10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the quarter ended September 30, 2009

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

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

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

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

Pepco Holdings	Yes  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, 2009
Pepco Holdings	221,592,782 ($.01 par value)
Pepco	100 ($.01 par value) (a)
DPL	1,000 ($2.25 par value) (b)
ACE	8,546,017 ($3 par value) (b)

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

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

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

TABLE OF CONTENTS

		Page
	Glossary of Terms	i
PART I	FINANCIAL INFORMATION	1
Item 1.	- Financial Statements	1
Item 2.	- Management’s Discussion and Analysis of Financial Condition and Results of Operations	101
Item 3.	- Quantitative and Qualitative Disclosures About Market Risk	161
Item 4.	- Controls and Procedures	163
Item 4T.	- Controls and Procedures	163
PART II	OTHER INFORMATION	164
Item 1.	- Legal Proceedings	164
Item 1A.	- Risk Factors	165
Item 2.	- Unregistered Sales of Equity Securities and Use of Proceeds	169
Item 3.	- Defaults Upon Senior Securities	169
Item 4.	- Submission of Matters to a Vote of Security Holders	169
Item 5.	- Other Information	170
Item 6.	- Exhibits	171
Signatures		172

GLOSSARY OF TERMS

Term	Definition
2005 Permit	December 2005 Title V operating permit issued by the NJDEP for Deepwater
2008 Permit	January 2008 Title V operating permit issued by the NJDEP for Deepwater
ACE	Atlantic City Electric Company
ACE Funding	Atlantic City Electric Transition Funding LLC
ADITC	Accumulated deferred investment tax credits
Ancillary services	Generally, electricity generation reserves and reliability services
AOCI	Accumulated other comprehensive income
AOCL	Accumulated other comprehensive loss
April 2007 Order	Administrative Order and Notice of Civil Administrative Penalty Assessment concerning Deepwater issued in April 2007 by NJDEP
ASC	Accounting Standards Codification
BGS	Basic Generation Service (the supply of electricity by ACE to retail customers in New Jersey who have not elected to purchase electricity from a competitive supplier)
BSA	Bill Stabilization Adjustment
Cape May Bonds	Series 2004B Pollution Control Revenue Refunding Bonds issued for the benefit of ACE by the Pollution Control Financing Authority of Cape May County
CERCLA	Comprehensive Environmental Response, Compensation, and Liability Act of 1980
Citgo	Citgo Asphalt Refining Company
Conectiv	A wholly owned subsidiary of PHI and the parent of DPL and ACE
Competitive Energy	Competitive energy generation, marketing and supply
Conectiv Energy	Conectiv Energy Holding Company and its subsidiaries
Cooling Degree Days	Daily difference in degrees by which the mean (high and low divided by 2) dry bulb temperature is above a base of 65 degrees Fahrenheit
CSA	Credit Support Annex
Dark spread	The difference between the cost of coal required to produce a unit of electricity and the price of that same unit of electricity
DC OPC	District of Columbia Office of People’s Counsel
DCPSC	District of Columbia Public Service Commission
Default Electricity Supply	The supply of electricity by PHI’s electric utility subsidiaries at regulated rates to retail customers who do not elect to purchase electricity from a competitive supplier, and which, depending on the jurisdiction, is also known as SOS or BGS service
Default Supply Revenue	Revenue received for Default Electricity Supply
Deepwater	Deepwater generating facility
DPL	Delmarva Power & Light Company
DPSC	Delaware Public Service Commission
EBITDA	Earnings before interest, taxes, depreciation, and amortization
EDIT	Excess Deferred Income Taxes
EPA	U.S. Environmental Protection Agency
EPS	Earnings per share
EQR	Conectiv Energy’s Electric Quarterly Report filed with FERC
Exchange Act	Securities Exchange Act of 1934, as amended
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission

i

Term	Definition
FHACA	Flood Hazard Area Control Act
GAAP	Accounting principles generally accepted in the United States of America
GCR	Gas Cost Rate
GWh	Gigawatt hour
Heating Degree Days	Daily difference in degrees by which the mean (high and low divided by 2) dry bulb temperature is below a base of 65 degrees Fahrenheit
IRS	Internal Revenue Service
ISDA	International Swaps and Derivatives Association
ISONE	Independent System Operator - New England
LTIP	Long-Term Incentive Plan
July 2008 Revocation Order	Administrative Order of Revocation and Notice of Civil Administrative Penalty Assessment concerning Deepwater issued in July 2008 by NJDEP
MAPP	Mid-Atlantic Power Pathway
Market Transition Charge Tax	Revenue ACE receives, and pays to ACE Funding to recover income taxes associated with Transition Bond Charge revenue
Maryland OPC	Maryland Office of People’s Counsel
May 2007 Order	The second Administrative Order and Notice of Civil Administrative Penalty Assessment concerning Deepwater issued in May 2007 by NJDEP
MDC	MDC Industries, Inc.
MFVRD	Modified fixed variable rate design
Mirant	Mirant Corporation
MMBtu	One Million British Thermal Units
MSCG	Morgan Stanley Capital Group, Inc.
MPSC	Maryland Public Service Commission
Mwh	Megawatt hour
New Jersey Societal Benefit Charge	Revenue ACE receives to recover certain costs incurred under various NJBPU - mandated social programs
NFA	No Further Action letter issued by the NJDEP
NJBPU	New Jersey Board of Public Utilities
NJDEP	New Jersey Department of Environmental Protection
Normalization provisions	Sections of the Internal Revenue Code and related regulations that dictate how excess deferred income taxes resulting from the corporate income tax rate reduction enacted by the Tax Reform Act of 1986 and accumulated deferred investment tax credits should be treated for ratemaking purposes
NUGs	Non-utility generators
NYDEC	New York Department of Environmental Conservation
OAL	New Jersey Office of Administrative Law
OTTI	Other-than-temporary impairment
Panda	Panda-Brandywine, L.P.
Panda PPA	PPA between Pepco and Panda
PCI	Potomac Capital Investment Corporation and its subsidiaries
Pepco	Potomac Electric Power Company
Pepco Energy Services	Pepco Energy Services, Inc. and its subsidiaries
Pepco Holdings or PHI	Pepco Holdings, Inc.
PHI Retirement Plan	PHI’s noncontributory retirement plan
PJM	PJM Interconnection, LLC
PJM RTO	PJM Regional Transmission Organization

ii

Term	Definition
PM-10	Particulate matter less than 10 microns
Power Delivery	PHI’s Power Delivery Business
PPA	Power Purchase Agreement
PRP	Potentially responsible party
PUHCA 2005	Public Utility Holding Company Act of 2005, which became effective February 8, 2006
RBOB	Reformulated Gasoline Blendstock for Oxygen Blending
QSPE	Qualifying special purpose entity
RECs	Renewable energy credits
RAR	IRS revenue agent’s report
RC Cape May	RC Cape May Holdings, LLC, an affiliate of Rockland Capital Energy Investments, LLC, and the purchaser of the B.L. England generating facility
Regulated T&D Electric Revenue	Revenue from the transmission and the delivery of electricity to PHI’s customers within its service territories at regulated rates
ROE	Return on equity
RPM	Reliability Pricing Model
SEC	Securities and Exchange Commission
Sempra	Sempra Energy Trading LLC
SOS	Standard Offer Service (the supply of electricity by Pepco in the District of Columbia, by Pepco and DPL in Maryland and by DPL in Delaware to retail customers who have not elected to purchase electricity from a competitive supplier)
Spark spread	The difference between the cost of the fuel required to produce a unit of electricity and the price of that same unit of electricity
Spot	Commodities market in which goods are sold for cash and delivered immediately
Stipulation	Stipulation of Partial Settlement entered into by NJDEP and Conectiv Energy in May 2009
Transition Bond Charge	Revenue ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds and related taxes, expenses and fees
Transition Bonds	Transition Bonds issued by ACE Funding
Treasury Rate Locks	A hedging transaction that allows a company to “lock in” a specific interest rate corresponding to the rate of a designated Treasury bond for a determined period of time
TSA	Contract for terminal services between ACE and Citgo
VaR	Value at Risk

iii

PART I FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

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

	Registrants
Item	Pepco Holdings	Pepco*	DPL*	ACE
Consolidated Statements of Income	2	47	64	86
Consolidated Statements of Comprehensive Income	3	N/A	N/A	N/A
Consolidated Balance Sheets	4	48	65	87
Consolidated Statements of Cash Flows	6	50	67	89
Notes to Consolidated Financial Statements	7	51	68	90

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

1

PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
	(millions of dollars, except per share data)
Operating Revenue
Power Delivery	$	1,428		$	1,668		$	3,895		$	4,260
Competitive Energy		1,099			1,379			3,196			4,036
Other		12			13			33			(77	)
Total Operating Revenue		2,539			3,060			7,124			8,219
Operating Expenses
Fuel and purchased energy		1,784			2,124			5,162			5,774
Other services cost of sales		92			209			270			569
Other operation and maintenance		240			241			713			691
Depreciation and amortization		103			99			294			283
Other taxes		101			100			282			273
Deferred electric service costs		(32	)		12			(116	)		20
Effect of settlement of Mirant bankruptcy claims		(26	)		—			(40	)		—
Gain on sale of assets		—			—			—			(3	)
Total Operating Expenses		2,262			2,785			6,565			7,607
Operating Income		277			275			559			612
Other Income (Expenses)
Interest and dividend income		—			4			3			16
Interest expense		(93	)		(82	)		(279	)		(243	)
Gain (Loss) from equity investments		1			(1	)		2			(3	)
Other income		4			4			12			14
Other expenses		—			(1	)		(1	)		(2	)
Total Other Expenses		(88	)		(76	)		(263	)		(218	)
Income Before Income Tax Expense		189			199			296			394
Income Tax Expense		65			80			102			161
Net Income		124			119			194			233
Retained Earnings at Beginning of Period		1,222			1,198			1,271			1,193
Dividends Paid on Common Stock (Note 14)		(59	)		(54	)		(178	)		(163	)
Retained Earnings at End of Period	$	1,287		$	1,263		$	1,287		$	1,263
Basic and Diluted Share Information
Weighted average shares outstanding		221			202			220			201
Earnings per share of common stock	$	.56		$	.59		$	.88		$	1.16

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,
	2009			2008			2009			2008
	(millions of dollars)
Net income	$	124		$	119		$	194		$	233
Gains (losses) on commodity derivatives designated as cash flow hedges:
Losses arising during period		(14	)		(675	)		(296	)		(36	)
Less: amount of (losses) gains reclassified into income		(97	)		11			(309	)		93
Net gains (losses) on commodity derivatives		83			(686	)		13			(129	)
Losses on Treasury Rate Locks reclassified into income		1			1			4			4
Amortization of gains and losses for prior service costs		—			—			(10	)		(5	)
Other comprehensive income (loss), before income taxes		84			(685	)		7			(130	)
Income tax expense (benefit)		34			(278	)		3			(52	)
Other comprehensive income (loss), net of income taxes		50			(407	)		4			(78	)
Comprehensive income (loss)	$	174		$	(288	)	$	198		$	155

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, 2009			December 31, 2008
	(millions of dollars)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	20		$	384
Restricted cash equivalents		11			10
Accounts receivable, less allowance for uncollectible accounts of $46 million and $37 million, respectively		1,184			1,392
Inventories		286			333
Derivative assets		62			98
Prepayments of income taxes		365			294
Prepaid expenses and other		111			87
Total Current Assets		2,039			2,598
INVESTMENTS AND OTHER ASSETS
Goodwill		1,411			1,411
Regulatory assets		1,951			2,088
Investment in finance leases held in trust		1,376			1,335
Income taxes receivable		128			23
Restricted cash equivalents		4			108
Assets and accrued interest related to uncertain tax positions		12			32
Derivative assets		27			9
Other		208			215
Total Investments and Other Assets		5,117			5,221
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		13,476			12,926
Accumulated depreciation		(4,802	)		(4,612	)
Net Property, Plant and Equipment		8,674			8,314
TOTAL ASSETS	$	15,830		$	16,133

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, 2009			December 31, 2008
	(millions of dollars, except shares)
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Short-term debt	$	493		$	465
Current maturities of long-term debt and project funding		534			85
Accounts payable and accrued liabilities		634			847
Capital lease obligations due within one year		7			6
Taxes accrued		58			62
Interest accrued		93			71
Liabilities and accrued interest related to uncertain tax positions		1			47
Derivative liabilities		125			144
Other		289			275
Total Current Liabilities		2,234			2,002
DEFERRED CREDITS
Regulatory liabilities		662			893
Deferred income taxes, net		2,505			2,269
Investment tax credits		37			40
Pension benefit obligation		399			626
Other postretirement benefit obligations		451			461
Income taxes payable		1			8
Liabilities and accrued interest related to uncertain tax positions		110			17
Derivative liabilities		63			59
Other		155			184
Total Deferred Credits		4,383			4,557
LONG-TERM LIABILITIES
Long-term debt		4,470			4,859
Transition bonds issued by ACE Funding		378			401
Long-term project funding		17			19
Capital lease obligations		96			99
Total Long-Term Liabilities		4,961			5,378
COMMITMENTS AND CONTINGENCIES (NOTE 14)
EQUITY
Common stock, $.01 par value, 400,000,000 shares authorized, 221,592,782 shares and 218,906,220 shares outstanding, respectively		2			2
Premium on stock and other capital contributions		3,215			3,179
Accumulated other comprehensive loss		(258	)		(262	)
Retained earnings		1,287			1,271
Total Shareholders’ Equity		4,246			4,190
Noncontrolling interest		6			6
Total Equity		4,252			4,196
TOTAL LIABILITIES AND EQUITY	$	15,830		$	16,133

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,
	2009			2008
	(millions of dollars)
OPERATING ACTIVITIES
Net income	$	194		$	233
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		294			283
Gain on sale of assets		—			(3	)
Effect of settlement of Mirant bankruptcy claims		(40	)		—
Non-cash rents from cross-border energy lease investments		(41	)		(51	)
Non-cash charge to reduce equity value of PHI’s cross-border energy lease investments		—			124
Changes in restricted cash equivalents related to Mirant settlement		102			317
Deferred income taxes		250			31
Net unrealized losses (gains) on commodity derivatives accounted for as fair value hedges		57			(26	)
Changes in:
Accounts receivable		177			(130	)
Inventories		24			(72	)
Prepaid expenses		(31	)		(37	)
Regulatory assets and liabilities, net		(157	)		(284	)
Accounts payable and accrued liabilities		(261	)		87
Pension contributions		(300	)		—
Pension and other postretirement benefit obligations, excluding contributions		94			21
Cash collateral related to derivative activities		4			(88	)
Taxes accrued		(74	)		60
Interest accrued		22			10
Other assets and liabilities		(6	)		(6	)
Net Cash From Operating Activities		308			469
INVESTING ACTIVITIES
Investment in property, plant and equipment		(595	)		(561	)
Proceeds from sale of assets		4			52
Changes in restricted cash equivalents		(1	)		(31	)
Net other investing activities		2			2
Net Cash Used By Investing Activities		(590	)		(538	)
FINANCING ACTIVITIES
Dividends paid on common stock		(178	)		(163	)
Common stock issued for the Dividend Reinvestment Plan		23			25
Issuances of common stock		14			15
Issuances of long-term debt		110			400
Reacquisition of long-term debt		(75	)		(438	)
Issuances of short-term debt, net		28			441
Cost of issuances		(4	)		(13	)
Net other financing activities		—			(26	)
Net Cash (Used By) From Financing Activities		(82	)		241
Net (Decrease) Increase in Cash and Cash Equivalents		(364	)		172
Cash and Cash Equivalents at Beginning of Period		384			55
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	20		$	227
NONCASH ACTIVITIES
Asset retirement obligations associated with removal costs transferred to regulatory liabilities	$	9		$	5
Recoverable pension/other postretirement benefit costs included in regulatory assets	$	(41	)	$	90
Conversion of DPL long-term debt to short-term debt	$	—		$	150
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash (received) paid for income taxes, net	$	(74	)	$	83

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

6

PEPCO HOLDINGS

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

PEPCO HOLDINGS, INC.

(1) ORGANIZATION

Pepco Holdings, Inc. (PHI or Pepco Holdings), a Delaware corporation incorporated in 2001, is a diversified energy company that, through its operating subsidiaries, is engaged primarily in two businesses:

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

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

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

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

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

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

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

Power Delivery

The largest component of PHI’s business is Power Delivery. Each of Pepco, DPL and ACE is a regulated public utility in the jurisdictions that comprise its service territory. Each company owns and operates a network of wires, substations and other equipment that is classified either as transmission or distribution facilities. Transmission facilities are high-voltage systems that carry wholesale electricity into, or across, the utility’s service territory. Distribution facilities are low-voltage systems that carry electricity to end-use customers in the utility’s service territory. Together the three companies constitute a single segment for financial reporting purposes.

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

7

PEPCO HOLDINGS

Competitive Energy

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

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

Other Business Operations

Through its subsidiary Potomac Capital Investment Corporation (PCI), PHI maintains a portfolio of cross-border energy sale-leaseback transactions, with a book value at September 30, 2009 of approximately $1.4 billion. This activity constitutes a fourth operating segment for financial reporting purposes, which is designated as “Other Non-Regulated.”

(2) SIGNIFICANT ACCOUNTING POLICIES

Financial Statement Presentation

Pepco Holdings’ unaudited consolidated financial statements are prepared in conformity with accounting principles generally accepted in the United States of America (GAAP). PHI adopted the Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC), which is the single source reference system for all authorative U.S. GAAP, as discussed in Note (3), “Newly Adopted Accounting Standards.” Pursuant to the rules and regulations of the Securities and Exchange Commission, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been omitted. Therefore, these financial statements should be read along with the annual financial statements included in PHI’s Annual Report on Form 10-K for the year ended December 31, 2008. In the opinion of PHI’s management, the consolidated financial statements contain all adjustments (which all are of a normal recurring nature) necessary to present fairly Pepco Holdings’ financial condition as of September 30, 2009, in accordance with GAAP. The year-end balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP. Interim results for the three and nine months ended September 30, 2009 may not be indicative of PHI’s results that will be realized for the full year ending December 31, 2009, since its Power Delivery and Competitive Energy business are seasonal. PHI has evaluated all subsequent events through October 29, 2009, the date of issuance of the consolidated financial statements to which these Notes relate.

Change in Accounting Principle

After the completion of the July 1, 2009 goodwill impairment test, PHI adopted a new accounting policy whereby PHI’s annual impairment review of goodwill will be performed as of November 1 each year. Management believes that the change in PHI’s annual impairment testing date is preferable because it better aligns the timing of the test with management’s annual update of its long-term financial forecast. The change in accounting principle had no effect on PHI’s consolidated financial statements.

8

PEPCO HOLDINGS

Change in Accounting Estimate

In the second quarter of 2008, PHI reassessed the sustainability of its tax position and revised its assumptions regarding the estimated timing of the tax benefits generated from its cross-border energy lease investments. Based on the reassessment, PHI for the quarter ended June 30, 2008, recorded an after-tax charge to net income of $93 million. For additional discussion on this matter, see Notes (7), “Leasing Activities,” and (14), “Commitments and Contingencies.”

Consolidation of Variable Interest Entities

In accordance with the provisions of FASB guidance on the consolidation of variable interest entities (ASC 810), Pepco Holdings consolidates those variable interest entities where Pepco Holdings or a subsidiary has been determined to be the primary beneficiary. The guidance addresses conditions under which an entity should be consolidated based upon variable interests rather than voting interests. Subsidiaries of Pepco Holdings have power purchase agreements (PPAs) with a number of entities to which the guidance applies.

ACE and Pepco 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 plants operated by the NUGs and, therefore, has a variable interest in the counterparties. Despite continued efforts to obtain information from these three entities during the three months ended September 30, 2009, PHI was unable to obtain sufficient information to conduct the analysis required under FASB guidance on the consolidation of variable interest entities 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 under the PPAs for the three months ended September 30, 2009 and 2008, were approximately $70 million and $93 million, respectively, of which approximately $66 million and $82 million, respectively, consisted of power purchases under the PPAs. Net purchase activities under the PPAs for the nine months ended September 30, 2009 and 2008, were approximately $214 million and $265 million, respectively, of which approximately $197 million and $233 million, respectively, consisted of power purchases under the PPAs. Pepco Holdings does not have direct loss exposure under the PPAs because ACE is able to recover its costs from its customers through regulated rates.

During the third quarter of 2008, Pepco transferred to Sempra Energy Trading LLP (Sempra) an agreement with Panda-Brandywine, L.P. (Panda) under which Pepco was obligated to purchase from Panda 230 megawatts of capacity and energy annually through 2021 (Panda PPA). Net purchase activities under the Panda PPA for the three and nine months ended September 30, 2008, were approximately $17 million and $59 million, respectively.

DPL Wind Transactions

PHI, through its DPL subsidiary, has entered into four wind PPAs in amounts up to a total of 350 megawatts. Three of the PPAs are with land-based facilities and one of the PPAs is with an offshore facility. When completed and operational, DPL would purchase energy and renewable energy credits (RECs) from the four wind facilities and capacity from one of the wind facilities. The RECs help DPL fulfill a portion of its requirements under the State of Delaware’s Renewable Energy Portfolio Standards Act, which requires that 20 percent of total load needed in Delaware be produced from renewable sources by 2019. The Delaware Public Service Commission (DPSC) has approved the four agreements, each of which sets forth the prices to be paid by DPL over the life of the respective contracts. Payments under the agreements are currently expected to start in late 2009 for one of the land-based contracts, 2010 for the other two land-based contracts, and 2014 for the offshore contract, if the projects are ultimately completed and operational.

The lengths of the contracts range between 15 and 25 years. 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. Recent disruptions in the capital and credit markets, as well as permitting delays, could result in setbacks in the construction schedules and the

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operational start dates of the wind facility currently expected to start in late 2009, one of the wind facilities expected to start in 2010, and the wind facility currently expected to start in 2014. If the wind facilities are not operational by specified dates, DPL has the right to terminate the PPAs.

DPL concluded that consolidation is not required for any of these PPAs under FASB guidance on the consolidation of variable interest entities (ASC 810). DPL would need to reassess its accounting conclusions if there were material changes to the contractual arrangements or wind facilities.

Goodwill

Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired at the acquisition date. Substantially all of Pepco Holdings’ goodwill was generated by Pepco’s acquisition of Conectiv in 2002 and was allocated to Pepco Holdings’ Power Delivery reporting unit based on the aggregation of its components. Pepco Holdings tests its goodwill for impairment annually 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. After the completion of its July 1, 2009 annual impairment test, PHI changed the date of its annual impairment test to 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; a protracted decline in stock price causing market capitalization to fall below book value; an adverse regulatory action; or an impairment of long-lived assets in the reporting unit. As described in Note (6), “Goodwill,” no impairment charge has been recorded for the three and nine months ended September 30, 2009.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in Pepco Holdings’ gross revenues were $88 million for each of the three months ended September 30, 2009 and 2008, and $245 million and $238 million for the nine months ended September 30, 2009 and 2008, 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:

Pepco Holdings

In the third quarter of 2008, PHI identified an error in the accounting for certain of its restricted stock awards granted under the Long-Term Incentive Plan that resulted in an understatement of stock-based compensation expense in 2006 and 2007. This error was corrected in the third quarter of 2008, resulting in an increase in Other Operation and Maintenance expenses for the three and nine months ended September 30, 2008 of $9 million.

Pepco

In the second quarter of 2008, Pepco recorded an adjustment to correct errors in Other Operation and Maintenance expenses for prior periods dating back to February 2005 for which late payment fees were incorrectly recognized. This adjustment resulted in an increase in Other Operation and Maintenance expenses for the nine months ended September 30, 2008 of $3 million.

DPL

In the third quarter of 2008, DPL recorded an adjustment to correct errors in Other Operation and Maintenance expenses for prior periods dating back to May 2006 for which late payment fees were incorrectly recognized. This adjustment resulted in an increase in Other Operation and Maintenance expenses for the three and nine months ended September 30, 2008 of $4 million and $3 million, respectively.

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(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Business Combinations (ASC 805)

The accounting guidance on business combinations was amended by the FASB effective beginning January 1, 2009. The amendment did not change the fundamental concepts that the acquisition method of accounting be used and that an acquirer must be identified for each business combination. However, the guidance expanded the definition of a business subject to this guidance and also requires the acquirer to recognize changes in the amount of its deferred tax benefits that are realizable because of a business combination either in income from continuing operations or directly in contributed capital, depending on the circumstances.

On April 1, 2009, the FASB issued additional guidance to clarify the accounting for the initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. The additional guidance requires that assets acquired and liabilities assumed in a business combination that arise from contingencies be measured at fair value if the acquisition date fair value of that asset and liability can be determined during the measurement period. If the acquisition date fair value cannot be determined, then the asset or liability would be measured in accordance with FASB guidance on contingencies (ASC 450).

The new guidance applies prospectively to business combinations for which the acquisition date is on or after January 1, 2009. The adoption of the guidance did not have a material impact on PHI’s overall financial condition, results of operations, or cash flows.

Fair Value Measurement and Disclosures (ASC 820)

There is a variety of new accounting guidance from the FASB that is effective for different financial reporting periods during 2009. Nonrecurring fair value measurement guidance for non-financial assets and non-financial liabilities was effective beginning January 1, 2009 for PHI. The adoption of this guidance did not have a material impact on the fair value measurements of PHI’s non-financial assets and non-financial liabilities.

New FASB guidance for the fair value measurement of liabilities issued with inseparable third-party credit enhancements was also effective beginning January 1, 2009 for PHI. The guidance applies to liabilities such as debt, derivatives, and other instruments that are guaranteed by third parties. The effect of the credit enhancement may not be included in the fair value measurement of the liability, even if the liability has an inseparable third-party credit enhancement. The issuer is required to disclose the existence of the inseparable third-party credit enhancement on the issued liability. The adoption of the guidance did not have a material impact on PHI’s overall financial condition, results of operations, or cash flows.

