism.

The threat of, or actual acts of, terrorism may affect the operations of PHI and its subsidiaries in unpredictable ways and may cause changes in the insurance markets, force an increase in security measures and cause disruptions of fuel supplies and markets. If any of its infrastructure facilities, including its transmission or distribution facilities, were to be a direct target, or an indirect casualty, of an act of terrorism, the operations of PHI, Pepco, DPL or ACE could be adversely affected. Corresponding instability in the financial markets as a result of terrorism also could adversely affect the ability to raise needed capital.

(2) The following risk factor supersedes, as it relates to PHI, the risk factor in the Form 10-K with the heading having as its introductory sentence, “Changes in technology may adversely affect the Power Delivery business and the Competitive Energy business”:

Changes in technology may adversely affect the Power Delivery business

Increased conservation made possible through advances in technology could reduce demand for electricity supply and distribution and advances in technology could alter the channels through which retail electricity is distributed to customers. Such developments could adversely affect the Power Delivery business.

(3) The following risk factor supersedes, as it relates to PHI, the risk factor in the Form 10-K with the heading having as its introductory sentence, “The operations of the Competitive Energy business can give rise to significant collateral requirements”:

The operations of the Competitive Energy business can give rise to significant collateral requirements. (PHI only)

A substantial portion of Pepco Energy Services’ business has been the sale of electricity and natural gas to retail customers. In conducting this business, Pepco Energy Services typically entered into electricity and natural gas sale contracts under which it committed to supply the electricity or natural gas requirements of its retail customers over a specified period at agreed upon prices. To acquire the required energy, Pepco Energy Services entered into wholesale purchase contracts for electricity and natural gas. These contracts typically impose collateral requirements on each party designed to protect the other party against the risk of nonperformance between the date the contract was entered into and the date the energy is paid for. The collateral required to be posted can be of varying forms, including cash, letters of credit and guarantees. When energy market prices decrease relative to the supplier contract prices, Pepco Energy Service’s collateral obligations increase. While Pepco Energy Services no longer enters into new energy supply contracts, it has continuing supply obligations based on prior contracts and corresponding wholesale purchase contracts that extend through 2014. Particularly in periods of energy market price volatility, the collateral obligations associated with the these wholesale purchase contracts can be substantial, although they can be expected to diminish as the Pepco Energy Services retail energy supply business is wound down. These collateral demands could negatively affect PHI’s liquidity by requiring PHI to draw on its capacity under its credit facilities and other financing sources.

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In addition, Conectiv Energy and Pepco Energy Services historically have entered into contracts to buy and sell electricity, various fuels, and related products, including derivative instruments, to reduce their financial exposure to changes in the value of their assets and obligations due to energy price fluctuations. These contracts usually required the posting of collateral. Under certain contracts, the required collateral was provided in the form of an investment grade guaranty issued by PHI. Under these contracts, a reduction in PHI’s credit rating could trigger a requirement to post additional collateral. To satisfy these obligations when required, PHI and its non-utility subsidiaries relied primarily on cash balances, access to the capital markets and existing credit facilities. With the sale of Conectiv Energy’s generation assets, upon the completion of the ongoing liquidation of Conectiv Energy’s load supply contracts and hedging portfolio and the deactivation of Pepco Energy Services’ two generating plants (scheduled for May 2012), these collateral requirements no longer will apply.

(4) The risk factor with the following heading is hereby deleted:

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

Pepco

For a discussion of Pepco’s risk factors, please refer to Item 1A “Risk Factors” in Pepco’s Annual Report on Form 10-K for the year ended December 31, 2009. There have been no material changes to Pepco’s risk factors as disclosed in the 10-K, except that the risk factor with the following heading is hereby deleted:

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

DPL

For a discussion of DPL’s risk factors, please refer to Item 1A “Risk Factors” in DPL’s Annual Report on Form 10-K for the year ended December 31, 2009. There have been no material changes to DPL’s risk factors as disclosed in the 10-K.