PHI adopted new FASB guidance in the second quarter of 2009 for fair value measurement when markets are inactive and distressed. This guidance was effective for interim periods ending after June 15, 2009. The guidance outlines a two-step test to identify inactive and distressed markets and provides a fair value application example for financial instruments when both conditions are met. The guidance primarily applies to PHI’s valuation of its derivatives in the event they were being valued using information from inactive and distressed markets. These market conditions would require management to exercise judgment regarding how the market information is incorporated into the measurement of fair value. This guidance did not have a material impact on PHI’s overall financial condition, results of operations, or cash flows.

Effective beginning with its June 30, 2009 financial statements, PHI began disclosing the fair value of debt issued by PHI and its utilities on a quarterly basis in Note (13), “Fair Value Disclosures,” in accordance with FASB guidance which is effective for interim reporting periods ending after June 15, 2009. Disclosures for the prior year-end balance sheet were also required.

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Consolidation (ASC 810)

The FASB established new accounting and reporting standards for a non-controlling interest (also called a “minority interest”) in a subsidiary and for the deconsolidation of a subsidiary. The new guidance clarified that a non-controlling interest in a subsidiary is an ownership interest in the consolidated entity that should be separately reported in the consolidated financial statements.

The guidance was effective prospectively for financial statement reporting periods beginning January 1, 2009 for PHI, except for the financial statement presentation and disclosure requirements which also apply to prior reporting periods presented. As of January 1, 2009, PHI adopted the provisions of this guidance and reclassified $6 million of non-controlling interests from the minority interest line item of its balance sheet to a component of equity. Otherwise, the adoption of the guidance did not have a material impact on PHI’s overall financial condition, results of operations, or cash flows.

Derivatives and Hedging Disclosures (ASC 815)

The FASB issued new disclosure requirements for derivatives and hedging effective for financial statement reporting periods beginning January 1, 2009 for PHI. Some of the new disclosures include derivative objectives and strategies, derivative volumes by product type, classification and gross fair values of derivative assets and liabilities, classification and amounts of gains and losses on derivatives and related hedged items, and credit-risk-related contingent features in derivatives. PHI adopted the new requirements beginning with its March 31, 2009 financial statements with comparative disclosures for prior reporting periods. The disclosures are included within Note (12), “Derivative Instruments and Hedging Activities.”

Earnings Per Share (ASC 260)

The FASB issued new guidance to determine when unvested instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation in computing earnings per share (EPS). As of January 1, 2009, PHI adopted the provisions of this guidance for the presentation of EPS data in the consolidated statements of income and Note (11), “Earnings Per Share.” All prior period EPS information presented was adjusted retrospectively to conform to the provisions of the guidance. The adoption did not result in a change in the reported EPS for prior periods presented.

Investments – Equity Method and Joint Ventures (ASC 323)

The FASB issued guidance addressing the accounting for equity method investments including: (i) how an equity method investment should initially be measured, (ii) how it should be tested for impairment, and (iii) how to account for an equity method investee’s issuance of shares. As of January 1, 2009, PHI adopted the provisions of this guidance and there was no material impact on PHI’s overall financial condition, results of operations, or cash flows.

Investments – Debt and Equity Securities (ASC 320)

The FASB issued new guidance on other-than-temporary impairment (OTTI) of debt and equity securities. The guidance requires information about the credit and noncredit component of an OTTI event and when an OTTI event has occurred. It requires separate display of losses related to credit deterioration and losses related to other market factors on the statements of income. Market-related losses would be recorded in other comprehensive income if it is not likely that the investor will have to sell the security prior to recovery. PHI adopted this guidance as of April 1, 2009, and concluded that none of its debt and equity securities investments were within its scope. The new guidance, therefore, did not have a material impact on PHI’s overall financial condition, results of operations, or cash flows.

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Subsequent Events (ASC 855)

Beginning with its June 30, 2009 financial statements, PHI adopted new FASB guidelines for the disclosure of events that occur after the balance sheet reporting date but before the financial statements are issued. The new guidance requires the disclosure of the date through which PHI has assessed the impact of subsequent events on the financial statements. The new guidance was effective for interim or annual financial periods ending after June 15, 2009. PHI has disclosed this subsequent events date in Note (2), “Significant Accounting Policies.”

FASB Accounting Standards Codification (ASC 105)

The ASC identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of non-governmental financial statements presented under GAAP. In addition, it replaces the current reference system for standards and guidance with a new numerical designation system known as the ASC. The ASC will be the single source reference system for all authoritative GAAP. The ASC is numerically organized by topic, subtopic, section, and subsection.

The ASC is effective for financial statements issued for interim and annual periods ending after September 15, 2009. PHI has adopted the ASC guidance and referencing system for GAAP in its September 30, 2009 financial statements. Entities are not required to revise previous financial statements for the change in references to GAAP. The adoption of ASC did not result in a change in accounting principle for PHI, therefore, it did not have a material impact on PHI’s overall financial condition, results of operations, or cash flows.

(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Disclosures about Pension and Postretirement Plan Assets (ASC 715)

The FASB issued new disclosure requirements about the plan assets of a defined benefit pension or other postretirement plan that will be effective starting with financial statement reporting periods ending December 31, 2009 for PHI. Comparative disclosures are not required for earlier periods presented. The new requirements would expand current disclosures to be in line with FASB guidance on fair value measurement disclosures.

The disclosures are to provide users an understanding of: (1) the investment allocation decisions made, (2) factors used in investment policies and strategies, (3) plan assets by major investment types, (4) inputs and valuation techniques used to measure the fair value of plan assets, (5) significant concentrations of risk within the plan, and (6) the effects of fair value measurement using significant unobservable inputs on changes in the value of plan assets for the period. PHI is evaluating the impact that this new guidance will have on PHI’s financial statement footnote disclosures.

Transfers and Servicing (ASC 860)

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

The new guidance is effective for transfers of financial assets occurring in fiscal periods beginning after November 15, 2009, therefore, this guidance will be effective on January 1, 2010 for PHI. Comparative disclosures are encouraged but not required for earlier periods presented. PHI is evaluating the impact that this new guidance will have on its overall financial condition and financial statements.

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Consolidation of Variable Interest Entities (ASC 810)

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

The new guidance is effective for fiscal periods beginning after November 15, 2009 for existing and newly created entities; therefore, this guidance will be effective on January 1, 2010 for PHI. Comparative disclosures under this new guidance are encouraged but not required for earlier periods presented. PHI is evaluating the impact that this new guidance will have on its overall financial condition and financial statements.

Fair Value Measurement of Liabilities (ASC 820)

The FASB issued new guidance on the fair value measurement of liabilities when there is a lack of observable market information. The guidance clarifies that, when a quoted price is not available for the identical liability, an entity can use either the quoted price of the identical liability when it is traded as an asset, quoted price for a similar liability, or quoted price for a similar liability when traded as an asset. If these prices are not available, then entities can employ an income or market valuation approach that considers what the entity would pay to transfer the identical liability or would receive to enter into the identical liability. The guidance is effective for PHI starting October 1, 2009. PHI is evaluating the impact of this new guidance on PHI’s overall financial condition and financial statements.

(5) SEGMENT INFORMATION

Based on the provisions of FASB guidance on segment reporting (ASC 280), Pepco Holdings’ management has identified its operating segments at September 30, 2009 as Power Delivery, Conectiv Energy, Pepco Energy Services, and Other Non-Regulated. Segment information for the three and nine months ended September 30, 2009 and 2008, is as follows:

	Three Months Ended September 30, 2009
	(millions of dollars)
				Competitive Energy Segments
	Power Delivery			Conectiv Energy			Pepco Energy Services		Other Non- Regulated		Corp. & Other (a)			PHI Cons.
Operating Revenue	$	1,428		$	581	(b)	$	611	$	13	$	(94	)	$	2,539
Operating Expense (c)		1,235	(b)(d)		539			584		—		(96	)		2,262
Operating Income		193			42			27		13		2			277
Interest Income		—			—			—		1		(1	)		—
Interest Expense		53			9			6		4		21			93
Other Income		3			1			—		1		—			5
Preferred Stock Dividends		—			—			—		1		(1	)		—
Income Tax Expense (Benefit)		49			13			7		3		(7	)		65
Net Income (Loss)		94	(e)		21			14		7		(12	)		124
Total Assets		10,181			1,978			699		1,552		1,420			15,830
Construction Expenditures	$	138		$	57		$	2	$	—	$	10		$	207

Notes:

(a) Includes unallocated Pepco Holdings’ (parent company) capital costs, such as acquisition financing costs, and the depreciation and amortization expense related to purchase accounting adjustments for the fair value of Conectiv assets and liabilities as of the August 1, 2002 acquisition date. Additionally, the Total Assets line item in this column includes Pepco Holdings’ goodwill balance. Corp. & Other includes intercompany amounts of $(94) million for Operating Revenue, $(92) million for Operating Expense, $(17) million for Interest Income, $(17) million for Interest Expense, and $(1) million of Preferred Stock Dividends.

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(b) Power Delivery purchased electric energy and capacity and natural gas from Conectiv Energy in the amount of $75 million for the three months ended September 30, 2009.

(c) Includes depreciation and amortization expense of $103 million, consisting of $84 million for Power Delivery, $10 million for Conectiv Energy, $4 million for Pepco Energy Services, and $5 million for Corp. & Other.

(d) Includes $26 million ($16 million after-tax) gain related to settlement of Mirant bankruptcy claims.

(e) 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.

	Three Months Ended September 30, 2008
	(millions of dollars)
				Competitive Energy Segments
	Power Delivery			Conectiv Energy			Pepco Energy Services		Other Non- Regulated			Corp. & Other (a)			PHI Cons.
Operating Revenue	$	1,668		$	783	(b)	$	716	$	14		$	(121	)	$	3,060
Operating Expense (c)		1,495	(b)		694			713		2			(119	)		2,785
Operating Income		173			89			3		12			(2	)		275
Interest Income		2			1			1		1			(1	)		4
Interest Expense		48			6			1		5			22			82
Other Income (Expense)		3			—			—		(1	)		—			2
Preferred Stock Dividends		—			—			—		1			(1	)		—
Income Tax Expense (Benefit)		53			35			—		1			(9	)		80
Net Income (Loss)		77			49			3		5			(15	)		119
Total Assets		9,875			2,047			708		1,465			1,477			15,572
Construction Expenditures	$	151		$	31		$	6	$	—		$	7		$	195

Notes:

(a) Includes unallocated Pepco Holdings’ (parent company) capital costs, such as acquisition financing costs, and the depreciation and amortization expense related to purchase accounting adjustments for the fair value of Conectiv assets and liabilities as of the August 1, 2002 acquisition date. Additionally, the Total Assets line item in this column includes Pepco Holdings’ goodwill balance. Corp. & Other includes intercompany amounts of $(121) million for Operating Revenue, $(120) million for Operating Expense, $(14) million for Interest Income, $(14) million for Interest Expense, and $(1) million for Preferred Stock Dividends.

(b) Power Delivery purchased electric energy and capacity and natural gas from Conectiv Energy in the amount of $113 million for the three months ended September 30, 2008.

(c) Includes depreciation and amortization expense of $99 million, consisting of $84 million for Power Delivery, $9 million for Conectiv Energy, $4 million for Pepco Energy Services, and $2 million for Corp. & Other.

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	Nine Months Ended September 30, 2009
	(millions of dollars)
				Competitive Energy Segments
	Power Delivery			Conectiv Energy			Pepco Energy Services		Other Non- Regulated		Corp. & Other (a)			PHI Cons.
Operating Revenue	$	3,895		$	1,625	(b)	$	1,828	$	40	$	(264	)	$	7,124
Operating Expense (c)		3,488	(b)(d)		1,587			1,757		2		(269	)		6,565
Operating Income		407			38			71		38		5			559
Interest Income		2			1			1		3		(4	)		3
Interest Expense		159			24			22		11		63			279
Other Income		9			1			1		1		1			13
Preferred Stock Dividends		—			—			—		2		(2	)		—
Income Tax Expense (Benefit)		92			5			19		8		(22	)		102
Net Income (Loss)		167	(e)		11			32		21		(37	)		194
Total Assets		10,181			1,978			699		1,552		1,420			15,830
Construction Expenditures	$	419		$	148		$	8	$	—	$	20		$	595

Notes:

(a) Includes unallocated Pepco Holdings’ (parent company) capital costs, such as acquisition financing costs, and the depreciation and amortization expense related to purchase accounting adjustments for the fair value of Conectiv assets and liabilities as of the August 1, 2002 acquisition date. Additionally, the Total Assets line item in this column includes Pepco Holdings’ goodwill balance. Corp. & Other includes intercompany amounts of $(264) million for Operating Revenue, $(257) million for Operating Expense, $(61) million for Interest Income, $(59) million for Interest Expense, and $(2) million for Preferred Stock Dividends.

(b) Power Delivery purchased electric energy and capacity and natural gas from Conectiv Energy in the amount of $220 million for the nine months ended September 30, 2009.

(c) Includes depreciation and amortization expense of $294 million, consisting of $242 million for Power Delivery, $29 million for Conectiv Energy, $13 million for Pepco Energy Services, $1 million for Other Non-Regulated, and $9 million for Corp. & Other.

(d) Includes $40 million ($24 million after-tax) gain related to settlement of Mirant bankruptcy claims.

(e) 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.

	Nine Months Ended September 30, 2008
	(millions of dollars)
				Competitive Energy Segments
	Power Delivery			Conectiv Energy			Pepco Energy Services		Other Non- Regulated			Corp. & Other (a)			PHI Cons.
Operating Revenue	$	4,260		$	2,395	(b)	$	1,968	$	(73	)(d)	$	(331	)	$	8,219
Operating Expense (c)		3,830	(b)		2,178			1,926		4			(331	)		7,607
Operating Income		430			217			42		(77	)		—			612
Interest Income		11			2			2		3			(2	)		16
Interest Expense		142			18			2		14			67			243
Other Income (Expense)		10			—			2		(4	)		1			9
Preferred Stock Dividends		—			—			—		2			(2	)		—
Income Tax Expense (Benefit)		110			83			16		(25	)(d)		(23	)		161
Net Income (Loss)		199			118			28		(69	)(d)		(43	)		233
Total Assets		9,875			2,047			708		1,465			1,477			15,572
Construction Expenditures	$	433		$	90		$	23	$	—		$	15		$	561

Notes:

(a) Includes unallocated Pepco Holdings’ (parent company) capital costs, such as acquisition financing costs, and the depreciation and amortization expense related to purchase accounting adjustments for the fair value of Conectiv assets and liabilities as of the August 1, 2002 acquisition date. Additionally, the Total Assets line item in this column includes Pepco Holdings’ goodwill balance. Corp. & Other includes intercompany amounts of $(331) million for Operating Revenue, $(327) million for Operating Expense, $(43) million for Interest Income, $(40) million for Interest Expense, and $(2) million for Preferred Stock Dividends.

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(b) Power Delivery purchased electric energy and capacity and natural gas from Conectiv Energy in the amount of $298 million for the nine months ended September 30, 2008.

(c) Includes depreciation and amortization expense of $283 million, consisting of $239 million for Power Delivery, $28 million for Conectiv Energy, $9 million for Pepco Energy Services, $1 million for Other Non-Regulated, and $6 million for Corp. & Other.

(d) Included in operating revenue is a pre-tax charge of $124 million ($86 million after-tax) related to the adjustment to the equity value of cross-border energy lease investments, and included in income taxes is a $7 million after-tax charge for the additional interest accrued on the related tax obligations.

(6) GOODWILL

PHI’s goodwill balance of $1.4 billion was unchanged during the three and nine month period ended September 30, 2009. Substantially all of PHI’s goodwill was generated by Pepco’s acquisition of Conectiv in 2002 and is allocated to the Power Delivery reporting unit based on the aggregation of its components for purposes of assessing impairment under FASB guidance on goodwill and other intangibles (ASC 350).

PHI’s annual impairment test as of July 1, 2009 indicated that goodwill was not impaired at June 30, 2009. As of September 30, 2009, after review of its significant assumptions in the goodwill impairment analysis, PHI concluded that there were no events requiring PHI to perform an interim goodwill impairment test. Although PHI’s market capitalization was below book value as of September 30, 2009, PHI’s market capitalization has improved compared to earlier periods. PHI performed interim goodwill impairment tests as of March 31, 2009 and December 31, 2008 when its market capitalization was further below book value than at September 30, 2009, and concluded that its goodwill was not impaired at those earlier dates. PHI’s next annual impairment test will be as of November 1, 2009.

In order to estimate the fair value of its Power Delivery reporting unit, PHI reviews the results from two discounted cash flow models. The models differ in the method used to calculate the terminal value of the reporting unit. One model estimates terminal value based on a constant annual cash flow growth rate that is consistent with PHI’s long-term view of the business, and the other model estimates terminal value based on a multiple of earnings before interest, taxes, depreciation, and amortization (EBITDA) that management believes is consistent with EBITDA multiples for comparable utilities. The models use a cost of capital appropriate for a regulated utility as the discount rate for the estimated cash flows associated with the reporting unit. PHI has consistently used this valuation approach to estimate the fair value of Power Delivery.

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

In addition to estimating the fair value of its Power Delivery reporting unit, PHI estimated the fair value of its other reporting units (Conectiv Energy, Pepco Energy Services, Other Non-Regulated, and Corporate & Other) at July 1, 2009. The sum of the fair value of all reporting units was reconciled to PHI’s market capitalization at July 1, 2009 to further substantiate the estimated fair value of its reporting units.

The sum of the estimated fair values of all reporting units exceeded the market capitalization of PHI at July 1, 2009. PHI believes that the excess of the estimated fair value of PHI’s reporting units as compared to PHI’s market capitalization reflects a reasonable control premium that is comparable to control premiums observed in historical acquisitions in the utility industry during various economic environments. Given the lack of a fundamental change in

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the Power Delivery reporting unit’s business, PHI does not believe the declines in its stock price in reporting periods prior to July 1, 2009, indicated a commensurate decline in the fair value of PHI’s Power Delivery reporting unit. PHI’s Power Delivery reporting unit consists of regulated companies with regulated recovery rates and approved rates of return allowing for generally predictable and steady streams of revenues and cash flows over an extended period of time.

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

(7) LEASING ACTIVITIES

Investment in Finance Leases Held in Trust

As of September 30, 2009 and December 31, 2008, Pepco Holdings had cross-border energy lease investments of $1.4 billion and $1.3 billion, respectively, consisting of hydroelectric generation and coal-fired electric generation facilities and natural gas distribution networks located outside of the United States.

As further discussed in Note (14), “Commitments and Contingencies - PHI’s Cross-Border Energy Lease Investments,” during the second quarter of 2008, PHI reassessed the sustainability of its tax position and revised its assumptions regarding the estimated timing of tax benefits generated from its cross-border energy lease investments. Based on this reassessment, PHI for the quarter ended June 30, 2008, recorded a reduction in its cross-border energy lease investments of $124 million. No further charges were recorded in 2008 or in the first three quarters of 2009.

The components of the cross-border energy lease investments at September 30, 2009 and at December 31, 2008 (reflecting the effects of recording this charge) are summarized below:

	September 30, 2009			December 31, 2008
	(millions of dollars)
Scheduled lease payments to PHI, net of non-recourse debt	$	2,281		$	2,281
Less: Unearned and deferred income		(905	)		(946	)
Investment in finance leases held in trust		1,376			1,335
Less: Deferred income tax liabilities		(725	)		(679	)
Net investment in finance leases held in trust	$	651		$	656

Income recognized from cross-border energy lease investments was comprised of the following for the three and nine months ended September 30, 2009 and 2008:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
	(millions of dollars)
Pre-tax income from PHI’s cross-border energy lease investments (included in “Other Revenue”)	$	14	$	14	$	41	$	51
Non-cash charge to reduce equity value of PHI’s cross-border energy lease investments		—		—		—		(124	)
Pre-tax income (loss) from PHI’s cross-border energy lease investments after adjustment		14		14		41		(73	)
Income tax expense (benefit)		4		4		11		(25	)
Net income (loss) from PHI’s cross-border energy lease investments	$	10	$	10	$	30	$	(48	)

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(8) PENSIONS AND OTHER POSTRETIREMENT BENEFITS

The following Pepco Holdings information is for the three months ended September 30, 2009 and 2008:

	Pension Benefits						Other Postretirement Benefits
	2009			2008			2009			2008
	(millions of dollars)
Service cost	$	9		$	9		$	2		$	2
Interest cost		27			27			10			10
Expected return on plan assets		(25	)		(33	)		(3	)		(4	)
Prior service credit component		—			—			(1	)		(1	)
Loss component		14			3			3			3
Net periodic benefit cost	$	25		$	6		$	11		$	10

The following Pepco Holdings information is for the nine months ended September 30, 2009 and 2008:

	Pension Benefits						Other Postretirement Benefits
	2009			2008			2009			2008
	(millions of dollars)
Service cost	$	27		$	27		$	5		$	5
Interest cost		83			81			30			30
Expected return on plan assets		(76	)		(97	)		(10	)		(12	)
Prior service credit component		—			—			(3	)		(3	)
Loss component		43			7			12			10
Net periodic benefit cost	$	77		$	18		$	34		$	30

Pension and Other Postretirement Benefits

Net periodic benefit cost is included in other operation and maintenance expense, net of the portion of the net periodic benefit cost that is capitalized as part of the cost of labor for internal construction projects. After intercompany allocations, the three utility subsidiaries are generally responsible for approximately 80% to 85% of total PHI net periodic benefit cost.

Pension Contributions

PHI’s funding policy with regard to PHI’s non contributory retirement plan (the PHI Retirement Plan) is to maintain a funding level that is at least equal to the funding target as defined under the Pension Protection Act of 2006. During 2009, discretionary tax-deductible contributions totaling $300 million have been made to the PHI Retirement Plan which are expected to bring plan assets to at least the funding target level for 2009 under the Pension Protection Act. Of this amount, $240 million was contributed, through tax-deductible contributions from Pepco, ACE and DPL in the amounts of $170 million, $60 million and $10 million, respectively. The remaining $60 million was made through tax-deductible contributions from the PHI Service Company. No contributions were made in 2008.

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

PHI and its utility subsidiaries historically have issued commercial paper to meet their short-term working capital requirements. As a result of the disruptions in the commercial paper market in 2008, the companies borrowed under the $1.5 billion credit facility to meet short-term operating needs. At September 30, 2009, PHI had an outstanding loan of $100 million under this facility.

In November 2008, PHI entered into a second unsecured credit facility in the amount of $400 million with a syndicate of nine lenders, which was amended and restated in October 2009 to extend the facility termination date to October 15, 2010. Under the facility, PHI has access to revolving and swingline loans over the term of the facility. The facility does not provide for the issuance of letters of credit. These two facilities are referred to collectively as PHI’s “primary credit facilities.”

At September 30, 2009 and December 31, 2008, the amount of cash, plus borrowing capacity under PHI’s primary credit facilities available to meet the future liquidity needs of PHI and its utility subsidiaries on a consolidated basis totaled $1.4 billion and $1.5 billion, respectively. PHI’s utility subsidiaries had a combined cash and borrowing capacity under the $1.5 billion credit facility of $581 million and $843 million, respectively.

Other Financing Activities

During the three months ended September 30, 2009, the following financing activities occurred:

In July 2009, Atlantic City Electric Transition Funding LLC (ACE Funding) made principal payments of $5.2 million on Series 2002-1 Bonds, Class A-2, $1.4 million on Series 2003-1 Bonds, Class A-1, and $.7 million on Series 2003-1 Bonds, Class A-2.

In July 2009, DPL repaid, at maturity, the remaining $100 million of a short-term loan in the original amount of $150 million.

In July 2009, PHI’s utility subsidiaries entered into a $30 million line of credit that can be used by these entities for equipment leasing through July 2010.

In July 2009, DPL redeemed $15 million of Series 2003A and $18.2 million of Series 2003B Exempt Facilities Refunding Revenue Bonds issued for the benefit of DPL by The Delaware Economic Development Authority. These tax-exempt bonds were purchased by DPL in 2008 due to the disruptions in the tax-exempt capital markets.

In July 2009, ACE redeemed $25 million of Series 2004A and $6.5 million of Series 2004B Pollution Control Revenue Refunding Bonds issued for the benefit of ACE by the Pollution Control Financing Authority of Cape May County (collectively, the Cape May Bonds). The Cape May Bonds were purchased by ACE in 2008 due to the disruptions in the tax-exempt capital markets. The Cape May Bonds were insured by bond insurance policies purchased by ACE. At the time of the issuance of the Cape May Bonds, ACE issued to the bond insurer, as security for its reimbursement obligations under the bond insurance policies, a series of senior notes having terms substantially identical to the terms of the respective series of Cape May Bonds. ACE’s obligations under the senior notes were, in turn, secured by a corresponding series of collateral first mortgage bonds issued by ACE under its Mortgage and Deed of Trust. Upon the redemption of the Cape May Bonds, the corresponding series of senior notes and first mortgage bonds were likewise redeemed.

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In September 2009, DPL issued $165.5 million of collateral first mortgage bonds in order to secure its reimbursement obligations under bond insurance policies insuring the principal and interest payments on a series of previously issued DPL notes and two series of pollution control bonds previously issued for the benefit of DPL. DPL did not receive any cash proceeds from the issuance of the collateral first mortgage bonds. The payment by DPL of its principal and interest obligations in respect of the DPL notes and the pollution control bonds satisfies the corresponding payment obligations on collateral first mortgage bonds, and accordingly DPL’s outstanding debt did not increase as a result of these transactions.

Subsequent to September 30, 2009, the following financing activities occurred:

In October 2009, ACE Funding made principal payments of $7 million on Series 2002-1 Bonds, Class A-2, and $2.7 million on Series 2003-1 Bonds, Class A-2.

In October 2009, PHI, as discussed above, extended the term of its $400 million unsecured credit facility to October 15, 2010.

Collateral Requirements of the Competitive Energy Business

In conducting its retail energy supply business, Pepco Energy Services, during periods of declining energy prices, has been exposed to the asymmetrical risk of having to post collateral under its wholesale purchase contracts without receiving a corresponding amount of collateral from its retail customers. To partially address these asymmetrical collateral obligations, Pepco Energy Services, in the first quarter of 2009, entered into a credit intermediation arrangement with Morgan Stanley Capital Group, Inc. (MSCG). Under this arrangement, MSCG, in consideration for the payment to MSCG of certain fees: (i) has assumed by novation certain electricity purchase obligations of Pepco Energy Services in years 2009 through 2011 under several wholesale purchase contracts, and (ii) has agreed to supply electricity to Pepco Energy Services on the same terms as the novated transactions, but without imposing on Pepco Energy Services any associated collateral obligations. As of September 30, 2009, approximately 24% of Pepco Energy Services’ wholesale electricity purchase obligations (measured in megawatt hours) were covered by this credit intermediation arrangement with MSCG. The fees incurred by Pepco Energy Services in the amount of $25 million are being amortized into expense in declining amounts over the life of the arrangement based on the fair value of the underlying contracts at the time of novation. For the three and nine months ended September 30, 2009, approximately $4 million and $12 million, respectively, of the fees have been amortized and reflected in interest expense.

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

Depending on the contract terms, the collateral required to be posted by Pepco Energy Services and Conectiv Energy can be of varying forms, including cash and letters of credit. As of September 30, 2009, Pepco Energy Services and Conectiv Energy had posted net cash collateral of $131 million and $214 million, respectively, and letters of credit of $186 million and $16 million, respectively. At December 31, 2008, Pepco Energy Services and Conectiv Energy had posted net cash collateral of $125 million and $206 million, respectively, and letters of credit of $474 million and $84 million, respectively.

At September 30, 2009 and December 31, 2008, the amount of cash, plus borrowing capacity under PHI’s primary credit facilities available to meet the future liquidity needs of the Competitive Energy business totaled $822 million and $684 million, respectively.

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(10) INCOME TAXES

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

	For The Three Months Ended September 30,				For The Nine Months Ended September 30,
	2009		2008		2009		2008
Federal statutory rate	35.0	%	35.0	%	35.0	%	35.0	%
Increases (decreases) resulting from:
State income taxes, net of federal effect	5.6		5.9		5.6		7.5
Change in estimates and interest related to uncertain and effectively settled tax positions	1.2		1.2		.1		(.9	)
Depreciation	1.1		.9		1.7		1.3
Tax credits	(.6	)	(.5	)	(1.1	)	(.8	)
Cross-border energy lease investments	(.7	)	(.7	)	(1.4	)	.2
State tax benefits related to prior years’ asset dispositions	(6.9	)	—		(4.4	)	—
Other, net	(.3	)	(1.6	)	(1.0	)	(1.5	)
Consolidated Effective Income Tax Rate	34.4	%	40.2	%	34.5	%	40.8	%

PHI’s effective tax rates for the three months ended September 30, 2009 and 2008 were 34.4% and 40.2%, respectively. The decrease in the rate primarily resulted from the refund of $6 million (after tax) of state income taxes and the establishment of a state tax benefit carryforward of $7 million (after tax) related to a change in the tax reporting for the disposition of certain assets in prior years.

PHI’s effective tax rates for the nine months ended September 30, 2009 and 2008 were 34.5% and 40.8%, respectively. The decrease in the rate primarily resulted from the refund of $6 million (after tax) of state income taxes and the establishment of a state tax benefit carryforward of $7 million (after tax), each related to a change in tax reporting for the disposition of certain assets in prior years, and lower permanent and state income tax benefits in 2008 related to the charge taken in the second quarter of 2008 on the cross-border energy lease investments as described in Note (7), “Leasing Activities.”

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 included in the RAR. See Note (14), “Commitments and Contingencies – PHI’s Cross-Border Energy Lease Investments” for additional discussion.

In October 2009, PHI filed a claim with the IRS requesting a Federal income tax refund of approximately $138 million, a substantial portion of which is associated with PHI’s utility subsidiaries. The refund results from the carry back of a 2008 net operating loss for tax reporting purposes that reflected, among other things, significant tax deductions related to accelerated depreciation, the pension plan contributions paid in 2009 (which were deductible for 2008) and the cumulative effect of adopting a new method of tax reporting for certain repairs. The timing of receipt of the refund is uncertain, however, after a 45-day period, interest would begin to accrue on the amount of the refund.

During the third quarter of 2009, as a result of the acceptance of previously filed amended state returns, PHI’s uncertain tax benefits related to prior year tax positions decreased by $18 million. Further, as a result of a change in the tax accounting method related to certain repairs, PHI’s uncertain tax benefits related to current year tax positions increased by $40 million, none of which, if recognized, would affect the effective tax rate.

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(11) EARNINGS PER SHARE

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

	For the Three Months Ended September 30,
	2009		2008
	(millions of dollars, except per share data)
Income (Numerator):
Earnings Applicable to Common Stock	$	124	$	119
Shares (Denominator) (a):
Weighted average shares outstanding for basic computation:
Average shares outstanding		221		202
Adjustment to shares outstanding		—		—
Weighted Average Shares Outstanding for Computation of Basic Earnings Per Share of Common Stock		221		202
Net effect of potentially dilutive shares		—		—
Weighted Average Shares Outstanding for Computation of Diluted Earnings Per Share of Common Stock		221		202
Basic earnings per share of common stock	$	.56	$	.59
Diluted earnings per share of common stock	$	.56	$	.59

Notes:

(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 340,066 and 171,000 for the three months ended September 30, 2009 and 2008, respectively.

	For the Nine Months Ended September 30,
	2009		2008
	(millions of dollars, except per share data)
Income (Numerator):
Earnings Applicable to Common Stock	$	194	$	233
Shares (Denominator) (a):
Weighted average shares outstanding for basic computation:
Average shares outstanding		220		201
Adjustment to shares outstanding		—		—
Weighted Average Shares Outstanding for Computation of Basic Earnings Per Share of Common Stock		220		201
Net effect of potentially dilutive shares		—		—
Weighted Average Shares Outstanding for Computation of Diluted Earnings Per Share of Common Stock		220		201
Basic earnings per share of common stock	$	.88	$	1.16
Diluted earnings per share of common stock	$	.88	$	1.16

Notes:

(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 340,066 and 5,000 for the nine months ended September 30, 2009 and 2008, respectively.

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(12) DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

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

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

Pepco Energy Services purchases energy commodity contracts in the form of electric and natural gas futures, swaps, options and forward contracts to hedge price risk in connection with the purchase of physical natural gas and electricity for delivery to customers. Pepco Energy Services accounts for its futures and swap contracts as cash flow hedges of forecasted transactions. Certain commodity contracts that do not qualify as cash flow hedges of forecasted transactions or do not meet the requirements for normal purchase and normal sale accounting are marked-to-market through current earnings. Forward contracts are accounted for using standard accrual accounting since these contracts meet the requirements for normal purchase and normal sale accounting.

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

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

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The tables below identify the balance sheet location and fair values of derivative instruments as of September 30, 2009 and December 31, 2008:

	As of September 30, 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)	$	191		$	1,149		$	1,340		$	(1,278	)	$	62
Derivative Assets (non-current assets)		78			67			145			(118	)		27
Total Derivative Assets		269			1,216			1,485			(1,396	)		89
Derivative Liabilities (current liabilities)		(536	)		(1,153	)		(1,689	)		1,564			(125	)
Derivative Liabilities (non-current liabilities)		(120	)		(74	)		(194	)		131			(63	)
Total Derivative Liabilities		(656	)		(1,227	)		(1,883	)		1,695			(188	)
Net Derivative (Liability) Asset	$	(387	)	$	(11	)	$	(398	)	$	299		$	(99	)
	As of December 31, 2008
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)	$	314		$	1,736		$	2,050		$	(1,952	)	$	98
Derivative Assets (non-current assets)		86			87			173			(164	)		9
Total Derivative Assets		400			1,823			2,223			(2,116	)		107
Derivative Liabilities (current liabilities)		(698	)		(1,670	)		(2,368	)		2,224			(144	)
Derivative Liabilities (non-current liabilities)		(113	)		(112	)		(225	)		166			(59	)
Total Derivative Liabilities		(811	)		(1,782	)		(2,593	)		2,390			(203	)
Net Derivative (Liability) Asset	$	(411	)	$	41		$	(370	)	$	274		$	(96	)

Under 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, 2009			December 31, 2008
	(millions of dollars)
Cash collateral pledged to counterparties with the right to reclaim (a)	$	305		$	326
Cash collateral received from counterparties with the obligation to return		(6	)		(52	)

(a) Includes cash deposits on commodity brokerage accounts

As of September 30, 2009 and December 31, 2008, PHI had no cash collateral pledged or received related to derivative instruments accounted for at fair value that it was not entitled to offset under master netting agreements.

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Derivatives Designated as Hedging Instruments

Cash Flow Hedges

Competitive Energy

For energy commodity contracts that are designated and qualify as cash flow hedges, the effective portion of the gain or loss on the derivative is reported as a component of accumulated other comprehensive (loss) income (AOCL) and is reclassified into income in the same period or periods during which the hedged transactions affect income. Gains and losses on the derivative representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current income. This information for the activity during the three and nine months ended September 30, 2009 and 2008 is provided in the tables below:

	Three Months Ended September 30,
	2009			2008
	(millions of dollars)
Amount of net pre-tax (loss) gain arising during the period included in accumulated other comprehensive (loss) income	$	(14	)	$	(675	)
Amount of net pre-tax (loss) gain reclassified into income:
Effective portion:
Competitive Energy Revenue		59			(75	)
Fuel and Purchased Energy		(158	)		97
Total		(99	)		22
Ineffective portion: (a)
Competitive Energy Revenue		1			1
Fuel and Purchased Energy		1			(12	)
Total		2			(11	)
Total net (loss) gain reclassified into income		(97	)		11
Net pre-tax gain (loss) on commodity derivatives included in other comprehensive (loss) income	$	83		$	(686	)

(a) Included in the above table is a loss of $6 million for the three months ended September 30, 2008, which was reclassified from AOCL to income because the forecasted hedged transactions were deemed no longer probable. For the three months ended September 30, 2009, there were no losses reclassified from AOCL to income because the forecasted transaction was deemed no longer probable.

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	Nine Months Ended September 30,
	2009			2008
	(millions of dollars)
Amount of net pre-tax (loss) gain arising during the period included in accumulated other comprehensive (loss) income (a)	$	(296	)	$	(36	)
Amount of net (loss) gain reclassified into income:
Effective portion:
Competitive Energy Revenue		90			(31	)
Fuel and Purchased Energy		(398	)		125
Total		(308	)		94
Ineffective portion: (b)
Competitive Energy Revenue		—			2
Fuel and Purchased Energy		(1	)		(3	)
Total		(1	)		(1	)
Total net (loss) gain reclassified into income		(309	)		93
Net pre-tax gain (loss) on commodity derivatives included in other comprehensive (loss) income	$	13		$	(129	)

(a) Included in the $296 million loss for the nine months ended September 30, 2009, is a $3 million loss realized on the derivative transaction but not yet recognized into income. Included in the $36 million loss for the nine months ended September 30, 2008, is a $7 million gain realized on the derivative transaction but not yet recognized into income.

(b) Included in the above table is a loss of $3 million for the nine months ended September 30, 2009, which was reclassified from AOCL to income because the forecasted hedged transactions were deemed no longer probable. For the nine months ended September 30, 2008, there were no losses reclassified from AOCL to income because the forecasted transaction was deemed no longer probable.

As of September 30, 2009 and December 31, 2008, PHI’s Competitive Energy business had the following types and volumes of energy commodity contracts employed as cash flow hedges of forecasted purchases and forecasted sales.

	Quantities
Commodity	September 30, 2009	December 31, 2008
Forecasted Purchases Hedges
Coal (Tons)	235,000	120,000
Natural gas (One Million British Thermal Units (MMBtu))	83,100,000	85,034,233
Electricity (Megawatt hours (MWh))	20,776,789	27,856,037
Electric capacity (MW-Days)	180,000	1,400,400
Heating oil (Barrels)	138,000	128,000
Forecasted Sales Hedges
Coal (Tons)	105,000	—
Natural gas (MMBtu)	3,340,000	—
Electricity (MWh)	11,582,657	19,808,191
Electric capacity (MW-Days)	217,440	308,220
Financial transmission rights (MWh)	27,296	—

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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, 2009 and 2008:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
	(millions of dollars)
Net Gain Deferred as a Regulatory Asset/Liability	$	8		$	(26	)	$	19		$	(16	)
Net (Loss) Gain Reclassified from Regulatory Asset/Liability to Fuel and Purchased Energy Expense		(7	)		1			(33	)		2

As of September 30, 2009 and December 31, 2008, Power Delivery had the following outstanding commodity forward contracts that were entered into to hedge forecasted transactions:

	Quantities
Commodity	September 30, 2009	December 31, 2008
Forecasted Purchases Hedges:
Natural Gas (MMBtu)	6,845,000	10,805,000

Cash Flow Hedges Included in Accumulated Other Comprehensive Loss

The table below provides details regarding effective cash flow hedges included in PHI’s consolidated balance sheet as of September 30, 2009. Cash flow hedges are marked-to-market on the balance sheet with corresponding adjustments to AOCL. The data in the table indicate the cumulative net gain (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:

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)	$	220	$	148	56 months
Interest Rate		23		3	275 months
Total	$	243	$	151

(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. This balance is not included in this table as it is not a cash flow hedge.

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

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Fair Value Hedges

In connection with its energy commodity activities, the Competitive Energy business designates certain derivatives as fair value hedges. For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative as well as the offsetting gain or loss on the hedged item attributable to the hedged risk is recognized in current income. For the three and nine months ended September 30, 2009 and 2008, the amount of the derivative net gain (loss) on energy commodity contracts recognized for hedges, by consolidated statements of income line item, is as follows:

Consolidated Statements of Income Line Item	Net Gain (Loss) on Derivatives Recognized in Income					Net Gain (Loss) on Hedged Items Recognized in Income						Net Gain (Loss) on Derivatives Recognized in Income						Net Gain (Loss) on Hedged Items Recognized in Income
	Three Months Ended September 30,											Nine Months Ended September 30,
	2009			2008		2009			2008			2009			2008			2009		2008
	(millions of dollars)
Competitive Energy Revenue	$	1		$	17	$	(1	)	$	(14	)	$	(3	)	$	(10	)	$	4	$	10
Fuel and Purchased Energy Expense		(1	)		4		1			(4	)		—			(4	)		—		4
Total	$	—		$	21	$	—		$	(18	)	$	(3	)	$	(14	)	$	4	$	14

As of September 30, 2009 and December 31, 2008, PHI’s Competitive Energy business had the following outstanding commodity forward contracts volumes and net position on derivatives that were accounted for as fair value hedges of fuel inventory and natural gas transportation:

Commodity	September 30, 2009		December 31, 2008
	Quantity	Net Position	Quantity	Net Position
Natural Gas (MMBtu)	1,800,000	Short	1,800,000	Short
Oil (Barrels)	—	—	466,000	Short

Other Derivative Activity

Competitive Energy Business

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

For the three and nine months ended September 30, 2009 and 2008, the amount of the derivative gain (loss) for the Competitive Energy business recognized in income is provided in the table below:

	Three Months Ended September 30, 2009								Three Months Ended September 30, 2008
	Competitive Energy Revenue			Fuel and Purchased Energy Expense		Total			Competitive Energy Revenue			Fuel and Purchased Energy Expense			Total
	(millions of dollars)
Realized mark-to-market gains (losses)	$	6		$	2	$	8		$	27		$	(19	)	$	8
Unrealized mark-to-market (losses) gains		(8	)		—		(8	)		(5	)		—			(5	)
Total net mark-to-market (losses) gains	$	(2	)	$	2	$	—		$	22		$	(19	)	$	3

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	Nine Months Ended September 30, 2009									Nine Months Ended September 30, 2008
	Competitive Energy Revenue			Fuel and Purchased Energy Expense			Total			Competitive Energy Revenue		Fuel and Purchased Energy Expense			Total
	(millions of dollars)
Realized mark-to-market gains (losses)	$	54		$	(12	)	$	42		$	136	$	(103	)	$	33
Unrealized mark-to-market (losses) gains		(57	)		—			(57	)		26		—			26
Total net mark-to-market (losses) gains	$	(3	)	$	(12	)	$	(15	)	$	162	$	(103	)	$	59

As of September 30, 2009 and December 31, 2008, PHI’s Competitive Energy business had the following net outstanding commodity forward contract volumes and net position on derivatives that did not qualify for hedge accounting:

	September 30, 2009		December 31, 2008
Commodity	Quantity	Net Position	Quantity	Net Position
Coal (Tons)	175,000	Long	30,000	Short
Natural gas (MMBtu)	5,220,067	Short	578,443	Short
Natural gas basis (MMBtu)	3,795,000	Short	18,300,000	Long
Heating oil (Barrels)	210,000	Short	556,000	Short
Light sweet crude oil (Barrels)	—	—	361,988	Short
RBOB UL gasoline (Barrels)	99,000	Short	67,000	Short
Electricity (MWh)	98,318	Short	287,159	Short
Financial transmission rights (MWh)	252,621	Long	3,986,759	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, 2009 and 2008, the amount of the derivative gain (loss) recognized by line item in the consolidated statements of income is provided in the table below:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
	(millions of dollars)
Gain (Loss) Deferred as a Regulatory Asset/Liability	$	2		$	(15	)	$	(8	)	$	1
Gain (Loss) Reclassified from Regulatory Asset/Liability to Fuel and Purchased Energy Expense		(1	)		—			(6	)		—

As of September 30, 2009 and December 31, 2008, DPL had the following net outstanding natural gas commodity forward contracts that did not qualify for hedge accounting:

	September 30, 2009		December 31, 2008
Commodity	Quantity	Net Position	Quantity	Net Position
Natural Gas (MMBtu)	10,297,006	Long	8,928,750	Long

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Contingent Credit Risk Features

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

The collateral requirements under the ISDA or similar agreements generally work as follows. The parties establish a dollar threshold of unsecured credit for each party in excess of which the party would be required to post collateral to secure its obligations to the other party. The amount of the unsecured credit threshold varies according to the senior, unsecured debt rating of the respective parties or that of a guarantor of the party’s obligations. The fair values of all transactions between the parties are netted under the master netting provisions. Transactions may include derivatives accounted for on-balance sheet as well as normal purchases and normal sales that are accounted for off-balance sheet. If the aggregate fair value of the transactions in a net loss position exceeds the unsecured credit threshold, then collateral is required to be posted in an amount equal to the amount by which the unsecured credit threshold is exceeded. The obligations of the Competitive Energy business are usually guaranteed by PHI. The obligations of DPL are stand-alone obligations without the guaranty of PHI. If PHI’s or DPL’s credit rating were to fall below “investment grade,” the unsecured credit threshold would typically be set at zero and collateral would be required for the entire net loss position. Exchange-traded contracts do not contain this contingent credit risk feature related to credit rating as they are fully collateralized.

The gross fair value of PHI’s derivative liabilities, excluding the impact of offsetting transactions or collateral under master netting agreements, with credit risk-related contingent features on September 30, 2009, was $374 million. As of that date, PHI had posted cash collateral of $23 million in the normal course of business against the gross derivative liability resulting in a net liability of $351 million before giving effect to offsetting transactions that are encompassed within master netting agreements that would reduce this amount. PHI’s net settlement amount in the event of a downgrade of PHI and DPL below “investment grade” as of September 30, 2009, would have been approximately $255 million after taking into consideration the master netting agreements. The offsetting transactions or collateral that would reduce PHI’s obligation to the net settlement amount include derivatives and normal purchase and 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 primary credit facilities. At September 30, 2009, the aggregate amount of cash plus borrowing capacity under the primary credit facilities available to meet the future liquidity needs of PHI totaled $1.4 billion, of which $822 million was available for the Competitive Energy business.

(13) FAIR VALUE DISCLOSURES

Fair Value of Assets and Liabilities Excluding Debt

Effective January 1, 2008, PHI 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. PHI is able to classify fair value balances based on the observability of those inputs. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The

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hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurement) and the lowest priority to unobservable inputs (level 3 measurement). The three levels of the fair value hierarchy are as follows:

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

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

Level 3 – Pricing inputs include significant inputs that are generally less observable than those from objective sources. Level 3 includes those financial instruments that are valued using models or other valuation methodologies. Level 3 instruments classified as derivative assets are primarily power and capacity swaps. The majority of Conectiv Energy’s pricing information for its Level 3 valuations was obtained from a third party pricing system used widely throughout the energy industry.

Level 3 instruments classified as derivative liabilities are primarily natural gas options. Some non-standard assumptions are used in their forward valuation to adjust for the pricing; otherwise, most of the options follow NYMEX valuation. A few of the options have no significant NYMEX components, and have to be priced using internal volatility assumptions. Some of the options do not expire until December 2011. All of the options are part of the natural gas hedging program approved by the Delaware Public Service Commission.

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

The following tables set forth, by level within the fair value hierarchy, PHI’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2009 and December 31, 2008. 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, 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	$	66	$	8		$	36	(a)	$	22
Cash equivalents		22		22			—			—
Executive deferred compensation plan assets		74		14			42			18
	$	162	$	44		$	78		$	40
LIABILITIES
Derivative instruments	$	464	$	143	(b)	$	293		$	28
Executive deferred compensation plan liabilities		31		—			31			—
	$	495	$	143		$	324		$	28

(a) Includes a contra-asset balance of $2 million related to the impact of netting certain counterparties across the levels of the fair value hierarchy.

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(b) Includes a contra-liability balance of $4 million related to the impact of netting certain counterparties across the levels of the fair value hierarchy.

	Fair Value Measurements at December 31, 2008
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	$	139	$	53	$	79	$	7
Cash equivalents		460		460		—		—
Executive deferred compensation plan assets		70		11		41		18
	$	669	$	524	$	120	$	25
LIABILITIES
Derivative instruments	$	509	$	184	$	296	$	29
Executive deferred compensation plan liabilities		31		—		31		—
	$	540	$	184	$	327	$	29

Reconciliations of the beginning and ending balances of PHI’s fair value measurements using significant unobservable inputs (Level 3) for the nine months ended September 30, 2009 and 2008 are shown below:

	Nine Months Ended September 30, 2009
	Net Derivative Instruments Asset (Liability)			Deferred Compensation Plan Assets
	(millions of dollars)
Beginning balance as of January 1, 2009	$	(22	)	$	18
Total gains or (losses) (realized and unrealized)
Included in income		8			3
Included in accumulated other comprehensive (loss) income		25			—
Included in regulatory liabilities		(13	)		—
Purchases and issuances		—			(3	)
Settlements		3			—
Transfers in (out) of Level 3		(7	)		—
Ending balance as of September 30, 2009	$	(6	)	$	18

	Operating Revenue		Other Operation and Maintenance Expense
	(millions of dollars)
Gains or (losses) (realized and unrealized) included in income for the period above are reported in Operating Revenue and Other Operation and Maintenance Expense as follows:
Total gains (losses) included in income for the period above	$	8	$	3
Change in unrealized gains (losses) relating to assets still held at reporting date	$	5	$	3

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PEPCO HOLDINGS

	Nine Months Ended September 30, 2008
	Net Derivative Instruments Asset (Liability)			Deferred Compensation Plan Assets
	(millions of dollars)
Beginning balance as of January 1, 2008	$	(3	)	$	17
Total gains or (losses) (realized and unrealized)
Included in income		—			3
Included in accumulated other comprehensive (loss) income		—			—
Included in regulatory liabilities		2			—
Purchases and issuances		—			(3	)
Settlements		3			—
Transfers in (out) of Level 3		(8	)		—
Ending balance as of September 30, 2008	$	(6	)	$	17
	Operating Revenue			Other Operation and Maintenance Expense
	(millions of dollars)
Gains or (losses) (realized and unrealized) included in income for the period above are reported in Operating Revenue and Other Operation and Maintenance Expense as follows:
Total gains (losses) included in income for the period above	$	—		$	3
Change in unrealized gains (losses) relating to assets still held at reporting date	$	4		$	3

Fair Value of Debt Instruments

The estimated fair values of PHI’s non-derivative financial instruments at September 30, 2009 and December 31, 2008 are shown below:

	September 30, 2009				December 31, 2008
	(millions of dollars)
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	4,969	$	5,331	$	4,910	$	4,736
Transition Bonds issued by ACE Funding		411		443		433		431
Long-Term Project Funding		19		19		21		21
Redeemable Serial Preferred Stock		6		4		6		4

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The methods and assumptions described below were used to estimate, as of September 30, 2009 and December 31, 2008, 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, 2009 and December 31, 2008, or bid prices obtained from brokers if actual trade prices were not available. The fair values of Long-Term Debt and Transition Bonds issued by ACE Funding, including amounts due within one year, were derived based on current market prices, or were based on discounted cash flows using current rates for similar issues with similar credit ratings, terms, and remaining maturities for issues with no market price available.

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

The carrying amounts of all other financial instruments in Pepco Holdings’ accompanying financial statements approximate fair value.

(14) COMMITMENTS AND CONTINGENCIES

Regulatory and Other Matters

Proceeds from Settlement of Mirant Bankruptcy Claims

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

In March 2009, the DCPSC issued an order approving Pepco’s sharing proposal for the District of Columbia under which approximately $24 million was distributed to District of Columbia customers as a one-time billing credit. As a result of this decision, Pepco recorded a pre-tax gain of approximately $14 million for the quarter ended March 31, 2009.