ACE

For a discussion of ACE’s risk factors, please refer to Item 1A “Risk Factors” in ACE’s Annual Report on Form 10-K for the year ended December 31, 2009. There have been no material changes to ACE’s risk factors as disclosed in the 10-K.

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

Pepco Holdings

None.

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

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Item 3. DEFAULTS UPON SENIOR SECURITIES

Pepco Holdings

None.

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

Item 4. RESERVED

Item 5. OTHER INFORMATION

Pepco Holdings

None.

Pepco

None.

DPL

None.

ACE

None.

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Item 6. EXHIBITS

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

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
12.1	PHI	Statements Re: Computation of Ratios	Filed herewith.
12.2	Pepco	Statements Re: Computation of Ratios	Filed herewith.
12.3	DPL	Statements Re: Computation of Ratios	Filed herewith.
12.4	ACE	Statements Re: Computation of Ratios	Filed herewith.
31.1	PHI	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	Filed herewith.
31.2	PHI	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	Filed herewith.
31.3	Pepco	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	Filed herewith.
31.4	Pepco	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	Filed herewith.
31.5	DPL	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	Filed herewith.
31.6	DPL	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	Filed herewith.
31.7	ACE	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	Filed herewith.
31.8	ACE	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	Filed herewith.
32.1	PHI	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	Furnished herewith.
32.2	Pepco	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	Furnished herewith.
32.3	DPL	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	Furnished herewith.
32.4	ACE	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	Furnished herewith.
101. INS	PHI, Pepco, DPL, ACE	XBRL Instance Document	Submitted herewith.
101. SCH	PHI, Pepco, DPL, ACE	XBRL Taxonomy Extension Schema Document	Submitted herewith.
101. CAL	PHI, Pepco, DPL, ACE	XBRL Taxonomy Extension Calculation Linkbase Document	Submitted herewith.
101. DEF	PHI, Pepco, DPL, ACE	XBRL Taxonomy Extension Definition Linkbase Document	Submitted herewith.
101. LAB	PHI, Pepco, DPL, ACE	XBRL Taxonomy Extension Label Linkbase Document	Submitted herewith.
101. PRE	PHI, Pepco, DPL, ACE	XBRL Taxonomy Extension Presentation Linkbase Document	Submitted herewith.

186

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)
October 29, 2010	By	/s/    A.J. KAMERICK
		Anthony J. Kamerick
		Senior Vice President and Chief Financial Officer, PHI, Pepco and DPL Chief Financial Officer, ACE

187

INDEX TO EXHIBITS FILED HEREWITH

Exhibit No.	Registrant(s)	Description of Exhibit
12.1	PHI	Statements Re: Computation of Ratios
12.2	Pepco	Statements Re: Computation of Ratios
12.3	DPL	Statements Re: Computation of Ratios
12.4	ACE	Statements Re: Computation of Ratios
31.1	PHI	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer
31.2	PHI	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer
31.3	Pepco	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer
31.4	Pepco	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer
31.5	DPL	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer
31.6	DPL	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer
31.7	ACE	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer
31.8	ACE	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer
INDEX TO EXHIBITS FURNISHED HEREWITH
Exhibit No.	Registrant(s)	Description of Exhibit
32.1	PHI	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350
32.2	Pepco	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350
32.3	DPL	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350
32.4	ACE	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350
101. INS	PHI, Pepco, DPL, ACE	XBRL Instance Document
101. SCH	PHI, Pepco, DPL, ACE	XBRL Taxonomy Extension Schema Document
101. CAL	PHI, Pepco, DPL, ACE	XBRL Taxonomy Extension Calculation Linkbase Document
101. DEF	PHI, Pepco, DPL, ACE	XBRL Taxonomy Extension Definition Linkbase Document
101. LAB	PHI, Pepco, DPL, ACE	XBRL Taxonomy Extension Label Linkbase Document
101. PRE	PHI, Pepco, DPL, ACE	XBRL Taxonomy Extension Presentation Linkbase Document