On July 2, 2009, the MPSC approved a settlement agreement among Pepco, the Maryland Office of People’s Counsel (the Maryland OPC) and the MPSC staff under which Pepco distributed approximately $39 million to Maryland customers during the billing month of August 2009 through a one-time billing credit. As a result of this decision, Pepco recorded a pre-tax gain of $26 million in the quarter ended September 30, 2009.

As a consequence of the MPSC order, $64 million previously accounted for as restricted cash was released and the corresponding regulatory liability was extinguished.

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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 and natural gas service in Delaware and may be implemented either in the context of pending decoupling cases or DPL’s next Delaware base rate cases.

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

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

Delaware

In August 2008, DPL submitted its 2008 Gas Cost Rate (GCR) filing to the DPSC, requesting an increase in the level of GCR, which permits DPL to recover gas procurement costs through customer rates. In September 2008, the DPSC issued an initial order approving the requested increase, which became effective on November 1, 2008, subject to refund pending final DPSC approval after evidentiary hearings. Due to a significant decrease in wholesale gas prices, in January 2009, DPL submitted to the DPSC an interim GCR filing, requesting a decrease in the level of GCR. The proposed decrease, when combined with the increase that became effective November 1, 2008, would have the net effect of a 13.8% increase in the level of GCR. On February 5, 2009, the DPSC issued an initial order approving the net increase, effective on March 1, 2009, subject to refund pending final DPSC approval after evidentiary hearings. A hearing was held on May 27, 2009, during which a settlement agreement among DPL, DPSC staff and the Delaware Public Advocate was submitted to the Hearing Examiner. The settlement agreement provided that the proposed net increase would become final and no longer subject to refund. The DPSC approved the settlement agreement and closed this docket on October 6, 2009.

On August 31, 2009, DPL submitted its 2009 GCR filing to the DPSC, requesting a 10.2% decrease in the level of GCR, to become effective on a temporary basis on November 1, 2009. This rate proposal was approved by the DPSC on September 9, 2009, subject to refund and pending final DPSC approval.

On June 25, 2009, DPL filed two applications requesting approval for the implementation of the MFVRD for electric distribution rates and gas distribution rates, respectively. These filings are based on revenues established in DPL’s last electric and gas distribution base rate cases, and accordingly are revenue neutral. On August 4, 2009, the DPSC issued an order opening a docket for the MFVRD for gas distribution rates and on September 9, 2009, the DPSC issued an order opening a docket for the MFVRD for electric distribution rates. The electric MFVRD may be implemented in the pending base rate case rather than in connection with the June 25, 2009 filing.

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On September 18, 2009, DPL submitted an application with the DPSC to increase its electric distribution base rates. The filing seeks approval of an annual rate increase of approximately $29 million based on a requested return on equity (ROE) of 11.00%. (or, with the MFVRD, the requested rate increase would be reduced to approximately $28 million, based on an ROE of 10.75%). The procedural schedule has not yet been established. DPL intends to put an increase of $2.5 million annually into effect on a temporary basis on November 17, 2009, subject to refund and pending final DPSC approval, which is expected in April 2010.

District of Columbia

In December 2006, Pepco submitted an application to the DCPSC to increase electric distribution base rates, including a proposed BSA. In January 2008, the DCPSC approved, effective February 20, 2008, a revenue requirement increase of approximately $28 million, based on an authorized return on rate base of 7.96%, including a 10% ROE. However, the DCPSC did not approve the BSA at that time. While finding a BSA to be an appropriate ratemaking concept, the DCPSC cited potential statutory problems in its authority to implement the BSA. In February 2008, the DCPSC established a Phase II proceeding to consider these implementation issues. In August 2008, the DCPSC issued an order concluding that it has the necessary statutory authority to implement the BSA proposal and that further evidentiary proceedings are warranted to determine whether the BSA is just and reasonable. On September 28, 2009, the DCPSC approved Pepco’s BSA proposal, and ordered an adjustment in Pepco’s return on equity by 50 basis points upon implementation of the BSA (which would result in the original increase of $28 million being reduced to approximately $24 million, based on an ROE of 9.50%). The DCPSC authorized Pepco to apply the BSA to usage on or after November 1, 2009.

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

On May 22, 2009, Pepco submitted an application to the DCPSC to increase electric distribution base rates. The filing seeks approval of an annual rate increase of approximately $52 million, based on a requested ROE of 11.50% (or, with the BSA, the requested rate increase would be reduced to approximately $50 million, based on an ROE of 11.25%). The filing also proposes recovery of pension expenses and uncollectible costs through a surcharge mechanism. If the proposed surcharge mechanism is approved, the requested annual rate increase would be reduced by approximately $3 million. Hearings are scheduled for mid-November 2009 and a decision is expected from the DCPSC in early 2010.

Maryland

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

DPL and Pepco filed separate appeals from the MPSC’s July 2007, July 2008 and August 2008 orders. The appeals were consolidated in the Circuit Court for Baltimore City. In a consolidated brief filed on March 9, 2009, Pepco and DPL each contend that the MPSC erred in failing to implement permanent rates in accordance with Maryland law, and in its denial of their respective rights to recover an increased share of the PHI Service Company costs and the costs of performing a MPSC-mandated management audit. On August 31, 2009, the Circuit Court issued a decision in which it affirmed the MPSC concerning the recovery of PHI Service Company costs and its use of temporary rates at the

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conclusion of the statutory suspension period. The court reversed the MPSC’s order requiring the costs of MPSC-mandated management audits to be paid by the utilities’ shareholders. No appeals were filed within the 30-day appeal period and, therefore, the Circuit Court’s decision has become final.

On May 6, 2009, DPL filed a distribution base rate case in Maryland. The filing seeks approval of an annual rate increase of approximately $14 million, based on a requested ROE of 11.25%. The filing also proposes recovery of pension, OPEB and uncollectible expenses through a surcharge mechanism using a three-year average, with the difference between actual expense and the surcharge amount captured in a deferral balance. If the proposed surcharge mechanism is approved, the requested annual rate increase would be reduced by approximately $4 million. Hearings were held September 22 through September 25, 2009. A decision is expected in December 2009.

New Jersey

On February 20, 2009, ACE filed an application with the New Jersey Board of Public Utilities (NJBPU) (supplemented on February 23, 2009), which included a proposal for the implementation of a BSA. However, because a BSA mechanism has been proposed in the electric distribution base rate proceeding discussed in the next paragraph, the implementation of a BSA will be considered instead in that proceeding.

On August 14, 2009, ACE submitted a petition to the NJBPU to increase its electric distribution base rates, including a request for the implementation of a BSA. Based on a test year ending December 31, 2009, adjusted for known and measurable changes, ACE requested an annual net increase in its current retail distribution rates for electric service in the amount of approximately $54 million (which includes a reduction to its Regulatory Asset Recovery Charge) based on a requested ROE of 11.50% (or, if the BSA is approved, the requested rate increase would be reduced to approximately $52 million, based on an ROE of 11.25%). The procedural schedule has not yet been established.

Divestiture Cases

District of Columbia

In June 2000, the DCPSC approved a divestiture settlement under which Pepco is required to share with its District of Columbia customers the net proceeds realized by Pepco from the sale of its generation-related assets. An unresolved issue relating to the application filed with the DCPSC by Pepco to implement the divestiture settlement is whether Pepco should be required to share with customers the excess deferred income taxes (EDIT) and accumulated deferred investment tax credits (ADITC) associated with the sold assets and, if so, whether such sharing would violate the normalization provisions of the Internal Revenue Code and its implementing regulations. As of September 30, 2009, the District of Columbia allocated portions of EDIT and ADITC associated with the divested generating assets were approximately $6 million each. Other issues in the divestiture proceeding deal with the treatment of internal costs and cost allocations as deductions from the gross proceeds of the divestiture.

Pepco believes that a sharing of EDIT and ADITC would violate the IRS normalization rules. Under these rules, Pepco could not transfer the EDIT and the ADITC benefit to customers more quickly than on a straight line basis over the book life of the related assets. Since the assets are no longer owned by Pepco, there is no book life over which the EDIT and ADITC can be returned. If Pepco were required to share EDIT and ADITC and, as a result, the normalization rules were violated, Pepco would be unable to use accelerated depreciation on District of Columbia allocated or assigned property. In addition to sharing with customers the generation-related EDIT and ADITC balances, Pepco would have to pay to the IRS an amount equal to Pepco’s District of Columbia jurisdictional generation-related ADITC balance ($6 million as of September 30, 2009), as well as its District of Columbia jurisdictional transmission and distribution-related ADITC balance ($3 million as of September 30, 2009) in each case as those balances exist as of the later of the date a DCPSC order is issued and all rights to appeal have been exhausted or lapsed, or the date the DCPSC order becomes operative.

In March 2008, the IRS approved final regulations, effective March 20, 2008, which allow utilities whose assets cease to be utility property (whether by disposition, deregulation or otherwise) to return to its utility customers the normalization reserve for EDIT and part or all of the normalization reserve for ADITC. This ruling applies to assets divested after December 21, 2005. For utility property divested on or before December 21, 2005, the IRS stated that it would continue to follow the holdings set forth in private letter rulings prohibiting the flow through of EDIT and

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ADITC associated with the divested assets. Pepco made a filing in April 2008, advising the DCPSC of the adoption of the final regulations and requesting that the DCPSC issue an order consistent with the IRS position. If the DCPSC issues the requested order, no accounting adjustments to the gain recorded in 2000 would be required.

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

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

Maryland

Pepco filed its divestiture proceeds plan application with the MPSC in April 2001. The principal issue in the Maryland case is the same EDIT and ADITC sharing issue that has been raised in the District of Columbia case. See the discussion above under “Divestiture Cases — District of Columbia.” On July 2, 2009, the MPSC approved a settlement agreement among Pepco, the Maryland OPC and the MPSC staff with respect to all of the open divestiture plan issues. Under the settlement agreement, Pepco is permitted to retain the entire amount of the Maryland allocated portions of EDIT and ADITC (approximately $9 million and $10 million, respectively) associated with Pepco’s divested generating assets. As a result of the settlement, no accounting adjustments to the gain recorded in 2000 were required.

ACE Sale of B.L. England Generating Facility

In February 2007, ACE completed the sale of the B.L. England generating facility to RC Cape May Holdings, LLC (RC Cape May), an affiliate of Rockland Capital Energy Investments, LLC. In July 2007, ACE received a claim for indemnification from RC Cape May under the purchase agreement in the amount of $25 million. RC Cape May contends that one of the assets it purchased, a contract for terminal services (TSA) between ACE and Citgo Asphalt Refining Co. (Citgo), has been declared by Citgo to have been terminated due to a failure by ACE to renew the contract in a timely manner. The claim for indemnification seeks payment from ACE in the event the TSA is held not to be enforceable against Citgo.

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

General Litigation

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

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

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

Delilah Road Landfill Site. In 1991, the New Jersey Department of Environmental Protection (NJDEP) identified ACE as a potentially responsible party (PRP) at the Delilah Road Landfill site in Egg Harbor Township, New Jersey. In 1993, ACE, along with two other PRPs, signed an administrative consent order with NJDEP to remediate the site. The soil cap remedy for the site has been implemented and in August 2006, NJDEP issued a No Further Action Letter (NFA) and Covenant Not to Sue for the site. Among other things, the NFA requires the PRPs to monitor the effectiveness of institutional (deed restriction) and engineering (cap) controls at the site every two years. In September 2007, NJDEP approved the PRP group’s petition to conduct semi-annual, rather than quarterly, ground water monitoring for two years and deferred until the end of the two-year period a decision on the PRP group’s request for annual groundwater monitoring thereafter. In August 2007, the PRP group agreed to reimburse the costs of the U.S. Environmental Protection Agency (EPA) in the amount of $81,400 in full satisfaction of EPA’s claims for all past and future response costs relating to the site (of which ACE’s share is one-third). Effective April 2008, EPA and the PRP group entered into a settlement agreement which will allow EPA to reopen the settlement in the event of new information or unknown conditions at the site. Based on information currently available, ACE anticipates that its share of additional cost associated with this site for post-remedy operation and maintenance will be approximately $555,000 to $600,000. On November 23, 2008, Lenox, Inc., a member of the PRP group, filed a bankruptcy petition under Chapter 11 of the U.S. Bankruptcy Code. ACE has filed a proof of claim in the Lenox bankruptcy seeking damages resulting from the rejection by Lenox, Inc., of its cost sharing obligations to ACE. ACE believes that its liability for post-remedy operation and maintenance costs will not have a material adverse effect on its financial position, results of operations or cash flows regardless of the impact of the Lenox bankruptcy. On August 11, 2009, EPA published simultaneously in the Federal Register, a notice of intent to delete, and a final notice of deletion of the Delilah Road Landfill site from the national priorities list. EPA published these actions simultaneously because the agency considers them to be noncontroversial and routine. EPA is proposing delisting the site, having determined that all appropriate response actions under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA) have been completed.

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

Franklin Slag Pile Site. On November 26, 2008, ACE received a general notice letter from EPA concerning the Franklin Slag Pile site in Philadelphia, Pennsylvania, asserting that ACE is a PRP that may have liability with respect to the site. If liable, ACE would be responsible for reimbursing EPA for clean-up costs incurred and to be incurred by the agency and for the costs of implementing an EPA-mandated remedy. The EPA’s claims are based on ACE’s sale of boiler slag from the B.L. England generating facility to MDC Industries, Inc. (MDC) during the period June 1978 to May 1983 (ACE owned B.L. England at that time and MDC formerly operated the Franklin Slag Pile site). EPA further claims that the boiler slag ACE sold to MDC contained copper and lead, which are hazardous substances under 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 such claims made by the EPA. In a May 2009 decision arising under CERCLA, which did not involve ACE, the U.S. Supreme Court rejected an EPA argument that the sale of a useful product constituted an arrangement for disposal or treatment of hazardous substances. While this decision supports ACE’s position, at this time ACE cannot predict how EPA will proceed with respect to the Franklin Slag Pile site, or what portion, if any, of the Franklin Slag Pile site response costs EPA would seek to recover from ACE.

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

Ward Transformer Site. In April 2009, a group of PRPs at 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 that the group has cost recovery and/or contribution claims against ACE, DPL and Pepco with respect to past and future response costs incurred 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. Although it is too early in the process to characterize the magnitude of the potential liability at this site, based on interviews with long-time ACE, DPL, and Pepco employees and record reviews, it does not appear that any of the three PHI utilities had extensive business transactions, if any, with the Ward Transformer site.

Deepwater Generating Facility. In December 2005, NJDEP issued a Title V operating permit (the 2005 Permit) to Deepwater generating facility (Deepwater) owned by Conectiv Energy. In January 2006, Conectiv Energy filed an appeal with the New Jersey Office of Administrative Law (OAL) challenging several provisions of the 2005 Permit, including newly imposed limits on unit heat input (which is energy introduced to the boiler in the form of fuel). In an

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October 2007 order, the OAL granted a summary decision in favor of Conectiv Energy, finding that hourly heat input may not be used as a basis to condition or limit Conectiv Energy’s electric generating operations. In January 2008, NJDEP issued a revised Deepwater Title V operating permit (the 2008 Permit), which included the challenged conditions from the 2005 Permit, in response to which Conectiv Energy filed a second appeal with the OAL. In a December 2008 order, the OAL found in favor of Conectiv Energy in its challenge to the 2005 and 2008 Permits’ provision limiting annual fuel use and found in favor of NJDEP regarding Conectiv Energy’s challenge to an annual stack test requirement. In May 2009, NJDEP and Conectiv Energy entered into a Stipulation of Partial Settlement (the Stipulation) that would resolve all of Conectiv Energy’s challenges to the terms of the 2005 Permit and the 2008 Permit, other than the three permit provisions relating to heat input, annual fuel use, and annual stack testing that the OAL previously had addressed. On July 23, 2009, the OAL amended its October 2007 order in favor of Conectiv Energy to clarify that neither annual nor hourly heat input may be used as a basis to condition or limit Conectiv Energy’s electric generating operations. On July 29, 2009, the OAL issued its initial decision incorporating its October 2007 order (as amended July 23, 2009) and the Stipulation, and transmitted the matter to the NJDEP Commissioner for a final decision adopting, rejecting or modifying the OAL initial decision. The OAL’s July 29 initial decision addresses all of the outstanding issues that are the subject of Conectiv Energy appeals, subject to the final decision from the NJDEP Commissioner. NJDEP filed exceptions to the initial decision with the NJDEP Commissioner on August 19, 2009, to which Conectiv Energy replied on August 26, 2009. The NJDEP Commissioner is expected to adopt, modify or reject the OAL’s initial decision in the fourth quarter of 2009.

In April 2007, NJDEP issued an Administrative Order and Notice of Civil Administrative Penalty Assessment (the April 2007 Order) alleging that Deepwater Unit 1 exceeded the maximum allowable heat input in calendar year 2005 and that Unit 6/8 exceeded its maximum allowable heat input in calendar years 2005 and 2006. The April 2007 Order required the cessation of operation of Units 1 and 6/8 above the alleged permitted heat input levels, assessed a penalty of approximately $1 million and requested that Conectiv Energy provide additional information about heat input to Units 1 and 6/8. In May 2007, NJDEP issued a second Administrative Order and Notice of Civil Administrative Penalty Assessment (the May 2007 Order) alleging that Units 1 and 6/8 exceeded their maximum allowable heat input in calendar year 2004. The May 2007 Order required the cessation of operation of Units 1 and 6/8 above the alleged permitted heat input levels and assessed a penalty of $811,600. Conectiv Energy requested contested case hearings challenging the issuance of the April 2007 Order and the May 2007 Order. The OAL has placed these matters on inactive status until December 1, 2009 because these matters can not be resolved until the question of NJDEP’s authority to impose heat input limits is resolved by Conectiv Energy’s appeal of the 2005 Permit.

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 and that is otherwise regulated under a number of other state and federal programs. In November 2008, ACE filed an appeal of these regulations with the Appellate Division of the Superior Court of New Jersey. The appeal remains pending.

PHI’s Cross-Border Energy Lease Investments

Between 1994 and 2002, PCI, a subsidiary of PHI, entered into eight cross-border energy lease investments involving public utility assets (primarily consisting of hydroelectric generation and coal-fired electric generation facilities and natural gas distribution networks) located outside of the United States. Each of these investments is structured as a sale and leaseback transaction commonly referred to as a sale-in/lease-out or SILO transaction. PHI’s annual tax benefits from these eight cross-border energy lease investments are approximately $56 million. As of September 30, 2009, PHI’s equity investment in its cross-border energy leases was approximately $1.4 billion which included the impact of the reassessment discussed below. During the open tax periods under audit from January 1, 2001 to September 30, 2009, PHI has derived approximately $502 million in federal income tax benefits from the depreciation and interest deductions in excess of rental income with respect to these cross-border energy lease investments.

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

On March 31, 2009, the IRS issued its RAR for the calendar years 2003 to 2005 which among other items proposes to disallow the depreciation and interest deductions in excess of rental income claimed by PHI with respect to all eight of its cross-border energy lease investments and recharacterize the eight leases as loan transactions as to which PHI would be subject to original issue discount income. On May 29, 2009, PHI filed a protest with respect to these proposed adjustments, and the case has been forwarded to the Appeals Office. In the last several years, IRS challenges to certain cross-border lease transactions have been the subject of litigation. This litigation has resulted in several decisions in favor of the IRS that were factored into PHI’s decision to adjust the lease value at June 30, 2008. Under FASB guidance on income taxes (ASC 740), the financial statement recognition of an uncertain tax position is permitted only if it is more likely than not that the position will be sustained. Further, under FASB guidance on leases (ASC 840), a company is required to assess on a periodic basis the likely outcome of tax positions relating to its cross-border energy lease investments and, if there is a change or a projected change in the timing of the tax benefits generated by the transactions, the company is required to recalculate the value of its equity investment.

While PHI believes that its tax position with regard to its cross-border energy lease investments is appropriate based on applicable statutes, regulations and case law, after evaluating the court rulings described above, PHI at June 30, 2008 reassessed the sustainability of its tax position and revised its assumptions regarding the estimated timing of the tax benefits from its cross-border energy lease investments. Based on this reassessment, PHI for the quarter ended June 30, 2008, recorded an after-tax charge to net income of $93 million, consisting of the following components:

• A non-cash pre-tax charge of $124 million ($86 million after tax) to reduce the equity value of these cross-border energy lease investments. This pre-tax charge has been recorded in the consolidated statements of income as a reduction in other operating revenue.

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

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

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

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

• PHI would have been obligated to pay, as of June 30, 2008, approximately $510 million in additional federal and state taxes and $63 million of interest.

Based on the assumptions used to calculate the estimated additional tax and interest as of June 30, 2008, PHI estimates that, as of September 30, 2009, it would be obligated to pay approximately $595 million in additional federal and state taxes and $100 million of interest in the event of a total disallowance of the tax benefits and the imputing of original issue discount income due to the re-characterization of the leases as loans. In addition, the IRS could require PHI to pay a penalty of up to 20% on the amount of additional taxes due.

PHI anticipates that any additional taxes that it would be required to pay as a result of the disallowance of prior deductions or a re-characterization of the leases as loans would be recoverable in the form of lower taxes over the remaining terms of the affected leases. Moreover, the entire amount of any additional tax would not be due immediately. Rather, the federal and state taxes would be payable when the open audit years are closed and PHI amends subsequent tax returns not then under audit. To mitigate the taxes due in the event of a total disallowance of tax benefits, PHI could, were it to so elect, choose to liquidate all or a portion of its cross-border energy lease portfolio 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 $695 million noted above as the estimated obligation for federal and state taxes and interest in the event of a total disallowance of tax benefits and a recharacterization of the transactions as loans. Accordingly, based on current assumptions, the net cash impact to PHI of such a mitigation action would be slightly favorable. If payments of additional taxes and interest preceded the receipt of liquidation proceeds, the payments would be funded by currently available sources of liquidity.

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

As noted above, in the last several years, IRS challenges to certain cross-border lease transactions have been the subject of litigation. On October 21, 2009, the U.S. Court of Federal Claims issued a decision in favor of a taxpayer regarding a lease-in lease-out 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. PHI is currently evaluating the implications of this decision.

IRS Mixed Service Cost Issue

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

In 2005, the IRS issued Revenue Ruling 2005-53, which limited the ability of Pepco, DPL and ACE to utilize its tax accounting method on their 2001 through 2004 tax returns. In accordance with this Revenue Ruling, the RAR for the 2001 and 2002 tax returns disallowed substantially all of the incremental tax benefits that Pepco, DPL and ACE had claimed on those returns.

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

District of Columbia Tax Legislation

On August 26, 2009, the Mayor of the District of Columbia signed emergency legislation that adopts mandatory combined unitary business tax reporting effective for tax year 2011, and revises the related party expense disallowance tax rules effective for tax year 2009. While effective as of August 26, 2009, the emergency legislation will automatically expire after a 90-day period. In addition, on September 22, 2009, the District of Columbia Council passed permanent legislation that contains provisions related to combined unitary business tax reporting and related party expense disallowance that are nearly identical to the emergency legislation. The permanent legislation is subject to a 30-day Congressional review period and, if Congress does not intervene during this 30-day period, the permanent legislation will become binding law. Because of this 30-day period, PHI believes that the legislative process was not complete as of September 30, 2009, and, therefore, the effect of the permanent legislation (both for combined unitary business tax reporting and related party expense disallowance) was not accounted for as of September 30, 2009. The 30-day Congressional review period should be complete in the fourth quarter of 2009.

The permanent legislation does not define the term “unitary business” and does not specify how combined tax reporting would differ from our current consolidated tax reporting in the District of Columbia. However, based upon PHI’s interpretation of combined unitary business tax reporting in other taxing jurisdictions, the legislation would likely result in a change in PHI’s overall state income tax rate and, therefore, would likely require an adjustment to PHI’s net deferred income tax liabilities. Further, to the extent that the change in rate increases net deferred income tax liabilities of a regulated utility subsidiary, PHI must determine if these increased tax liabilities are probable of recovery in future rates. The related party expense disallowance provisions of the permanent legislation would likely result in a change in PHI’s overall state income tax rate.

Management is currently analyzing the impact of this legislation on the financial position, results of operations and cash flows of PHI and its subsidiaries.

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

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

As of September 30, 2009, Pepco Holdings and its subsidiaries were parties to a variety of agreements pursuant to which they were guarantors for standby letters of credit, performance residual value, and other commitments and obligations. The commitments and obligations, in millions of dollars, were as follows:

	Guarantor
	PHI		DPL		ACE		Other		Total
Energy marketing obligations of Conectiv Energy (a)	$	181	$	—	$	—	$	—	$	181
Energy procurement obligations of Pepco Energy Services (a)		492		—		—		—		492
Guaranteed lease residual values (b)		1		4		2		1		8
Other (c)		1		—		—		—		1
Total	$	675	$	4	$	2	$	1	$	682

(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.

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(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, 2009, obligations under the guarantees were approximately $8 million. Assets leased under agreements subject to residual value guarantees are typically for periods ranging from 2 years to 10 years. Historically, payments under the guarantees have not been made by the guarantor as, under normal conditions, the contract runs to full term at which time the residual value is minimal. As such, Pepco Holdings believes the likelihood of payment being required under the guarantee is remote.

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

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

Dividends

On October 22, 2009, Pepco Holdings’ Board of Directors declared a dividend on common stock of 27 cents per share payable December 31, 2009, to shareholders of record on December 10, 2009.

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POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
	(millions of dollars)
Operating Revenue	$	648		$	728		$	1,743		$	1,792
Operating Expenses
Purchased energy		350			431			972			1,033
Other operation and maintenance		84			80			244			227
Depreciation and amortization		36			36			108			105
Other taxes		83			80			230			219
Effect of settlement of Mirant bankruptcy claims		(26	)		—			(40	)		—
Total Operating Expenses		527			627			1,514			1,584
Operating Income		121			101			229			208
Other Income (Expenses)
Interest and dividend income		—			2			1			8
Interest expense		(25	)		(23	)		(75	)		(70	)
Other income		2			1			7			6
Other expenses		—			(1	)		(1	)		(2	)
Total Other Expenses		(23	)		(21	)		(68	)		(58	)
Income Before Income Tax Expense		98			80			161			150
Income Tax Expense		40			34			67			58
Net Income		58			46			94			92
Retained Earnings at Beginning of Period		660			623			624			597
Dividends Paid to Parent		—			(44	)		—			(64	)
Retained Earnings at End of Period	$	718		$	625		$	718		$	625

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

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POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

(Unaudited)

	September 30, 2009			December 31, 2008
	(millions of dollars)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	154		$	146
Accounts receivable, less allowance for uncollectible accounts of $17 million and $15 million, respectively		389			377
Inventories		47			45
Prepayments of income taxes		120			151
Prepaid expenses and other		23			23
Total Current Assets		733			742
INVESTMENTS AND OTHER ASSETS
Regulatory assets		163			169
Prepaid pension expense		295			142
Investment in trust		26			24
Restricted cash equivalents		—			102
Income taxes receivable		60			36
Assets and accrued interest related to uncertain tax positions		—			29
Other		75			70
Total Investments and Other Assets		619			572
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		5,780			5,607
Accumulated depreciation		(2,454	)		(2,371	)
Net Property, Plant and Equipment		3,326			3,236
TOTAL ASSETS	$	4,678		$	4,550

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

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POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

(Unaudited)

	September 30, 2009		December 31, 2008
	(millions of dollars, except shares)
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Short-term debt	$	—	$	125
Current maturities of long-term debt		16		50
Accounts payable and accrued liabilities		152		187
Accounts payable due to associated companies		71		70
Capital lease obligations due within one year		7		6
Taxes accrued		45		44
Interest accrued		37		19
Liabilities and accrued interest related to uncertain tax positions		—		24
Other		127		94
Total Current Liabilities		455		619
DEFERRED CREDITS
Regulatory liabilities		145		239
Deferred income taxes, net		876		788
Investment tax credits		9		10
Other postretirement benefit obligation		50		49
Income taxes payable		—		7
Other		85		59
Total Deferred Credits		1,165		1,152
LONG-TERM LIABILITIES
Long-term debt		1,538		1,445
Capital lease obligations		96		99
Total Long-Term Liabilities		1,634		1,544
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		706		611
Retained earnings		718		624
Total Equity		1,424		1,235
TOTAL LIABILITIES AND EQUITY	$	4,678	$	4,550

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,
	2009			2008
	(millions of dollars)
OPERATING ACTIVITIES
Net income	$	94		$	92
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		108			105
Effect of settlement of Mirant bankruptcy claims		(40	)		—
Changes in restricted cash related to Mirant settlement		102			317
Deferred income taxes		101			60
Changes in:
Accounts receivable		(12	)		(61	)
Regulatory assets and liabilities, net		(55	)		(315	)
Accounts payable and accrued liabilities		(25	)		14
Pension contributions		(170	)		—
Taxes accrued		56			(31	)
Interest accrued		18			16
Other assets and liabilities		5			(5	)
Net Cash From Operating Activities		182			192
INVESTING ACTIVITIES
Investment in property, plant and equipment		(196	)		(202	)
Changes in restricted cash		—			(20	)
Net other investing activities		(3	)		(1	)
Net Cash Used By Investing Activities		(199	)		(223	)
FINANCING ACTIVITIES
Dividends paid to Parent		—			(64	)
Capital contribution from Parent		94			78
Issuances of long-term debt		110			250
Reacquisition of long-term debt		(50	)		(188	)
Repayments of short-term debt, net		(125	)		(12	)
Net other financing activities		(4	)		(13	)
Net Cash From Financing Activities		25			51
Net Increase in Cash and Cash Equivalents		8			20
Cash and Cash Equivalents at Beginning of Period		146			19
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	154		$	39
NONCASH ACTIVITIES
Asset retirement obligations associated with removal costs transferred to regulatory liabilities	$	4		$	6
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash (received) paid for income taxes (includes payments to PHI for Federal income taxes)	$	(86	)	$	41

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

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NOTES TO FINANCIAL STATEMENTS

POTOMAC ELECTRIC POWER COMPANY

(1) ORGANIZATION

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

(2) SIGNIFICANT ACCOUNTING POLICIES

Financial Statement Presentation

Pepco’s unaudited financial statements are prepared in conformity with accounting principles generally accepted in the United States of America (GAAP). Pepco adopted the Financial Standards Accounting Board (FASB) Accounting Standards Codification (ASC), which is the single source reference system for all authorative U.S. GAAP, as discussed in Note 3, “Newly Adopted Accounted Standards.” Pursuant to the rules and regulations of the Securities and Exchange Commission, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been omitted. Therefore, these financial statements should be read along with the annual financial statements included in Pepco’s Annual Report on Form 10-K for the year ended December 31, 2008. In the opinion of Pepco’s management, the financial statements contain all adjustments (which all are of a normal recurring nature) necessary to present fairly Pepco’s financial condition as of September 30, 2009, in accordance with GAAP. The year-end balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP. Interim results for the three and nine months ended September 30, 2009 may not be indicative of results that will be realized for the full year ending December 31, 2009 since the sales of electric energy are seasonal. Pepco has evaluated all subsequent events through October 29, 2009, the date of issuance of the financial statements to which these Notes relate.

Consolidation of Variable Interest Entities

Due to a variable element in the pricing structure of Pepco’s purchase power agreement with Panda-Brandywine, L.P. (Panda) entered into in 1991, pursuant to which Pepco was obligated to purchase from Panda 230 megawatts of capacity and energy annually through 2021 (Panda PPA), Pepco potentially assumed the variability in the operations of the plants related to the Panda PPA and therefore had a variable interest in the entity. During the third quarter of 2008, Pepco transferred the Panda PPA to Sempra Energy Trading LLP (Sempra). Net purchase activities with the counterparty to the Panda PPA for the three and nine months ended September 30, 2008 were approximately $17 million and $59 million, respectively.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in Pepco’s gross revenues were $71 million and $67 million for the three months ended September 30, 2009 and 2008, respectively, and $194 million and $183 million for the nine months ended September 30, 2009 and 2008, 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 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 Fuel and Purchased Energy expenses for the three months ended September 30, 2009 of $1 million.

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In the third quarter of 2008, PHI identified an error in the accounting for certain of its restricted stock awards under the Long-Term Incentive Plan which resulted in an understatement of Pepco’s stock-based compensation expense in 2006 and 2007. This error was corrected in the third quarter of 2008, resulting in an increase in Pepco’s Other Operation and Maintenance expenses for the three and nine months ended September 30, 2008 of $3 million.

In the second quarter of 2008, Pepco recorded an adjustment to correct errors in Other Operation and Maintenance expenses for prior periods dating back to February 2005 for which late payment fees were incorrectly recognized. This adjustment resulted in an increase in Other Operation and Maintenance expenses for the nine months ended September 30, 2008 of $3 million.

(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Business Combinations (ASC 805)

The accounting guidance on business combinations was amended by the FASB effective beginning January 1, 2009. The amendment did not change the fundamental concepts that the acquisition method of accounting be used and that an acquirer must be identified for each business combination. However, the guidance expanded the definition of a business subject to this guidance and also requires the acquirer to recognize changes in the amount of its deferred tax benefits that are realizable because of a business combination either in income from continuing operations or directly in contributed capital, depending on the circumstances.

On April 1, 2009, the FASB issued additional guidance to clarify the accounting for the initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. The additional guidance requires that assets acquired and liabilities assumed in a business combination that arise from contingencies be measured at fair value if the acquisition date fair value of that asset and liability can be determined during the measurement period. If the acquisition date fair value cannot be determined, then the asset or liability would be measured in accordance with FASB guidance on contingencies (ASC 450).

The new guidance applies prospectively to business combinations for which the acquisition date is on or after January 1, 2009. The adoption of the guidance did not have a material impact on Pepco’s overall financial condition, results of operations, or cash flows.

Fair Value Measurement and Disclosures (ASC 820)

There is a variety of new accounting guidance from the FASB that is effective for different financial reporting periods during 2009. Nonrecurring fair value measurement guidance for non-financial assets and non-financial liabilities was effective beginning January 1, 2009 for Pepco. The adoption of this guidance did not have a material impact on the fair value measurements of Pepco’s non-financial assets and non-financial liabilities.

Effective beginning with the June 30, 2009 financial statements, Pepco began disclosing the fair values of its financial instruments each quarter in accordance with FASB guidance. This new guidance is effective for interim reporting periods ending after June 15, 2009 and disclosures for the prior year-end balance sheet are required. The primary impact of the new guidance is disclosing the fair value of debt issued by Pepco on a quarterly basis in Note (9), “Fair Value Disclosures.”

Consolidation (ASC 810)

The FASB established new accounting and reporting standards for a non-controlling interest (also called a “minority interest”) in a subsidiary and for the deconsolidation of a subsidiary. The new guidance clarified that a non-controlling interest in a subsidiary is an ownership interest in the consolidated entity that should be separately reported in the consolidated financial statements.

The guidance was effective prospectively for financial statement reporting periods beginning January 1, 2009 for Pepco, except for the financial statement presentation and disclosure requirements which also apply to prior reporting periods presented. As of January 1, 2009, Pepco adopted the provisions of this guidance and the provisions did not have a material impact on Pepco’s overall financial condition, results of operations, or cash flows.

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Subsequent Events (ASC 855)

Beginning with its June 30, 2009 financial statements, Pepco adopted new FASB guidelines for the disclosure of events that occur after the balance sheet reporting date but before the financial statements are issued. The new guidance requires the disclosure of the date through which Pepco has assessed the impact of subsequent events on the financial statements. The new guidance was effective for interim or annual financial periods ending after June 15, 2009. Pepco has disclosed this subsequent events date in Note (2), “Significant Accounting Policies.”

FASB Accounting Standards Codification (ASC 105)

The ASC identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of non-governmental financial statements presented under GAAP. In addition, it replaces the current reference system for standards and guidance with a new numerical designation system known as the ASC. The ASC will be the single source reference system for all authoritative GAAP. The ASC is numerically organized by topic, subtopic, section, and subsection.

The ASC is effective for financial statements issued for interim and annual periods ending after September 15, 2009. Pepco has adopted the ASC guidance and referencing system for GAAP in its September 30, 2009 financial statements. Entities are not required to revise previous financial statements for the change in references to GAAP. The adoption of ASC did not result in a change in accounting principle for Pepco; therefore, it did not have a material impact on Pepco’s overall financial condition, results of operations, or cash flows.

(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Transfers and Servicing (ASC 860)

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

The new guidance is effective for transfers of financial assets occurring in fiscal periods beginning after November 15, 2009, therefore, this guidance will be effective on January 1, 2010 for Pepco. Comparative disclosures are encouraged but not required for earlier periods presented. Pepco is evaluating the impact that this new guidance will have on its overall financial condition and financial statements.

Fair Value Measurement of Liabilities (ASC 820)

The FASB issued new guidance on the fair value measurement of liabilities when there is a lack of observable market information. The guidance clarifies that, when a quoted price is not available for the identical liability, an entity can use either the quoted price of the identical liability when it is traded as an asset, quoted price for a similar liability, or quoted price for a similar liability when traded as an asset. If these prices are not available, then entities can employ an income or market valuation approach that considers what the entity would pay to transfer the identical liability or would receive to enter into the identical liability. The guidance is effective for Pepco starting October 1, 2009. We are assessing the impact of this new guidance on Pepco’s overall financial condition and financial statements.

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(5) SEGMENT INFORMATION

Based on the provisions of FASB guidance on segment reporting (ASC 280), Pepco has one segment, its regulated utility business.

(6) PENSIONS AND OTHER POSTRETIREMENT BENEFITS

Pepco accounts for its participation in the Pepco Holdings benefit plans as participation in a multi-employer plan. PHI’s pension and other postretirement net periodic benefit cost for the three months ended September 30, 2009 before intercompany allocations from the PHI Service Company, of $36 million included $9 million for Pepco’s allocated share. PHI’s pension and other postretirement net periodic benefit cost for the nine months ended September 30, 2009 of $111 million included $28 million for Pepco’s allocated share. PHI’s pension and other postretirement net periodic benefit cost for the three months ended September 30, 2008, of $16 million, before intercompany allocations, included $6 million for Pepco’s allocated share. PHI’s pension and other postretirement net periodic benefit cost for the nine months ended September 30, 2008 of $48 million included $18 million for Pepco’s allocated share.

(7) DEBT

Credit Facilities

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

At September 30, 2009 and December 31, 2008, 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 $581 million and $843 million, respectively.

(8) INCOME TAXES

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

	For The Three Months Ended September 30,				For The Nine Months Ended September 30,
	2009		2008		2009		2008
Federal statutory rate	35.0	%	35.0	%	35.0	%	35.0	%
Increases (decreases) resulting from:
Depreciation	1.2		1.6		2.2		2.6
Asset removal costs	(1.1	)	(.7	)	(1.4	)	(1.9	)
State income taxes, net of federal effect	5.4		5.9		5.5		5.9
Software amortization	.4		.6		.7		1.1
Tax credits	(.4	)	(.6	)	(.8	)	(1.0	)
Change in estimates and interest related to uncertain and effectively settled tax positions	.8		1.0		1.6		(1.8	)
Interest on state income tax refund, net of federal effect	—		(.4	)	—		(1.7	)
Adjustment to prior years’ taxes	.2		1.1		.1		.6
Permanent differences related to deferred compensation funding	(.3	)	—		(.4	)	.4
Other, net	(.4	)	(.2	)	(.9	)	(.1	)
Effective Income Tax Rate	40.8	%	43.3	%	41.6	%	39.1	%

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Pepco’s effective tax rates for the three months ended September 30, 2009 and 2008 were 40.8% and 43.3%, respectively. The decrease in the rate resulted from a lower adjustment for prior year taxes and depreciation in 2009 as compared to 2008. This is partially offset by the benefit related to the interest on the state income tax refund received in the third quarter of 2008.

Pepco’s effective tax rates for the nine months ended September 30, 2009 and 2008 were 41.6% and 39.1%, respectively. The increase in the rate primarily resulted from the change in estimates and interest related to uncertain tax positions which was the result of the reduction in previously accrued interest and estimates resulting from the settlement of the mixed service cost issue. Also contributing to the increase in the rate was the 2008 benefit recorded for interest received on the state income tax refund.

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.

In October 2009, PHI filed a claim with the IRS requesting a Federal income tax refund of approximately $138 million, a substantial portion of which is associated with PHI’s utility subsidiaries. The refund results from the carry back of a 2008 net operating loss for tax reporting purposes that reflected, among other things, significant tax deductions related to accelerated depreciation, the pension plan contributions paid in 2009 (which were deductible for 2008) and the cumulative effect of adopting a new method of tax reporting for certain repairs. The timing of receipt of the refund is uncertain, however, after a 45-day period, interest would begin to accrue on the amount of the refund.

During the third quarter of 2009, as a result of a change in tax accounting methods related to certain repairs, Pepco’s uncertain tax benefits related to current year tax positions increased by $23 million, none of which, if recognized, would affect the effective tax rate.

(9) FAIR VALUE DISCLOSURES

Fair Value of Assets and Liabilities Excluding Debt

Effective January 1, 2008, Pepco 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. Pepco is able to classify fair value balances based on the observability of those 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). The three levels of the fair value hierarchy are as follows:

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

Level 2 – Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using broker quotes in liquid markets, and other observable pricing data. Level 2 also includes those financial instruments that are valued using internally developed methodologies that have been corroborated by observable market data through

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correlation or by other means. Significant assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

Level 3 – Pricing inputs include significant inputs that are generally less observable than those from objective sources. Level 3 includes those financial investments that are valued using models or other valuation methodologies. Level 3 instruments classified as executive deferred compensation plan assets are life insurance policies that are valued using the cash surrender value of the policies. Since these values do not represent a quoted price in an active market they are considered level 3.

The following tables sets forth by level within the fair value hierarchy Pepco’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2009 and December 31, 2008. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Pepco’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Fair Value Measurements at September 30, 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	$	63	$	10	$	36	$	17
	$	63	$	10	$	36	$	17
LIABILITIES
Executive deferred compensation plan liabilities	$	13	$	—	$	13	$	—
	$	13	$	—	$	13	$	—
	Fair Value Measurements at December 31, 2008
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	$	236	$	236	$	—	$	—
Executive deferred compensation plan assets		59		7		35		17
	$	295	$	243	$	35	$	17
LIABILITIES
Executive deferred compensation plan liabilities	$	13	$	—	$	13	$	—
	$	13	$	—	$	13	$	—

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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, 2009 and 2008 are shown below:

	Nine Months Ended September 30, 2009
	Deferred Compensation Plan Assets
	(millions of dollars)
Beginning balance as of January 1, 2009	$	17
Total gains or (losses) (realized and unrealized)
Included in income		3
Included in accumulated other comprehensive (losses) income		—
Purchases and issuances		(3	)
Settlements		—
Transfers in (out) of Level 3		—
Ending balance as of September 30, 2009	$	17
	Other Operation and Maintenance Expense
	(millions of dollars)
Gains or (losses) (realized and unrealized) included in income for the period above are reported in Other Operation and Maintenance Expense as follows:
Total gains included in income for the period above	$	3
Change in unrealized gains relating to assets still held at reporting date	$	3
	Nine Months Ended September 30, 2008
	Deferred Compensation Plan Assets
	(millions of dollars)
Beginning balance as of January 1, 2008	$	16
Total gains or (losses) (realized and unrealized)
Included in income		3
Included in accumulated other comprehensive (losses) income		—
Purchases and issuances		(3	)
Settlements		—
Transfers in (out) of Level 3		—
Ending balance as of September 30, 2008	$	16
	Other Operation and Maintenance Expense
	(millions of dollars)
Gains or (losses) (realized and unrealized) included in income for the period above are reported in Other Operation and Maintenance Expense as follows:
Total gains (losses) included in income for the period above	$	3
Change in unrealized gains (losses) relating to assets still held at reporting date	$	3

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Fair Value of Debt Instruments

The estimated fair values of Pepco’s non-derivative financial instruments as of September 30, 2009 and December 31, 2008 are shown below:

	September 30, 2009				December 31, 2008
	(millions of dollars)
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	1,554	$	1,724	$	1,495	$	1,474

The fair values of the Long-Term Debt, which include First Mortgage Bonds and Medium-Term Notes, including amounts due within one year, were based on the current market prices, or were based on discounted cash flows using current rates for similar issues with similar terms and remaining maturities for issues with no market price available.

(10) COMMITMENTS AND CONTINGENCIES

Regulatory and Other Matters

Proceeds from Settlement of Mirant Bankruptcy Claims

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

In March 2009, the DCPSC issued an order approving Pepco’s sharing proposal for the District of Columbia under which approximately $24 million was distributed to District of Columbia customers as a one-time billing credit. As a result of this decision, Pepco recorded a pre-tax gain of approximately $14 million for the quarter ended March 31, 2009.

On July 2, 2009, the MPSC approved a settlement agreement among Pepco, the Maryland Office of People’s Counsel (the Maryland OPC) and the MPSC staff under which Pepco distributed approximately $39 million to Maryland customers during the billing month of August 2009 through a one-time billing credit. As a result of this decision, Pepco recorded a pre-tax gain of $26 million in the quarter ended September 30, 2009.

As a consequence of the MPSC order, $64 million previously accounted for as restricted cash was released and the corresponding regulatory liability was extinguished.

Rate Proceedings

In recent electric service distribution base rate cases, Pepso has proposed the adoption of revenue decoupling methods for retail customers. To date, a bill stabilization adjustment mechanism (BSA) has been approved and implemented for electric service in Maryland and the District of Columbia. Under the BSA, customer delivery rates are subject to adjustment (through a credit or surcharge mechanism), depending on whether actual distribution revenue per customer

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

District of Columbia

In December 2006, Pepco submitted an application to the DCPSC to increase electric distribution base rates, including a proposed BSA. In January 2008, the DCPSC approved, effective February 20, 2008, a revenue requirement increase of approximately $28 million, based on an authorized return on rate base of 7.96%, including a 10% return on equity (ROE). However, the DCPSC did not approve the BSA at that time. While finding a BSA to be an appropriate ratemaking concept, the DCPSC cited potential statutory problems in its authority to implement the BSA. In February 2008, the DCPSC established a Phase II proceeding to consider these implementation issues. In August 2008, the DCPSC issued an order concluding that it has the necessary statutory authority to implement the BSA proposal and that further evidentiary proceedings are warranted to determine whether the BSA is just and reasonable. On September 28, 2009, the DCPSC approved Pepco’s BSA proposal, and ordered an adjustment in Pepco’s return on equity by 50 basis points upon implementation of the BSA (which would result in the original increase of $28 million being reduced to approximately $24 million, based on an ROE of 9.50%). The DCPSC authorized Pepco to apply the BSA to usage on or after November 1, 2009.

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

On May 22, 2009, Pepco submitted an application to the DCPSC to increase electric distribution base rates. The filing seeks approval of an annual rate increase of approximately $52 million, based on a requested ROE of 11.50% (or, with the BSA, the requested rate increase would be reduced to approximately $50 million, based on an ROE of 11.25%). The filing also proposes recovery of pension expenses and uncollectible costs through a surcharge mechanism. If the proposed surcharge mechanism is approved, the requested annual rate increase would be reduced by approximately $3 million. Hearings are scheduled for mid-November 2009 and a decision is expected from the DCPSC in early 2010.

Maryland

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

Pepco filed an appeal from the MPSC’s July 2007, July 2008 and August 2008 orders. The appeal was consolidated in the Circuit Court for Baltimore City with an appeal filed by DPL. In a brief filed on March 9, 2009, Pepco contends that the MPSC erred in failing to implement permanent rates in accordance with Maryland law, and in its denial of Pepco’s rights to recover an increased share of the PHI Service Company costs and the costs of performing a MPSC-mandated management audit. On August 31, 2009, the Circuit Court issued a decision in which it affirmed the MPSC

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concerning the recovery of PHI Service Company costs and its use of temporary rates at the conclusion of the statutory suspension period. The court reversed the MPSC’s order requiring the costs of MPSC-mandated management audits to be paid by Pepco’s shareholders. No appeals were filed within the 30-day appeal period and, therefore, the Circuit Court’s decision has become final.

Divestiture Cases

District of Columbia

In June 2000, the DCPSC approved a divestiture settlement under which Pepco is required to share with its District of Columbia customers the net proceeds realized by Pepco from the sale of its generation-related assets. An unresolved issue relating to the application filed with the DCPSC by Pepco to implement the divestiture settlement is whether Pepco should be required to share with customers the excess deferred income taxes (EDIT) and accumulated deferred investment tax credits (ADITC) associated with the sold assets and, if so, whether such sharing would violate the normalization provisions of the Internal Revenue Code and its implementing regulations. As of September 30, 2009, the District of Columbia allocated portions of EDIT and ADITC associated with the divested generating assets were approximately $6 million each. Other issues in the divestiture proceeding deal with the treatment of internal costs and cost allocations as deductions from the gross proceeds of the divestiture.

Pepco believes that a sharing of EDIT and ADITC would violate the IRS normalization rules. Under these rules, Pepco could not transfer the EDIT and the ADITC benefit to customers more quickly than on a straight line basis over the book life of the related assets. Since the assets are no longer owned by Pepco, there is no book life over which the EDIT and ADITC can be returned. If Pepco were required to share EDIT and ADITC and, as a result, the normalization rules were violated, Pepco would be unable to use accelerated depreciation on District of Columbia allocated or assigned property. In addition to sharing with customers the generation-related EDIT and ADITC balances, Pepco would have to pay to the IRS an amount equal to Pepco’s District of Columbia jurisdictional generation-related ADITC balance ($6 million as of September 30, 2009), as well as its District of Columbia jurisdictional transmission and distribution-related ADITC balance ($3 million as of September 30, 2009) in each case as those balances exist as of the later of the date a DCPSC order is issued and all rights to appeal have been exhausted or lapsed, or the date the DCPSC order becomes operative.

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

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

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

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Maryland

Pepco filed its divestiture proceeds plan application with the MPSC in April 2001. The principal issue in the Maryland case is the same EDIT and ADITC sharing issue that has been raised in the District of Columbia case. See the discussion above under “Divestiture Cases — District of Columbia.” On July 2, 2009, the MPSC approved a settlement agreement among Pepco, the Maryland OPC and the MPSC staff with respect to all of the open divestiture plan issues. Under the settlement agreement, Pepco is permitted to retain the entire amount of the Maryland allocated portions of EDIT and ADITC (approximately $9 million and $10 million, respectively) associated with Pepco’s divested generating assets. As a result of the settlement, no accounting adjustments to the gain recorded in 2000 were required.

General Litigation

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

Since the initial filings in 1993, additional individual suits have been filed against Pepco, and significant numbers of cases have been dismissed. As a result of two motions to dismiss, numerous hearings and meetings and one motion for summary judgment, Pepco has had approximately 400 of these cases successfully dismissed with prejudice, either voluntarily by the plaintiff or by the court. As of September 30, 2009, there are approximately 180 cases still pending against Pepco in the State Courts of Maryland, of which approximately 90 cases were filed after December 19, 2000, and were tendered to Mirant for defense and indemnification pursuant to the terms of the Asset Purchase and Sale Agreement between Pepco and Mirant under which Pepco sold its generation assets to Mirant in 2000.

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

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, or for costs EPA has incurred in cleaning up the site. EPA’s letter states that Peck Iron and Metal purchased, processed, stored and shipped metal scrap from military bases, governmental agencies and businesses and that Peck’s metal scrap operations resulted in the improper storage and disposal of hazardous substances. EPA bases its allegation that Pepco arranged for disposal or treatment of hazardous substances sent to the site on information provided by Peck Iron and Metal personnel, who informed the EPA that Pepco was a customer at the site. Pepco has

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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.

Ward Transformer Site. In April 2009, a group of PRPs at 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 that the group has cost recovery and/or contribution claims against Pepco with respect to past and future response costs incurred 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. Although it is too early in the process to characterize the magnitude of the potential liability at this site, based on interviews with long-time Pepco employees and record reviews, it does not appear Pepco had extensive business transactions, if any, with the Ward Transformer site.

IRS Mixed Service Cost Issue

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

In 2005, the IRS issued Revenue Ruling 2005-53, which limited the ability of Pepco to utilize its tax accounting method on its 2001 through 2004 tax returns. In accordance with this Revenue Ruling, the RAR for the 2001 and 2002 tax returns disallowed substantially all of the incremental tax benefits that Pepco had claimed on those returns.

In March 2009, PHI reached a settlement with the IRS for all years (2001 through 2004). The terms of the settlement reduced the tax benefits related to the mixed service costs deductions by $17 million for Pepco.

District of Columbia Tax Legislation

On August 26, 2009, the Mayor of the District of Columbia signed emergency legislation that adopts mandatory combined unitary business tax reporting effective for tax year 2011, and revises the related party expense disallowance tax rules effective for tax year 2009. While effective as of August 26, 2009, the emergency legislation will automatically expire after a 90-day period. In addition, on September 22, 2009, the District of Columbia Council passed permanent legislation that contains provisions related to combined unitary business tax reporting and related party expense disallowance that are nearly identical to the emergency legislation. The permanent legislation is subject to a 30-day Congressional review period and, if Congress does not intervene during this 30-day period, the permanent legislation will become binding law. Because of this 30-day period, Pepco believes that the legislative process was not complete as of September 30, 2009, and, therefore, the effect of the permanent legislation (both for combined unitary business tax reporting and related party expense disallowance) was not accounted for as of September 30, 2009. The 30-day Congressional review period should be complete in the fourth quarter of 2009.

The permanent legislation does not define the term “unitary business” and does not specify how combined tax reporting would differ from our current consolidated tax reporting in the District of Columbia. However, based upon Pepco’s interpretation of combined unitary business tax reporting in other taxing jurisdictions, the legislation would likely result in a change in Pepco’s overall state income tax rate and, therefore, would likely require an adjustment to Pepco’s net deferred income tax liabilities. Further, to the extent that the change in rate increases net deferred income tax liabilities, Pepco must determine if these increased tax liabilities are probable of recovery in future rates. The related party expense disallowance provisions of the permanent legislation are not currently applicable to Pepco.

Management is currently analyzing the impact of this legislation on the financial position, results of operations and cash flows of Pepco.

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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, 2009 and 2008 were approximately $42 million and $43 million, respectively. PHI Service Company costs directly charged or allocated to Pepco for the nine months ended September 30, 2009 and 2008 were approximately $124 million and $120 million, respectively.

Certain subsidiaries of Pepco Energy Services Inc. (Pepco Energy Services) perform utility maintenance services, including services that are treated as capital costs, for Pepco. Amounts charged to Pepco by these companies for the three months ended September 30, 2009 and 2008 were approximately $2 million and $3 million, respectively. Amounts charged to Pepco by these companies for the nine months ended September 30, 2009 and 2008 were approximately $5 million and $9 million, respectively.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
Income (Expense)	2009		2008		2009		2008
	(millions of dollars)
Purchased power from Conectiv Energy Supply, Inc. (a)	$	—	$	—	$	1	$	(23	)

(a) Included in purchased energy expense.

As of September 30, 2009 and December 31, 2008, Pepco had the following balances on its Balance Sheets due (to) from related parties:

	September 30, 2009			December 31, 2008
Liability	(millions of dollars)
Payable to Related Party (current)
PHI Service Company	$	(17	)	$	(17	)
Pepco Energy Services (a)	$	(54	)	$	(53	)
The items listed above are included in the “Accounts payable due to associated companies” balances on the Balance Sheets of $71 million and $70 million at September 30, 2009 and December 31, 2008, respectively.
Money Pool Balance with Pepco Holdings (included in cash and cash equivalents)	$	141		$	—

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

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DELMARVA POWER & LIGHT COMPANY

STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
	(millions of dollars)
Operating Revenue
Electric	$	311		$	348		$	883		$	932
Natural Gas		28			53			199			252
Total Operating Revenue		339			401			1,082			1,184
Operating Expenses
Purchased Energy		211			243			591			630
Gas purchased		19			43			147			200
Other operation and maintenance		64			63			182			173
Depreciation and amortization		19			18			56			54
Other taxes		8			9			27			27
Gain on sale of assets		—			—			—			(3	)
Total Operating Expenses		321			376			1,003			1,081
Operating Income		18			25			79			103
Other Income (Expenses)
Interest and dividend income		—			—			—			2
Interest expense		(11	)		(9	)		(33	)		(28	)
Other income		—			1			1			3
Total Other Expenses		(11	)		(8	)		(32	)		(23	)
Income Before Income Tax Expense		7			17			47			80
Income Tax (Benefit) Expense		(7	)		6			7			27
Net Income		14			11			40			53
Retained Earnings at Beginning of Period		446			432			448			432
Dividends Paid to Parent		—			—			(28	)		(42	)
Retained Earnings at End of Period	$	460		$	443		$	460		$	443

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

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DELMARVA POWER & LIGHT COMPANY

BALANCE SHEETS

(Unaudited)

	September 30, 2009			December 31, 2008
	(millions of dollars)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	6		$	138
Accounts receivable, less allowance for uncollectible accounts of $15 million and $10 million, respectively		172			202
Inventories		46			52
Prepayments of income taxes		91			34
Prepaid expenses and other		20			18
Total Current Assets		335			444
INVESTMENTS AND OTHER ASSETS
Goodwill		8			8
Regulatory assets		200			244
Prepaid pension expense		184			184
Other		29			21
Total Investments and Other Assets		421			457
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		2,760			2,656
Accumulated depreciation		(857	)		(827	)
Net Property, Plant and Equipment		1,903			1,829
TOTAL ASSETS	$	2,659		$	2,730

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

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DELMARVA POWER & LIGHT COMPANY

BALANCE SHEETS

(Unaudited)

	September 30, 2009		December 31, 2008
	(millions of dollars, except shares)
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Short-term debt	$	105	$	246
Current portion of long-term debt		31		—
Accounts payable and accrued liabilities		66		108
Accounts payable due to associated companies		23		34
Taxes accrued		7		7
Interest accrued		13		6
Liabilities and accrued interest related to uncertain tax positions		—		13
Derivative liabilities		13		13
Other		69		56
Total Current Liabilities		327		483
DEFERRED CREDITS
Regulatory liabilities		293		277
Deferred income taxes, net		492		446
Investment tax credits		8		8
Above-market purchased energy contracts and other electric restructuring liabilities		17		19
Derivative liabilities		14		14
Other		57		45
Total Deferred Credits		881		809
LONG-TERM LIABILITIES
Long-term debt		655		686
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		304
Retained earnings		460		448
Total Equity		796		752
TOTAL LIABILITIES AND EQUITY	$	2,659	$	2,730

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,
	2009			2008
	(millions of dollars)
OPERATING ACTIVITIES
Net income	$	40		$	53
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		56			54
Gain on sale of assets		—			(3	)
Deferred income taxes		50			41
Changes in:
Accounts receivable		31			(25	)
Inventories		6			(7	)
Regulatory assets and liabilities, net		38			32
Accounts payable and accrued liabilities		(38	)		(21	)
Pension contributions		(10	)		—
Taxes accrued		(57	)		(25	)
Other assets and liabilities		15			(1	)
Net Cash From Operating Activities		131			98
INVESTING ACTIVITIES
Investment in property, plant and equipment		(125	)		(109	)
Proceeds from sale of assets		1			50
Changes in restricted cash equivalents		—			(8	)
Net Cash Used By Investing Activities		(124	)		(67	)
FINANCING ACTIVITIES
Dividends paid to Parent		(28	)		(42	)
Capital contribution from Parent		32			62
Issuance of long-term debt		—			150
Reacquisitions of long-term debt		—			(116	)
Repayments of short-term debt, net		(141	)		(82	)
Net other financing activities		(2	)		(6	)
Net Cash Used By Financing Activities		(139	)		(34	)
Net Decrease in Cash and Cash Equivalents		(132	)		(3	)
Cash and Cash Equivalents at Beginning of Period		138			11
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	6		$	8
NONCASH ACTIVITIES
Asset retirement obligations associated with removal costs transferred to regulatory liabilities	$	5		$	(1	)
Conversion of long-term debt to short-term debt	$	—		$	150
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for income taxes (includes payments to PHI for Federal income taxes)	$	18		$	8

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

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NOTES TO FINANCIAL STATEMENTS

DELMARVA POWER & LIGHT COMPANY

(1) ORGANIZATION

Delmarva Power & Light Company (DPL) is engaged in the transmission and distribution of electricity in Delaware and portions of Maryland and provides gas distribution service in northern Delaware. Additionally, DPL supplies electricity at regulated rates to retail customers in its territories who do not elect to purchase electricity from a competitive supplier. The regulatory term for this service is 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).

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

(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). DPL adopted the Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC), which is the single source reference system for all authorative U.S. GAAP, as discussed in Note 3, “Newly Adopted Accounting Standards.” Pursuant to the rules and regulations of the Securities and Exchange Commission, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been omitted. Therefore, these financial statements should be read along with the annual financial statements included in DPL’s Annual Report on Form 10-K for the year ended December 31, 2008. In the opinion of DPL’s management, the financial statements contain all adjustments (which all are of a normal recurring nature) necessary to present fairly DPL’s financial condition as of September 30, 2009, in accordance with GAAP. The year-end balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP. Interim results for the three and nine months ended September 30, 2009 may not be indicative of results that will be realized for the full year ending December 31, 2009 since the sales of electric energy are seasonal. DPL has evaluated all subsequent events through October 29, 2009, the date of issuance of the financial statements to which these Notes relate.

Change in Accounting Principle

After the completion of the July 1, 2009 goodwill impairment test, DPL adopted a new accounting policy whereby DPL’s annual impairment review of goodwill will be performed as of November 1 each year. Management believes that the change in DPL’s annual impairment testing date is preferable because it better aligns the timing of the test with management’s annual update of its long-term financial forecast. The change in accounting principle has had no effect on DPL’s financial statements.

DPL Wind Transactions

PHI, through its DPL subsidiary, has entered into four wind power purchase agreements (PPAs) in amounts up to a total of 350 megawatts. Three of the PPAs are with land-based facilities and one of the PPAs is with an offshore facility. When completed and operational, DPL would purchase energy and renewable energy credits (RECs) from the four wind facilities and capacity from one of the wind facilities. The RECs help DPL fulfill a portion of its requirements under the State of Delaware’s Renewable Energy Portfolio Standards Act, which requires that 20 percent of total load needed in Delaware be produced from renewable sources by 2019. The Delaware Public Service Commission

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(DPSC) has approved the four agreements, each of which sets forth the prices to be paid by DPL over the life of the respective contracts. Payments under the agreements are currently expected to start in late 2009 for one of the land-based contracts, 2010 for the other two land-based contracts, and 2014 for the offshore contract, if the projects are ultimately completed and operational.

The lengths of the contracts range between 15 and 25 years. 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. Recent disruptions in the capital and credit markets, as well as permitting delays, could result in setbacks in the construction schedules and the operational start dates of the wind facility currently expected to start in late 2009, one of the wind facilities expected to start in 2010, and the wind facility currently expected to start in 2014. If the wind facilities are not operational by specified dates, DPL has the right to terminate the PPAs.

DPL concluded that consolidation is not required for any of these PPAs under FASB guidance on the consolidation of variable interest entities (ASC 810). DPL would need to reassess its accounting conclusions if there were material changes to the contractual arrangements or wind facilities.

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. After the completion of its July 1, 2009 annual impairment test, DPL changed the date of its annual impairment test to 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,” no impairment charge has been recorded for the three and nine months ended September 30, 2009.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in DPL’s gross revenues were $4 million for each of the three months ended September 30, 2009 and 2008, and $13 million for each of the nine months ended September 30, 2009 and 2008.

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

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.

In the third quarter of 2008, DPL recorded an adjustment to correct errors in Other Operation and Maintenance expenses for prior periods dating back to May 2006 for which late payment fees were incorrectly recognized. This adjustment resulted in an increase in Other Operation and Maintenance expenses for the three and nine months ended September 30, 2008 of $4 million and $3 million, respectively.

In the third quarter of 2008, PHI identified an error in the accounting for certain of its restricted stock awards under the Long-Term Incentive Plan which resulted in an understatement of DPL’s stock-based compensation expense in 2006 and 2007. This error was corrected in the third quarter of 2008, resulting in an increase in DPL’s Other Operation and Maintenance expenses for the three and nine months ended September 30, 2008 of $2 million.

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(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Business Combinations (ASC 805)

The accounting guidance on business combinations was amended by the FASB effective beginning January 1, 2009. The amendment did not change the fundamental concepts that the acquisition method of accounting be used and that an acquirer must be identified for each business combination. However, the guidance expanded the definition of a business subject to this guidance and also requires the acquirer to recognize changes in the amount of its deferred tax benefits that are realizable because of a business combination either in income from continuing operations or directly in contributed capital, depending on the circumstances.

On April 1, 2009, the FASB issued additional guidance to clarify the accounting for the initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. The additional guidance requires that assets acquired and liabilities assumed in a business combination that arise from contingencies be measured at fair value if the acquisition date fair value of that asset and liability can be determined during the measurement period. If the acquisition date fair value cannot be determined, then the asset or liability would be measured in accordance with FASB guidance on contingencies (ASC 450).

The new guidance applies prospectively to business combinations for which the acquisition date is on or after January 1, 2009. The adoption of the guidance did not have a material impact on DPL’s overall financial condition, results of operations, or cash flows.

Fair Value Measurement and Disclosures (ASC 820)

There is a variety of new accounting guidance from the FASB that is effective for different financial reporting periods during 2009. Nonrecurring fair value measurement guidance for non-financial assets and non-financial liabilities was effective beginning January 1, 2009 for DPL. The adoption of this guidance did not have a material impact on the fair value measurements of DPL’s non-financial assets and non-financial liabilities.

New FASB guidance for the fair value measurement of liabilities issued with inseparable third-party credit enhancements was also effective beginning January 1, 2009 for DPL. The guidance applies to liabilities such as debt, derivatives, and other instruments that are guaranteed by third parties. The effect of the credit enhancement may not be included in the fair value measurement of the liability, even if the liability has an inseparable third-party credit enhancement. The issuer is required to disclose the existence of the inseparable third-party credit enhancement on the issued liability. The adoption of the guidance did not have a material impact on DPL’s overall financial condition, results of operations, or cash flows.

DPL adopted new FASB guidance in the second quarter of 2009 for fair value measurement when markets are inactive and distressed. This guidance was effective for interim periods ending after June 15, 2009. The guidance outlines a two-step test to identify inactive and distressed markets and provides a fair value application example for financial instruments when both conditions are met. The guidance primarily applies to DPL’s valuation of its derivatives in the event they were being valued using information from inactive and distressed markets. These market conditions would require management to exercise judgment regarding how the market information is incorporated into the measurement of fair value. This guidance did not have a material impact on DPL’s overall financial condition, results of operations, or cash flows.

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Effective beginning with its June 30, 2009 financial statements, DPL began disclosing the fair value of debt issued on a quarterly basis in Note (13), “Fair Value Disclosures,” in accordance with FASB guidance which is effective for interim reporting periods ending after June 15, 2009. Disclosures for the prior year-end balance sheet were also required.

Consolidation (ASC 810)

The FASB established new accounting and reporting standards for a non-controlling interest (also called a “minority interest”) in a subsidiary and for the deconsolidation of a subsidiary. The new guidance clarified that a non-controlling interest in a subsidiary is an ownership interest in the consolidated entity that should be separately reported in the consolidated financial statements.

The guidance was effective prospectively for financial statement reporting periods beginning January 1, 2009 for DPL, except for the financial statement presentation and disclosure requirements which also apply to prior reporting periods presented. As of January 1, 2009, DPL adopted the provisions of this guidance and the guidance did not have a material impact on DPL’s overall financial condition, results of operations, or cash flows.

Derivatives and Hedging Disclosures (ASC 815)

The FASB issued new disclosure requirements for derivatives and hedging effective for financial statement reporting periods beginning January 1, 2009 for DPL. Some of the new disclosures include derivative objectives and strategies, derivative volumes by product type, classification and gross fair values of derivative assets and liabilities, classification and amounts of gains and losses on derivatives and related hedged items, and credit-risk-related contingent features in derivatives. DPL adopted the new requirements beginning with its March 31, 2009 financial statements with comparative disclosures for prior reporting periods. The disclosures are included within Note (10), “Derivative Instruments and Hedging Activities.”

Subsequent Events (ASC 855)

Beginning with its June 30, 2009 financial statements, DPL adopted new FASB guidelines for the disclosure of events that occur after the balance sheet reporting date but before the financial statements are issued. The new guidance requires the disclosure of the date through which DPL has assessed the impact of subsequent events on the financial statements. The new guidance was effective for interim or annual financial periods ending after June 15, 2009. DPL has disclosed this subsequent events date in Note (2), “Significant Accounting Policies.”

FASB Accounting Standards Codification (ASC 105)

The ASC identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of non-governmental financial statements presented under GAAP. In addition, it replaces the current reference system for standards and guidance with a new numerical designation system known as the ASC. The ASC will be the single source reference system for all authoritative GAAP. The ASC is numerically organized by topic, subtopic, section, and subsection.

The ASC is effective for financial statements issued for interim and annual periods ending after September 15, 2009. DPL has adopted the ASC guidance and referencing system for GAAP in its September 30, 2009 financial statements. Entities are not required to revise previous financial statements for the change in references to GAAP. The adoption of ASC did not result in a change in accounting principle for DPL, therefore, it did not have a material impact on DPL’s overall financial condition, results of operations, or cash flows.

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(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Transfers and Servicing (ASC 860)

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

The new guidance is effective for transfers of financial assets occurring in fiscal periods beginning after November 15, 2009, therefore, this guidance will be effective on January 1, 2010 for DPL. Comparative disclosures are encouraged but not required for earlier periods presented. DPL is evaluating the impact that this new guidance will have on its overall financial condition and financial statements.

Consolidation of Variable Interest Entities (ASC 810)

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

The new guidance is effective for fiscal periods beginning after November 15, 2009 for existing and newly created entities; therefore, this guidance will be effective on January 1, 2010 for DPL. Comparative disclosures under this new guidance are encouraged but not required for earlier periods presented. DPL is evaluating the impact that this new guidance will have on its overall financial condition and financial statements.

Fair Value Measurement of Liabilities (ASC 820)

The FASB issued new guidance on the fair value measurement of liabilities when there is a lack of observable market information. The guidance clarifies that, when a quoted price is not available for the identical liability, an entity can use either the quoted price of the identical liability when it is traded as an asset, quoted price for a similar liability, or quoted price for a similar liability when traded as an asset. If these prices are not available, then entities can employ an income or market valuation approach that considers what the entity would pay to transfer the identical liability or would receive to enter into the identical liability. The guidance is effective for DPL starting October 1, 2009. We are assessing the impact of this new guidance on DPL’s overall financial condition and financial statements.

(5) SEGMENT INFORMATION

Based on the provisions of FASB guidance on segment reporting (ASC 280), DPL has one segment, its regulated utility business.

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(6) GOODWILL

DPL’s goodwill balance of $8 million was unchanged during the three and nine month period ended September 30, 2009. All of DPL’s goodwill was generated by its acquisition of Conowingo Power Company in 1995.

DPL’s annual impairment test as of July 1, 2009 indicated that goodwill was not impaired at June 30, 2009. As of September 30, 2009, after review of its significant assumptions in the goodwill impairment analysis, DPL concluded that there were no events requiring DPL to perform an interim goodwill impairment test. DPL performed an interim impairment test as of December 31, 2008 which indicated that goodwill was not impaired. DPL’s next annual impairment test will be as of November 1, 2009.

In order to estimate the fair value of DPL’s business, DPL reviews the results from two discounted cash flow models. The models differ in the method used to calculate the terminal value. One model estimates terminal value based on a constant annual cash flow growth rate that is consistent with DPL’s long-term view of the business, and the other model estimates terminal value based on a multiple of earnings before interest, taxes, depreciation, and amortization (EBITDA) that management believes is consistent with EBITDA multiples for comparable utilities. The models use a cost of capital appropriate for a regulated utility as the discount rate for the estimated cash flows. DPL has consistently used this valuation approach to estimate the fair value of DPL’s business.

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

With the continuing volatile general market conditions and the disruptions in the credit and capital markets, 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, 2009 before intercompany allocations from the PHI Service Company, of $36 million included $6 million for DPL’s allocated share. PHI’s pension and other post retirement net periodic benefit cost for the nine months ended September 30, 2009 of $111 million included $19 million for DPL’s allocated share. PHI’s pension and other postretirement net periodic benefit cost for the three months ended September 30, 2008 before intercompany allocations, of $16 million included $1 million for DPL’s allocated share. PHI’s pension and other post retirement net periodic benefit cost for the nine months ended September 30, 2008 of $48 million included $3 million for DPL’s allocated share.

(8) DEBT

Credit Facilities

PHI, Potomac Electric Power Company (Pepco), DPL and Atlantic City Electric Company (ACE) maintain an unsecured credit facility to provide for their respective short-term liquidity needs. The aggregate borrowing limit under the facility is $1.5 billion, all or any portion of which may be used to obtain loans or to issue letters of credit. PHI’s credit limit under the facility is $875 million. The credit

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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, 2009 and December 31, 2008, 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 $581 million and $843 million, respectively.

Other Financing Activities

During the three months ended September 30, 2009, the following financing activities occurred:

In July 2009, DPL repaid, at maturity, the remaining $100 million of a short-term loan in the original amount of $150 million.

In July 2009, DPL redeemed $15 million of Series 2003A and $18.2 million of Series 2003B Exempt Facilities Refunding Revenue Bonds issued for the benefit of DPL by The Delaware Economic Development Authority. These tax-exempt bonds were purchased by DPL in 2008 due to the disruptions in the tax-exempt capital markets.

In September 2009, DPL issued $165.5 million of collateral first mortgage bonds in order to secure its reimbursement obligations under bond insurance policies insuring the principal and interest payments on a series of previously issued DPL notes and two series of pollution control bonds previously issued for the benefit of DPL. DPL did not receive any cash proceeds from the issuance of the collateral first mortgage bonds. The payment by DPL of its principal and interest obligations in respect of the DPL notes and the pollution control bonds satisfies the corresponding payment obligations on collateral first mortgage bonds, and accordingly DPL’s outstanding debt did not increase as a result of these transactions.

(9) INCOME TAXES

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

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2009		2008		2009		2008
Federal statutory rate	35.0	%	35.0	%	35.0	%	35.0	%
Increases (decreases) resulting from:
Depreciation	11.4		(1.2	)	3.4		1.0
State income taxes, net of federal effect	5.7		5.4		5.5		5.4
State tax benefit related to prior years’ asset dispositions	(187.1	)	—		(27.9	)	—
Tax credits	(2.9	)	(1.2	)	(1.3	)	(.8	)
Change in estimates and interest related to uncertain and effectively settled tax positions	21.4		—		(1.9	)	(7.0	)
Adjustments to prior years’ taxes	22.9		(5.3	)	3.4		(1.1	)
Other, net	(6.4	)	—		(1.3	)	.1
Effective Income Tax Rate	(100.0	)%	32.7	%	14.9	%	32.6	%

DPL’s effective tax rates for the three months ended September 30, 2009 and 2008 were (100.0) % and 32.7%, respectively. The decrease in the rate primarily resulted from the refund of $6 million (after tax) of state income taxes and the establishment of a state tax benefit carryforward of $7 million (after tax), each related to a change in the tax reporting for the disposition of certain assets in prior years. This decrease is partially offset by the changes in estimates and interest related to uncertain and effectively settled tax positions and the non-recurring adjustments to prior years’ taxes.

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DPL’s effective tax rates for the nine months ended September 30, 2009 and 2008 were 14.9 % and 32.6% respectively. The decrease in the rate primarily resulted from the refund of $6 million (after tax) of state income taxes and the establishment of a state tax benefit carryforward of $7 million (after tax), each related to a change in the tax reporting for the disposition of certain assets in prior years. This decrease is partially offset by the changes in estimates and interest related to uncertain and effectively settled tax positions and the non-recurring adjustments to prior years’ taxes.

In March 2009, the 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.

In October 2009, PHI filed a claim with the IRS requesting a Federal income tax refund of approximately $138 million, a substantial portion of which is associated with PHI’s utility subsidiaries. The refund results from the carry back of a 2008 net operating loss for tax reporting purposes that reflected, among other things, significant tax deductions related to accelerated depreciation, the pension plan contributions paid in 2009 (which were deductible for 2008) and the cumulative effect of adopting a new method of tax reporting for certain repairs. The timing of receipt of the refund is uncertain, however, after a 45-day period, interest would begin to accrue on the amount of the refund.

During the third quarter of 2009, as a result of the acceptance of previously filed amended state returns, DPL’s uncertain tax benefits related to prior year tax positions decreased by $18 million. Further, as a result of a change in tax accounting methods related to certain repairs, DPL’s uncertain tax benefits related to current year tax positions increased by $9 million, none of which, if recognized, would affect the effective tax rate.

(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, 2009 and December 31, 2008:

	As of September 30, 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)	$	—		$	2		$	2		$	(2	)	$	—
Derivative Assets (non-current assets)		—			—			—			—			—
Total Derivative Assets		—			2			2			(2	)		—
Derivative Liabilities (current liabilities)		(13	)		(16	)		(29	)		16			(13	)
Derivative Liabilities (non-current liabilities)		—			(14	)		(14	)		—			(14	)
Total Derivative Liabilities		(13	)		(30	)		(43	)		16			(27	)
Net Derivative (Liability) Asset	$	(13	)	$	(28	)	$	(41	)	$	14		$	(27	)
	As of December 31, 2008
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)	$	—		$	3		$	3		$	(3	)	$	—
Derivative Assets (non-current assets)		—			—			—			—			—
Total Derivative Assets		—			3			3			(3	)		—
Derivative Liabilities (current liabilities)		(31	)		(13	)		(44	)		31			(13	)
Derivative Liabilities (non-current liabilities)		—			(14	)		(14	)		—			(14	)
Total Derivative Liabilities		(31	)		(27	)		(58	)		31			(27	)
Net Derivative (Liability) Asset	$	(31	)	$	(24	)	$	(55	)	$	28		$	(27	)

Under FASB guidance on the offsetting of balance sheet accounts (ASC 210-20), 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, 2009		December 31, 2008
	(millions of dollars)
Cash collateral pledged to counterparties with the right to reclaim	$	14	$	28

As of September 30, 2009 and December 31, 2008, DPL had no cash collateral pledged or received related to derivatives accounted for at fair value that was not entitled to offset under master netting arrangements.

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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, 2009 and 2008:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
	(millions of dollars)
Net Gain (Loss) Deferred as a Regulatory Asset/Liability	$	8		$	(26	)	$	19		$	(16	)
Net (Loss) Gain Reclassified from Regulatory Asset/Liability to Purchased Energy		(7	)		1			(33	)		2

As of September 30, 2009 and December 31, 2008, DPL had the following outstanding commodity forward contracts that were entered into to hedge forecasted transactions:

	Quantities
Commodity	September 30, 2009	December 31, 2008
Forecasted Purchases Hedges:
Natural Gas (One Million British Thermal Units (MMBtu))	6,845,000	10,805,000

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, 2009 and 2008, the amount of the derivative gain (loss) recognized by line item in the statements of income is provided in the table below:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
	(millions of dollars)
Net Gain (Loss) Deferred as a Regulatory Asset/Liability	$	2		$	(15	)	$	(8	)	$	1
Net (Loss) Reclassified from Regulatory Asset/Liability to Purchased Energy		(1	)		—			(6	)		—

As of September 30, 2009 and December 31, 2008, DPL had the following net outstanding natural gas commodity forward contracts that did not qualify for hedge accounting:

	September 30, 2009		December 31, 2008
Commodity	Quantity	Net Position	Quantity	Net Position
Natural Gas (MMBtu)	10,297,006	Long	8,928,750	Long

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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 do not contain this contingent credit risk feature related to credit rating as they are fully collateralized.

The gross fair value of DPL’s derivative liabilities, excluding the impact of offsetting transactions or collateral under master netting agreements, with credit-risk-related contingent features on September 30, 2009, was $29 million. As of that date, DPL had posted cash collateral of $1 million in the normal course of business against the gross derivative liability resulting in a net liability of $28 million before giving effect to offsetting transactions that are encompassed within master netting agreements that would reduce this amount. PHI’s net settlement amount in the event of a downgrade of DPL below “investment grade” as of September 30, 2009, would have been approximately $19 million after taking into account the master netting agreements.

DPL’s primary source for posting cash collateral or letters of credit is PHI’s primary credit facility. At September 30, 2009, the aggregate amount of cash plus borrowing capacity under the primary credit facility available to meet the liquidity needs of utility subsidiaries totaled $581 million.

(11) FAIR VALUE DISCLOSURES

Fair Value of Assets and Liabilities Excluding Debt

Effective January 1, 2008, DPL 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

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unobservable inputs. DPL is able to classify fair value balances based on the observability of those 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). The three levels of the fair value hierarchy are as follows:

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

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

Level 3 – Pricing inputs include significant inputs that are generally less observable than those from objective sources. Level 3 includes those financial investments that are valued using models or other valuation methodologies. DPL’s Level 3 instruments are natural gas options. Some non-standard assumptions are used in their forward valuation to adjust for the pricing; otherwise, most of the options follow NYMEX valuation. A few of the options have no significant NYMEX components, and have to be priced using internal volatility assumptions. Some of the options do not expire until December 2011. All of the options are part of the natural gas hedging program approved by the Delaware Public Service Commission.

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

The following tables set forth by level within the fair value hierarchy DPL’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2009 and December 31, 2008. 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, 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	$	4	$	3	$	—	$	1
	$	4	$	3	$	—	$	1
LIABILITIES
Derivative instruments	$	41	$	13	$	—	$	28
	$	41	$	13	$	—	$	28

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	Fair Value Measurements at December 31, 2008
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	$	129	$	129	$	—	$	—
Executive deferred compensation plan assets		4		3		—		1
	$	133	$	132	$	—	$	1
LIABILITIES
Derivative instruments	$	56	$	29	$	3	$	24
Executive deferred compensation plan liabilities		1		—		1		—
	$	57	$	29	$	4	$	24

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, 2009 and 2008 are shown below:

	Nine Months Ended September 30, 2009
	Net Derivative Instruments Asset (Liability)			Deferred Compensation Plan Assets
	(millions of dollars)
Beginning balance as of January 1, 2009	$	(24	)	$	1
Total gains or (losses) (realized and unrealized)
Included in income		—			—
Included in accumulated other comprehensive (loss) income		—			—
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
				Other Operation and Maintenance Expense
				(millions of dollars)
Gains or (losses) (realized and unrealized) included in income for the period above are reported in Other Operation and Maintenance Expense as follows:
Total losses included in income for the period above				$	—
Change in unrealized gains relating to assets still held at reporting date				$	—

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	Nine Months Ended September 30, 2008
	Net Derivative Instruments Asset (Liability)			Deferred Compensation Plan Assets
	(millions of dollars)
Beginning balance as of January 1, 2008	$	(10	)	$	1
Total gains or (losses) (realized and unrealized)
Included in income		—			—
Included in accumulated other comprehensive (loss) income		—			—
Included in regulatory liabilities		1			—
Purchases and issuances		(1	)		—
Settlements		—			—
Transfers in (out) of Level 3		—			—
Ending balance as of September 30, 2008	$	(10	)	$	1
				Other Operation and Maintenance Expense
				(millions of dollars)
Gains or (losses) (realized and unrealized) included in income for the period above are reported in Other Operation and Maintenance Expense as follows:
Total gains (losses) included in income for the period above				$	—
Change in unrealized gains (losses) relating to assets still held at reporting date				$	—

Fair Value of Debt Instruments

The estimated fair values of DPL’s non-derivative financial instruments as of September 30, 2009 and December 31, 2008 are shown below:

	September 30, 2009				December 31, 2008
	(millions of dollars)
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	686	$	731	$	686	$	682

The fair values of the Long-term debt, which includes First Mortgage Bonds, Amortizing First Mortgage Bonds, Unsecured Tax-Exempt Bonds, Medium-Term Notes, and Unsecured Notes, including amounts due within one year, were derived based on current market prices, or were based on discounted cash flows using current rates for similar issues with similar terms and remaining maturities for issues with no market price available.

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(12) COMMITMENTS AND CONTINGENCIES

Regulatory and Other Matters

Rate Proceedings

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

• A 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 and natural gas service in Delaware and may be implemented either in the context of pending decoupling cases or DPL’s next Delaware base rate cases.

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

Delaware

In August 2008, DPL submitted its 2008 Gas Cost Rate (GCR) filing to the DPSC, requesting an increase in the level of GCR, which permits DPL to recover gas procurement costs through customer rates. In September 2008, the DPSC issued an initial order approving the requested increase, which became effective on November 1, 2008, subject to refund pending final DPSC approval after evidentiary hearings. Due to a significant decrease in wholesale gas prices, in January 2009, DPL submitted to the DPSC an interim GCR filing, requesting a decrease in the level of GCR. The proposed decrease, when combined with the increase that became effective November 1, 2008, would have the net effect of a 13.8% increase in the level of GCR. On February 5, 2009, the DPSC issued an initial order approving the net increase, effective on March 1, 2009, subject to refund pending final DPSC approval after evidentiary hearings. A hearing was held on May 27, 2009, during which a settlement agreement among DPL, DPSC staff and the Delaware Public Advocate was submitted to the Hearing Examiner. The settlement agreement provided that the proposed net increase would become final and no longer subject to refund. The DPSC approved the settlement agreement and closed this docket on October 6, 2009.

On August 31, 2009, DPL submitted its 2009 GCR filing to the DPSC, requesting a 10.2% decrease in the level of GCR, to become effective on a temporary basis on November 1, 2009. This rate proposal was approved by the DPSC on September 9, 2009, subject to refund and pending final DPSC approval.

On June 25, 2009, DPL filed two applications requesting approval for the implementation of the MFVRD for electric distribution rates and gas distribution rates, respectively. These filings are based on revenues established in DPL’s last electric and gas distribution base rate cases, and accordingly are revenue neutral. On August 4, 2009, the DPSC issued an order opening a docket for the MFVRD for gas distribution rates and on September 9, 2009, the DPSC issued an order opening a docket for the MFVRD for electric distribution rates. The electric MFVRD may be implemented in the pending base rate case rather than in connection with the June 25, 2009 filing.

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On September 18, 2009, DPL submitted an application with the DPSC to increase its electric distribution base rates. The filing seeks approval of an annual rate increase of approximately $29 million based on a requested return on equity (ROE) of 11.00%. (or, with the MFVRD, the requested rate increase would be reduced to approximately $28 million, based on an ROE of 10.75%). The procedural schedule has not yet been established. DPL intends to put an increase of $2.5 million annually into effect on a temporary basis on November 17, 2009, subject to refund and pending final DPSC approval, which is expected in April 2010.

Maryland

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

DPL filed an appeal from the MPSC’s July 2007, July 2008 and August 2008 orders. The appeal was consolidated in the Circuit Court for Baltimore City with an appeal filed by Pepco. In a brief filed on March 9, 2009, DPL contends that the MPSC erred in failing to implement permanent rates in accordance with Maryland law, and in its denial of DPL’s rights to recover an increased share of the PHI Service Company costs and the costs of performing a MPSC-mandated management audit. On August 31, 2009, the Circuit Court issued a decision in which it affirmed the MPSC concerning the recovery of PHI Service Company costs and its use of temporary rates at the conclusion of the statutory suspension period. The court reversed the MPSC’s order requiring the costs of MPSC-mandated management audits to be paid by DPL’s shareholders. No appeals were filed within the 30-day appeal period and, therefore, the Circuit Court’s decision has become final.

On May 6, 2009, DPL filed a distribution base rate case in Maryland. The filing seeks approval of an annual rate increase of approximately $14 million, based on a requested ROE of 11.25%. The filing also proposes recovery of pension, OPEB and uncollectible expenses through a surcharge mechanism using a three-year average, with the difference between actual expense and the surcharge amount captured in a deferral balance. If the proposed surcharge mechanism is approved, the requested annual rate increase would be reduced by approximately $4 million. Hearings were held September 22 through September 25, 2009. A decision is expected in December 2009.

Environmental Litigation

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

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Ward Transformer Site. In April 2009, a group of potentially responsible parties at 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 that the group has cost recovery and/or contribution claims against DPL with respect to past and future response costs incurred 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. Although it is too early in the process to characterize the magnitude of the potential liability at this site, based on interviews with long-time DPL employees and record reviews, it does not appear that DPL had extensive business transactions, if any, with the Ward Transformer site.

IRS Mixed Service Cost Issue

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

In 2005, the IRS issued Revenue Ruling 2005-53, which limited the ability of DPL to utilize its tax accounting method on its 2001 through 2004 tax returns. In accordance with this Revenue Ruling, the RAR for the 2001 and 2002 tax returns disallowed substantially all of the incremental tax benefits that DPL had claimed on those returns.

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

(13) RELATED PARTY TRANSACTIONS

PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries including DPL. The cost of these services is allocated in accordance with cost allocation methodologies set forth in the service agreement using a variety of factors, including the subsidiaries’ share of employees, operating expenses, assets, and other cost causal methods. These intercompany transactions are eliminated by PHI in consolidation and no profit results from these transactions at PHI. PHI Service Company costs directly charged or allocated to DPL for the three months ended September 30, 2009 and 2008 were $32 million and $31 million, respectively. PHI Service Company costs directly charged or allocated to DPL for the nine months ended September 30, 2009 and 2008 were approximately $95 million and $92 million, respectively.

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

Income (Expenses)	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
	(millions of dollars)
Purchased power from Conectiv Energy Supply, Inc. (a)	$	(14	)	$	(43	)	$	(73	)	$	(147	)
Intercompany lease transactions (b)		2			2			6			5
Transcompany pipeline gas purchases with Conectiv Energy Supply, Inc. (c)		—			(1	)		—			(2	)

(a) Included in purchased energy expense.

(b) Included in electric revenue.

(c) Included in gas purchased expense.

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As of September 30, 2009 and December 31, 2008, DPL had the following balances on its balance sheets due (to) from related parties:

Liability	September 30, 2009			December 31, 2008
	(millions of dollars)
Payable to Related Party (current)
PHI Service Company	$	(17	)	$	(15	)
Conectiv Energy Supply, Inc.		(3	)		(14	)
Pepco Energy Services, Inc. and its subsidiaries (Pepco Energy Services) (a)		(3	)		(6	)

The items listed above are included in the “Accounts payable due to associated companies” balances on the Balance Sheets of $23 million and $34 million at September 30, 2009 and December 31, 2008, respectively.

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

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ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
	(millions of dollars)
Operating Revenue	$	441		$	540		$	1,072		$	1,288
Operating Expenses
Purchased energy		334			395			850			913
Other operation and maintenance		50			50			145			139
Depreciation and amortization		29			31			78			80
Other taxes		6			6			16			18
Deferred electric service costs		(32	)		12			(116	)		20
Total Operating Expenses		387			494			973			1,170
Operating Income		54			46			99			118
Other Income (Expenses)
Interest and dividend income		—			—			—			1
Interest expense		(16	)		(14	)		(50	)		(44	)
Other income		—			1			1			3
Total Other Expenses		(16	)		(13	)		(49	)		(40	)
Income Before Income Tax Expense		38			33			50			78
Income Tax Expense		15			13			17			26
Net Income		23			20			33			52
Retained Earnings at Beginning of Period		152			143			166			142
Dividends Paid to Parent		—			—			(24	)		(31	)
Retained Earnings at End of Period	$	175		$	163		$	175		$	163

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

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ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30, 2009			December 31, 2008
	(millions of dollars)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	5		$	65
Restricted cash equivalents		11			10
Accounts receivable, less allowance for uncollectible accounts of $8 million and $6 million, respectively		200			195
Inventories		16			15
Prepayments of income taxes		52			47
Prepaid expenses and other		40			16
Total Current Assets		324			348
INVESTMENTS AND OTHER ASSETS
Regulatory assets		721			768
Restricted funds held by trustee		4			5
Assets and accrued interest related to uncertain tax positions		54			110
Income taxes receivable		71			10
Prepaid pension expense		59			6
Other		10			12
Total Investments and Other Assets		919			911
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		2,294			2,216
Accumulated depreciation		(693	)		(666	)
Net Property, Plant and Equipment		1,601			1,550
TOTAL ASSETS	$	2,844		$	2,809

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

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ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30, 2009		December 31, 2008
	(millions of dollars, except shares)
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Short-term debt	$	63	$	23
Current maturities of long-term debt		34		32
Accounts payable and accrued liabilities		111		122
Accounts payable due to associated companies		28		28
Taxes accrued		2		7
Interest accrued		17		14
Liabilities and accrued interest related to uncertain tax positions		—		6
Other		39		35
Total Current Liabilities		294		267
DEFERRED CREDITS
Regulatory liabilities		224		377
Deferred income taxes, net		593		549
Investment tax credits		9		10
Other postretirement benefit obligation		45		41
Other		11		12
Total Deferred Credits		882		989
LONG-TERM LIABILITIES
Long-term debt		609		610
Transition Bonds issued by ACE Funding		378		401
Total Long-Term Liabilities		987		1,011
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		474		344
Retained earnings		175		166
Total Equity		675		536
TOTAL LIABILITIES AND EQUITY	$	2,844	$	2,809

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

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ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
	2009			2008
	(millions of dollars)
OPERATING ACTIVITIES
Net income	$	33		$	52
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		78			80
Deferred income taxes		46			19
Changes in:
Accounts receivable		(5	)		(23	)
Prepaid New Jersey sales and excise tax		(44	)		(48	)
Regulatory assets and liabilities, net		(139	)		(2	)
Accounts payable and accrued liabilities		(9	)		25
Pension contributions		(60	)		—
Taxes accrued		3			20
Interest accrued		3			(3	)
Other assets and liabilities		12			5
Net Cash (Used By) From Operating Activities		(82	)		125
INVESTING ACTIVITIES
Investment in property, plant and equipment		(98	)		(122	)
Proceeds from sale of assets		—			1
Net Cash Used By Investing Activities		(98	)		(121	)
FINANCING ACTIVITIES
Dividends paid to Parent		(24	)		(31	)
Capital contribution from Parent		129			35
Reacquisition of long-term debt		(23	)		(126	)
Issuances of short-term debt, net		40			167
Net other financing activities		(2	)		(9	)
Net Cash From Financing Activities		120			36
Net (Decrease) Increase in Cash and Cash Equivalents		(60	)		40
Cash and Cash Equivalents at Beginning of Period		65			7
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	5		$	47
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash (received) paid for income taxes (includes payments to PHI for Federal income taxes)	$	(16	)	$	11

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ATLANTIC CITY ELECTRIC COMPANY

(1) ORGANIZATION

Atlantic City Electric Company (ACE) is engaged in the transmission and distribution of electricity in southern New Jersey. ACE provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its service territory who do not elect to purchase electricity from a competitive supplier. Default Electricity Supply is also known as Basic Generation Service. 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). ACE adopted the Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC), which is the single source reference system for all authorative U.S. GAAP, as discussed in Note 3, “Newly Adopted Accounting Standards.” Pursuant to the rules and regulations of the Securities and Exchange Commission, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been omitted. Therefore, these financial statements should be read along with the annual financial statements included in ACE’s Annual Report on Form 10-K for the year ended December 31, 2008. In the opinion of ACE’s management, the consolidated financial statements contain all adjustments (which all are of a normal recurring nature) necessary to present fairly ACE’s financial condition as of September 30, 2009, in accordance with GAAP. The year-end balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP. Interim results for the three and nine months ended September 30, 2009 may not be indicative of results that will be realized for the full year ending December 31, 2009 since the sales of electric energy are seasonal. ACE has evaluated all subsequent events through October 29, 2009, the date of issuance of the consolidated financial statements to which these Notes relate.

Consolidation of Variable Interest Entities

ACE has power purchase agreements (PPAs) with a number of entities, including three contracts between unaffiliated non-utility generators (NUGs) and ACE. Due to a variable element in the pricing structure of the PPAs, ACE potentially assumes the variability in the operations of the plants operated by the NUGs and, therefore, has a variable interest in the entities. In accordance with the provisions of FASB guidance on the consolidation of variable interest entities (ASC 810), ACE continued, during the third quarter of 2009, to conduct its efforts to obtain information from these entities, but was unable to obtain sufficient information to conduct the analysis required under the 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 under the PPAs for the three months ended September 30, 2009 and 2008 were approximately $70 million and $93 million, respectively, of which approximately $66 million and $82 million, respectively, consisted of power purchases under the PPAs. Net power purchase activities with the counterparties under the PPAs for the nine months ended September 30, 2009 and 2008 were approximately $214 million and $265 million, respectively, of which approximately $197 million and $233 million, respectively, consisted of power purchases under the PPAs. ACE does not have direct exposure to loss under the PPAs because ACE is able to recover its costs from its customers through regulated rates.

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Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in ACE’s gross revenues were $6 million and $7 million for the three months ended September 30, 2009 and 2008, respectively, and $17 million for each of the nine months ended September 30, 2009 and 2008.

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 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.

In the third quarter of 2008, PHI identified an error in the accounting for certain of its restricted stock awards under the Long-Term Incentive Plan which resulted in an understatement of ACE’s stock-based compensation expense in 2006 and 2007. This error was corrected in the third quarter of 2008, resulting in an increase in ACE’s Other Operation and Maintenance expenses for the three and nine months ended September 30, 2008 of $1 million.

(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Business Combinations (ASC 805)

The accounting guidance on business combinations was amended by the FASB effective beginning January 1, 2009. The amendment did not change the fundamental concepts that the acquisition method of accounting be used and that an acquirer must be identified for each business combination. However, the guidance expanded the definition of a business subject to this guidance and also requires the acquirer to recognize changes in the amount of its deferred tax benefits that are realizable because of a business combination either in income from continuing operations or directly in contributed capital, depending on the circumstances.

On April 1, 2009, the FASB issued additional guidance to clarify the accounting for the initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. The additional guidance requires that assets acquired and liabilities assumed in a business combination that arise from contingencies be measured at fair value if the acquisition date fair value of that asset and liability can be determined during the measurement period. If the acquisition date fair value cannot be determined, then the asset or liability would be measured in accordance with FASB guidance on contingencies (ASC 450).

The new guidance applies prospectively to business combinations for which the acquisition date is on or after January 1, 2009. The adoption of the guidance did not have a material impact on ACE’s overall financial condition, results of operations, or cash flows.

Fair Value Measurement and Disclosures (ASC 820)

There is a variety of new accounting guidance from the FASB that is effective for different financial reporting periods during 2009. Nonrecurring fair value measurement guidance for non-financial assets and non-financial liabilities was effective beginning January 1, 2009 for ACE. The adoption of this guidance did not have a material impact on the fair value measurements of ACE’s non-financial assets and non-financial liabilities.

Effective beginning with its June 30, 2009 financial statements, ACE began disclosing the fair value of debt issued on a quarterly basis in Note (13), “Fair Value Disclosures,” in accordance with FASB guidance which is effective for interim reporting periods ending after June 15, 2009. Disclosures for the prior year-end balance sheet were also required.

Consolidation (ASC 810)

The FASB established new accounting and reporting standards for a non-controlling interest (also called a “minority interest”) in a subsidiary and for the deconsolidation of a subsidiary. The new guidance clarified that a non-controlling interest in a subsidiary is an ownership interest in the consolidated entity that should be separately reported in the consolidated financial statements.

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The guidance was effective prospectively for financial statement reporting periods beginning January 1, 2009 for ACE, except for the financial statement presentation and disclosure requirements which also apply to prior reporting periods presented. As of January 1, 2009, ACE adopted the provisions of this guidance and the provisions did not have a material impact on ACE’s overall financial condition, results of operations, or cash flows.

Subsequent Events (ASC 855)

Beginning with its June 30 2009 financial statements, ACE adopted new FASB guidelines for the disclosure of events that occur after the balance sheet reporting date but before the financial statements are issued. The new guidance requires the disclosure of the date through which ACE has assessed the impact of subsequent events on the financial statements. The new guidance was effective for interim or annual financial periods ending after June 15, 2009. ACE has disclosed this subsequent events date in Note (2), “Significant Accounting Policies.”

FASB Accounting Standards Codification (ASC 105)

The ASC identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of non-governmental financial statements presented under GAAP. In addition, it replaces the current reference system for standards and guidance with a new numerical designation system known as the ASC. The ASC will be the single source reference system for all authoritative GAAP. The ASC is numerically organized by topic, subtopic, section, and subsection.

The ASC is effective for financial statements issued for interim and annual periods ending after September 15, 2009. ACE has adopted the ASC guidance and referencing system for GAAP in its September 30, 2009 financial statements. Entities are not required to revise previous financial statements for the change in references to GAAP. The adoption of ASC did not result in a change in accounting principle for ACE, therefore, it did not have a material impact on ACE’s overall financial condition, results of operations, or cash flows.

(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Transfers and Servicing (ASC 860)

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

The new guidance is effective for transfers of financial assets occurring in fiscal periods beginning after November 15, 2009, therefore, this guidance will be effective on January 1, 2010 for ACE. Comparative disclosures are encouraged but not required for earlier periods presented. ACE is evaluating the impact that this new guidance will have on its overall financial condition and financial statements.

Consolidation of Variable Interest Entities (ASC 810)

The FASB issued new consolidation guidance regarding variable interest entities that eliminates the existing quantitative analysis requirement and adds new qualitative factors to determine whether consolidation is required. The new qualitative factors would be 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

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losses significant to the entity would consolidate. The new guidance retained the existing provision that allowed entities created before December 31, 2003 to be scoped out from a consolidation assessment if exhaustive efforts are taken and there is insufficient information to determine the primary beneficiary.

The new guidance is effective for fiscal periods beginning after November 15, 2009 for existing and newly created entities; therefore, this guidance will be effective on January 1, 2010 for ACE. Comparative disclosures under this new guidance are encouraged but not required for earlier periods presented. ACE is evaluating the impact that this new guidance will have on its overall financial condition and financial statements.

Fair Value Measurement of Liabilities (ASC 820)

The FASB issued new guidance on the fair value measurement of liabilities when there is a lack of observable market information. The guidance clarifies that, when a quoted price is not available for the identical liability, an entity can use either the quoted price of the identical liability when it is traded as an asset, quoted price for a similar liability, or quoted price for a similar liability when traded as an asset. If these prices are not available, then entities can employ an income or market valuation approach that considers what the entity would pay to transfer the identical liability or would receive to enter into the identical liability. The guidance is effective for PHI starting October 1, 2009. We are assessing the impact of this new guidance on ACE’s overall financial condition and financial statements.

(5) SEGMENT INFORMATION

Based on the provisions of FASB guidance on segment reporting (ASC 280), ACE has one segment, its regulated utility business.

(6) PENSION AND OTHER POSTRETIREMENT BENEFITS

ACE accounts for its participation in the Pepco Holdings benefit plans as participation in a multi-employer plan. PHI’s pension and other postretirement net periodic benefit cost for the three months ended September 30, 2009 before intercompany allocations from the PHI Service Company, of $36 million included $5 million for ACE’s allocated share. PHI’s pension and other postretirement net periodic benefit cost for the nine months ended September 30, 2009 of $111 million included $15 million for ACE’s allocated share. PHI’s pension and other postretirement net periodic benefit cost for the three months ended September 30, 2008 before intercompany allocations, of $16 million included $3 million for ACE’s allocated share. PHI’s pension and other postretirement net periodic benefit cost for the nine months ended September 30, 2008 of $48 million included $9 million for ACE’s allocated share.

(7) DEBT

Credit Facilities

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

At September 30, 2009 and December 31, 2008, 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 $581 million and $843 million, respectively.

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Other Financing Activities

During the three months ended September 30, 2009, the following financing activities occurred:

In July 2009, Atlantic City Electric Transition Funding LLC (ACE Funding) made principal payments of $5.2 million on Series 2002-1 Bonds, Class A-2, $1.4 million on Series 2003-1 Bonds, Class A-1, and $.7 million on Series 2003-1 Bonds, Class A-2.

In July 2009, ACE redeemed $25 million of Series 2004A and $6.5 million of Series 2004B Pollution Control Revenue Refunding Bonds issued for the benefit of ACE by the Pollution Control Financing Authority of Cape May County (collectively, the Cape May Bonds). The Cape May Bonds were purchased by ACE in 2008 due to the disruptions in the tax-exempt capital markets. The Cape May Bonds were insured by bond insurance policies purchased by ACE. At the time of the issuance of the Cape May Bonds, ACE issued to the bond insurer, as security for its reimbursement obligations under the bond insurance policies, a series of senior notes having terms substantially identical to the terms of the respective series of Cape May Bonds. ACE’s obligations under the senior notes were, in turn, secured by a corresponding series of collateral first mortgage bonds issued by ACE under its Mortgage and Deed of Trust. Upon the redemption of the Cape May Bonds, the corresponding series of senior notes and first mortgage bonds were likewise redeemed.

Subsequent to September 30, 2009, the following financing activity occurred:

In October 2009, ACE Funding made principal payments of $7 million on Series 2002-1 Bonds, Class A-2, and $2.7 million on Series 2003-1 Bonds, Class A-2.

(8) INCOME TAXES

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

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2009		2008		2009		2008
Federal statutory rate	35.0	%	35.0	%	35.0	%	35.0	%
Increases (decreases) resulting from:
Depreciation	—		—		—		—
State income taxes, net of federal effect	7.1		7.4		7.8		7.1
Tax credits	(.8	)	(.9	)	(1.6	)	(1.0	)
Change in estimates and interest related to uncertain and effectively settled tax positions	(1.3	)	.3		(4.4	)	(7.4	)
Adjustment to prior years’ taxes	—		(3.1	)	(2.0	)	(1.3	)
Other, net	(.5	)	(.4	)	(.8	)	(1.0	)
Consolidated Effective Income Tax Rate	39.5	%	38.3	%	34.0	%	31.4	%

ACE’s consolidated effective tax rates for the three months ended September 30, 2009 and 2008 were 39.5% and 38.3%, respectively. The increase in the rate primarily resulted from non-recurring adjustments to prior year taxes, partially offset by the impact of changes in estimates and interest related to uncertain and effectively settled positions and the effect of certain permanent state tax differences as a percentage of pre-tax income.

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ACE’s consolidated effective tax rates for the nine months ended September 30, 2009 and 2008 were 34.0% and 31.4% respectively. The increase in the rate resulted from changes in estimates and interest related to uncertain and effectively settled tax positions and the impact of certain permanent state tax differences as a percentage of pre-tax income, partially offset by the non-recurring adjustments to prior year taxes and amortization of tax credits.

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.

In October 2009, PHI filed a claim with the IRS requesting a Federal income tax refund of approximately $138 million, a substantial portion of which is associated with PHI’s utility subsidiaries. The refund results from the carry back of a 2008 net operating loss for tax reporting purposes that reflected, among other things, significant tax deductions related to accelerated depreciation, the pension plan contributions paid in 2009 (which were deductible for 2008) and the cumulative effect of adopting a new method of tax reporting for certain repairs. The timing of receipt of the refund is uncertain, however, after a 45-day period, interest would begin to accrue on the amount of the refund.

During third quarter of 2009, as a result of changing its tax accounting method for certain repairs, ACE’s uncertain tax benefits related to current year positions increased by $8 million, none of which, if recognized, would affect the effective tax rate.

(9) FAIR VALUE DISCLOSURES

Fair Value of Assets and Liabilities Excluding Debt

Effective January 1, 2008, ACE 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. ACE is able to classify fair value balances based on the observability of those 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). The three levels of the fair value hierarchy are as follows:

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

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

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

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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, 2009 and December 31, 2008. 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, 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	$	16	$	16	$	—	$	—
	$	16	$	16	$	—	$	—
LIABILITIES
Executive deferred compensation plan liabilities	$	1	$	—	$	1	$	—
	$	1	$	—	$	1	$	—

	Fair Value Measurements at December 31, 2008
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	$	75	$	75	$	—	$	—
Executive deferred compensation plan assets		1		1		—		—
	$	76	$	76	$	—	$	—
LIABILITIES
Executive deferred compensation plan liabilities	$	1	$	—	$	1	$	—
	$	1	$	—	$	1	$	—

Fair Value of Debt Instruments

The estimated fair values of ACE’s non-derivative financial instruments as of September 30, 2009 and December 31, 2008 are shown below:

	September 30, 2009				December 31, 2008
	(millions of dollars)
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	610	$	679	$	610	$	638
Transition Bonds issued by ACE Funding		411		443		433		431
Redeemable Serial Preferred Stock		6		4		6		4

The methods and assumptions below were used to estimate, as of September 30, 2009 and December 31, 2008, the fair value of each class of financial instruments shown above for which it is practicable to estimate a value.

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The fair values of the Long-term debt, which includes First Mortgage Bonds, Medium-Term Notes, and Transition Bonds issued by ACE Funding, including amounts due within one year, were derived based on current market prices, or were based on discounted cash flows using current rates for similar issues with similar terms and remaining maturities for issues with no market price available.

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

(10) COMMITMENTS AND CONTINGENCIES

Regulatory and Other Matters

Rate Proceedings

As described below, ACE has proposed the adoption of a bill stabilization adjustment mechanism (BSA) for retail customers. The proposed BSA 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 approved revenue-per-customer amount. The BSA increases rates if actual distribution revenues fall below the level approved by the applicable commission and decreases rates if actual distribution revenues are above the approved level. The result is that, over time, ACE collects its authorized revenues for distribution deliveries. As a consequence, a BSA “decouples” revenue from unit sales consumption and ties the growth in revenues to the growth in the number of customers. Some advantages of the BSA are that it (i) eliminates revenue fluctuations due to weather and changes in customer usage patterns and, therefore, provides for more predictable utility distribution revenues that are better aligned with costs, (ii) provides for more reliable fixed-cost recovery, (iii) tends to stabilize customers’ delivery bills, and (iv) removes any disincentives for ACE to promote energy efficiency programs for its customers, because it breaks the link between overall sales volumes and delivery revenues.

On February 20, 2009, ACE filed an application with the New Jersey Board of Public Utilities (NJBPU) (supplemented on February 23, 2009), which included a proposal for the implementation of a BSA. However, because a BSA mechanism has been proposed in the electric distribution base rate proceeding discussed in the next paragraph, the implementation of a BSA will be considered instead in that proceeding.

On August 14, 2009, ACE submitted a petition to the NJBPU to increase its electric distribution base rates, including a request for the implementation of a BSA. Based on a test year ending December 31, 2009, adjusted for known and measurable changes, ACE requested an annual net increase in its current retail distribution rates for electric service in the amount of approximately $54 million (which includes a reduction to its Regulatory Asset Recovery Charge) based on a requested return on equity (ROE) of 11.50% (or, if the BSA is approved, the requested rate increase would be reduced to approximately $52 million, based on an ROE of 11.25%). The procedural schedule has not yet been established.

ACE Sale of B.L. England Generating Facility

In February 2007, ACE completed the sale of the B.L. England generating facility to RC Cape May Holdings, LLC (RC Cape May), an affiliate of Rockland Capital Energy Investments, LLC. In July 2007, ACE received a claim for indemnification from RC Cape May under the purchase agreement in the amount of $25 million. RC Cape May contends that one of the assets it purchased, a contract for terminal services (TSA) between ACE and Citgo Asphalt Refining Co. (Citgo), has been declared by Citgo to have been terminated due to a failure by ACE to renew the contract in a timely manner. The claim for indemnification seeks payment from ACE in the event the TSA is held not to be enforceable against Citgo.

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

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Environmental Litigation

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

Delilah Road Landfill Site. In 1991, the New Jersey Department of Environmental Protection (NJDEP) identified ACE as a potentially responsible party (PRP) at the Delilah Road Landfill site in Egg Harbor Township, New Jersey. In 1993, ACE, along with two other PRPs, signed an administrative consent order with NJDEP to remediate the site. The soil cap remedy for the site has been implemented and in August 2006, NJDEP issued a No Further Action Letter (NFA) and Covenant Not to Sue for the site. Among other things, the NFA requires the PRPs to monitor the effectiveness of institutional (deed restriction) and engineering (cap) controls at the site every two years. In September 2007, NJDEP approved the PRP group’s petition to conduct semi-annual, rather than quarterly, ground water monitoring for two years and deferred until the end of the two-year period a decision on the PRP group’s request for annual groundwater monitoring thereafter. In August 2007, the PRP group agreed to reimburse the costs of the U.S. Environmental Protection Agency (EPA) in the amount of $81,400 in full satisfaction of EPA’s claims for all past and future response costs relating to the site (of which ACE’s share is one-third). Effective April 2008, EPA and the PRP group entered into a settlement agreement which will allow EPA to reopen the settlement in the event of new information or unknown conditions at the site. Based on information currently available, ACE anticipates that its share of additional cost associated with this site for post-remedy operation and maintenance will be approximately $555,000 to $600,000. On November 23, 2008, Lenox, Inc., a member of the PRP group, filed a bankruptcy petition under Chapter 11 of the U.S. Bankruptcy Code. ACE has filed a proof of claim in the Lenox bankruptcy seeking damages resulting from the rejection by Lenox, Inc., of its cost sharing obligations to ACE. ACE believes that its liability for post-remedy operation and maintenance costs will not have a material adverse effect on its financial position, results of operations or cash flows regardless of the impact of the Lenox bankruptcy. On August 11, 2009, EPA published simultaneously in the Federal Register, a notice of intent to delete, and a final notice of deletion of the Delilah Road Landfill site from the national priorities list. EPA published these actions simultaneously because the agency considers them to be noncontroversial and routine. EPA is proposing delisting the site, having determined that all appropriate response actions under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA) have been completed.

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

Franklin Slag Pile Site. On November 26, 2008, ACE received a general notice letter from EPA concerning the Franklin Slag Pile site in Philadelphia, Pennsylvania, asserting that ACE is a PRP that may have liability with respect to the site. If liable, ACE would be responsible for reimbursing EPA for clean-up costs incurred and to be incurred by the agency and for the costs of implementing an EPA-mandated remedy. The EPA’s claims are based on ACE’s sale of boiler slag from the B.L. England generating facility to MDC Industries, Inc. (MDC) during the period June 1978 to May 1983 (ACE owned B.L. England at that time and MDC formerly operated the Franklin Slag Pile site). EPA further claims that the boiler slag ACE

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sold to MDC contained copper and lead, which are hazardous substances under 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 such claims made by the EPA. In a May 2009 decision arising under CERCLA, which did not involve ACE, the U.S. Supreme Court rejected an EPA argument that the sale of a useful product constituted an arrangement for disposal or treatment of hazardous substances. While this decision supports ACE’s position, at this time ACE cannot predict how EPA will proceed with respect to the Franklin Slag Pile site, or what portion, if any, of the Franklin Slag Pile site response costs EPA would seek to recover from ACE.

Ward Transformer Site. In April 2009, a group of PRPs at 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 that the group has cost recovery and/or contribution claims against ACE with respect to past and future response costs incurred 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. Although it is too early in the process to characterize the magnitude of the potential liability at this site, based on interviews with long-time ACE employees and record reviews, it does not appear that ACE had extensive business transactions, if any, with the Ward Transformer site.

IRS Mixed Service Cost Issue

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

In 2005, the IRS issued Revenue Ruling 2005-53, which limited the ability of ACE to utilize its tax accounting method on its 2001 through 2004 tax returns. In accordance with this Revenue Ruling, the RAR for the 2001 and 2002 tax returns disallowed substantially all of the incremental tax benefits that ACE had claimed on those returns.

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

(11) RELATED PARTY TRANSACTIONS

PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries including ACE. The cost of these services is allocated in accordance with cost allocation methodologies set forth in the service agreement using a variety of factors, including the subsidiaries’ share of employees, operating expenses, assets, and other cost causal methods. These intercompany transactions are eliminated by PHI in consolidation and no profit results from these transactions at PHI. PHI Service Company costs directly charged or allocated to ACE for the three months ended September 30, 2009 and 2008 were $24 million and $25 million, respectively. PHI Service Company costs directly charged or allocated to ACE for the nine months ended September 30, 2009 and 2008 were $75 million and $71 million, respectively.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
Income (Expense)	2009			2008			2009			2008
	(millions of dollars)
Purchased power from Conectiv Energy Supply, Inc. (a)	$	(61	)	$	(70	)	$	(148	)	$	(128	)
Meter reading services provided by Millennium Account Services LLC (b)		(1	)		(1	)		(3	)		(3	)
Intercompany lease transactions (b)		—			—			(1	)		(1	)
Intercompany use revenue (c)		2			1			5			2
Intercompany use expense (c)		(1	)		(1	)		(2	)		(2	)

(a) Included in purchased energy expense.

(b) Included in other operation and maintenance expense.

(c) Included in operating revenue.

As of September 30, 2009 and December 31, 2008, ACE had the following balances due (to) from related parties:

Liability	September 30, 2009			December 31, 2008
	(millions of dollars)
Payable to Related Party (current)
PHI Service Company	$	(10	)	$	(11	)
Conectiv Energy Supply, Inc.		(15	)		(16	)

The items listed above are included in the “Accounts payable due to associated companies” balances on the Consolidated Balance Sheets of $28 million at each of September 30, 2009 and December 31, 2008.

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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	102
Pepco	142
DPL	148
ACE	155

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

Pepco Holdings, Inc.

General Overview

Pepco Holdings, Inc. (PHI or Pepco Holdings), a Delaware corporation incorporated in 2001, is a diversified energy company that, through its operating subsidiaries, is engaged primarily in two businesses:

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

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

The following table sets forth the percentage contributions to consolidated operating revenue and operating income attributable to the Power Delivery and Competitive Energy businesses.

	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
(% including Intercompany Transactions)
Percentage of Consolidated Operating Revenue
Power Delivery	56	%	55	%	55	%	52	%
Competitive Energy	47	%	49	%	48	%	53	%
Percentage of Consolidated Operating Income
Power Delivery	70	%	63	%	73	%	70	%
Competitive Energy	25	%	33	%	19	%	42	%
Percentage of Power Delivery Operating Revenue
Power Delivery Electric	98	%	97	%	95	%	94	%
Power Delivery Gas	2	%	3	%	5	%	6	%

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

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

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

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

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

In connection with its approval of new electric service distribution base rates for Pepco and DPL in Maryland, effective in June 2007, the Maryland Public Service Commission (MPSC) approved a bill stabilization adjustment mechanism (BSA) for retail customers. For customers to which the BSA applies, Pepco and DPL recognize distribution revenue based on the approved distribution charge per customer. From a revenue recognition standpoint, this has the effect of decoupling distribution revenue recognized in a reporting period from the amount of power delivered during the period. As a consequence, the only factors that will cause distribution revenue in Maryland to fluctuate from period to period are changes in the number of customers and changes in the approved distribution charge per customer. For customers to 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 revenue.

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

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

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

Each of Conectiv Energy and Pepco Energy Services is a separate operating segment for financial reporting purposes. The decrease in the Competitive Energy business’ percentage of consolidated operating income in 2009 was the result of a decrease in Conectiv Energy’s operating income, which was primarily due to substantially lower short-term sales of natural gas and natural gas transportation and storage rights in 2009. For the three months ended September 30, 2009 and 2008, 6% and 8% of the operating revenues of the Competitive Energy business were attributable to electric energy and capacity, and natural gas sold to the Power Delivery segment. For the nine months ended September 30, 2009 and 2008, 6% and 7% of the operating revenues of the Competitive Energy business were attributable to electric energy and capacity, and natural gas sold to the Power Delivery segment.

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

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

Through its subsidiary Potomac Capital Investment Corporation (PCI), PHI maintains a portfolio of cross-border energy sale-leaseback transactions with a book value at September 30, 2009 of approximately $1.4 billion. This activity constitutes a fourth operating segment, which is designated as “Other Non-Regulated,” for financial reporting purposes. For a discussion of PHI’s cross-border leasing transactions, see Note (14), “Commitments and Contingencies—Regulatory and Other Matters – PHI’s Cross-Border Energy Lease Investments,” to the consolidated financial statements of PHI set forth in Part I, Item 1 of this Form 10-Q.

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Earnings Overview

Three Months Ended September 30, 2009 Compared to Three Months Ended September 30, 2008

PHI’s net income for the three months ended September 30, 2009 was $124 million, or $.56 per share, compared to $119 million, or $.59 per share, for the three months ended September 30, 2008.

Net income 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:

Mirant Corporation (Mirant) bankruptcy claims settlement	$	16
Maryland income tax benefit, net of fees	$	11

Excluding the items listed above, net income would have been $97 million, or $.44 per share, for the three months ended September 30, 2009.

PHI’s net income for the three months ended September 30, 2009 and 2008, by operating segment, is set forth in the table below (in millions of dollars):

	2009			2008			Change
Power Delivery	$	94		$	77		$	17
Conectiv Energy		21			49			(28	)
Pepco Energy Services		14			3			11
Other Non-Regulated		7			5			2
Corporate and Other		(12	)		(15	)		3
Total PHI Net Income	$	124		$	119		$	5

Discussion of Operating Segment Net Income Variances:

Power Delivery’s $17 million increase in earnings is primarily due to the following:

• $16 million increase due to 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. (Panda) and Pepco (the Panda PPA) to a third party.

• $11 million increase due to a Maryland income tax benefit, net of $1 million (after tax) in professional fees, related to a change in the tax reporting for the disposition of certain assets in prior years.

• $6 million increase from ACE Basic Generation Service related to unbilled revenue.

• $6 million decrease due to higher operating and maintenance expenses (primarily higher pension expenses).

• $5 million decrease due to higher interest expense associated with an increase in outstanding debt.

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Conectiv Energy’s $28 million decrease in earnings is primarily due to the following:

Merchant Generation & Load Service earnings decreased approximately $23 million primarily due to:

• $27 million decrease primarily related to economic fuel hedges that were favorable in the third quarter of 2008 due to high fuel prices and unfavorable in the third quarter of 2009 due to low fuel prices.

• $26 million decrease resulting from lower run-time (down 16%) and reduced spark (natural gas) spreads and dark (coal) spreads (down 57%).

• $16 million increase due to higher margins for default electricity supply contracts and associated hedges primarily due to lower power prices.

• $14 million increase due to an increase in capacity margins primarily due to higher Reliability Pricing Model (RPM) clearing prices in the eastern part of PJM.

Energy Marketing earnings decreased approximately $6 million primarily due to power marketing activities.

Pepco Energy Services’ $11 million increase in earnings is primarily due to the following:

• $10 million increase due to the lower cost of electricity and electricity supply costs and lower losses on energy derivative contracts accounted for at fair value for the energy supply business.

• $6 million increase due to lower RPM charges and higher PJM capacity prices associated with the power plants.

• $4 million decrease due to higher interest and other expenses, primarily associated with credit and collateral facilities for the retail energy supply business.

Nine Months Ended September 30, 2009 Compared to Nine Months Ended September 30, 2008

PHI’s net income for the nine months ended September 30, 2009 was $194 million, or $.88 per share, compared to $233 million, or $1.16 per share, for the nine months ended September 30, 2008.

Net income 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:

Mirant bankruptcy claims settlement	$	24
Maryland income tax benefit, net of fees	$	11

Excluding the items listed above, net income would have been $159 million, or $.72 per share, for the nine months ended September 30, 2009.

PHI’s net income for the nine months ended September 30, 2008, included the charges set forth below in the Other Non-Regulated operating segment, which are presented net of federal and state income taxes and are in millions of dollars:

Adjustment to the equity value of cross-border energy lease investments at PCI to reflect the impact of a change in assumptions regarding the estimated timing of the tax benefits	$	(86	)
Additional interest accrued related to the estimated federal and state income tax obligations from the change in assumptions regarding the estimated timing of the tax benefits on cross-border energy lease investments	$	(7	)

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Excluding the items listed above, net income would have been $326 million, or $1.62 per share, for the nine months ended September 30, 2008.

PHI’s net income for the nine months ended September 30, 2009 and 2008, by operating segment, is set forth in the table below (in millions of dollars):

	2009			2008			Change
Power Delivery	$	167		$	199		$	(32	)
Conectiv Energy		11			118			(107	)
Pepco Energy Services		32			28			4
Other Non-Regulated		21			(69	)		90
Corporate and Other		(37	)		(43	)		6
Total PHI Net Income	$	194		$	233		$	(39	)

Discussion of Operating Segment Net Income Variances:

Power Delivery’s $32 million decrease in earnings is primarily due to the following:

• $18 million decrease due to higher operating and maintenance expenses (primarily higher pension expenses).

• $17 million decrease due to higher interest expense associated with an increase in outstanding debt.

• $12 million decrease due to favorable income tax adjustments in 2008, primarily interest resulting from Financial Accounting Standards Board (FASB) guidance on income taxes (ASC 740).

• $6 million decrease due to higher depreciation expense associated with increased plant.

• $5 million decrease due to lower distribution sales related to customer usage (weather and non-weather).

• $4 million decrease due to lower Default Electricity Supply margins, primarily due to increased bad debt expense and commercial customer migration to competitive suppliers.

• $24 million increase due to approvals by the District of Columbia Public Service Commission (DCPSC) and 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.

• $11 million increase due to a Maryland income tax benefit, net of $1 million (after tax) in professional fees, related to a change in the tax reporting for the disposition of certain assets in prior years.

Conectiv Energy’s $107 million decrease in earnings is primarily due to the following:

Merchant Generation & Load Service earnings decreased approximately $105 million primarily due to:

• $73 million decrease resulting from significantly lower run-time (down 23%) and reduced spark (natural gas) spreads and dark (coal) spreads (down 58%).

• $66 million decrease primarily related to economic fuel hedges that were favorable in the first nine months of 2008 due to rising fuel prices and unfavorable in the first nine months of 2009 due to falling fuel prices.

• $24 million increase due to an increase in capacity margins, primarily due to higher RPM clearing prices in the eastern part of PJM.

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• $10 million increase due to higher margins from default electricity supply contracts and associated hedges primarily due to lower power prices.

Energy Marketing earnings decreased approximately $3 million primarily due to gas marketing activities.

Pepco Energy Services’ $4 million increase in earnings is primarily due to the following:

• $23 million increase due to the lower cost of electricity and electricity supply costs; partially offset by losses on energy derivative contracts accounted for at fair value for the retail energy supply business.

• $13 million decrease due to higher interest and other expenses primarily associated with credit and collateral facilities for the retail energy supply business.

• $4 million decrease due to higher operating costs for the power plants.

• $3 million decrease due to lower construction activities.

Other Non-Regulated’s $90 million increase in earnings is primarily due to the impact of the cross-border energy lease investment re-evaluation adjustment recorded in June 2008.

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Consolidated Results Of Operations

The following results of operations discussion is for the three months ended September 30, 2009, compared to the three months ended September 30, 2008. All amounts in the tables (except sales and customers) are in millions of dollars.

Operating Revenue

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

	2009			2008			Change
Power Delivery	$	1,428		$	1,668		$	(240	)
Conectiv Energy		581			783			(202	)
Pepco Energy Services		611			716			(105	)
Other Non-Regulated		13			14			(1	)
Corporate and Other		(94	)		(121	)		27
Total Operating Revenue	$	2,539		$	3,060		$	(521	)

Power Delivery Business

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

	2009		2008		Change
Regulated T&D Electric Revenue	$	482	$	502	$	(20	)
Default Supply Revenue		901		1,096		(195	)
Other Electric Revenue		17		17		—
Total Electric Operating Revenue		1,400		1,615		(215	)
Regulated Gas Revenue		20		18		2
Other Gas Revenue		8		35		(27	)
Total Gas Operating Revenue		28		53		(25	)
Total Power Delivery Operating Revenue	$	1,428	$	1,668	$	(240	)

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

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

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

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

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

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Electric Operating Revenue

Regulated T&D Electric Revenue	2009		2008		Change
Residential	$	190	$	193	$	(3	)
Commercial and industrial		229		228		1
Other		63		81		(18	)
Total Regulated T&D Electric Revenue	$	482	$	502	$	(20	)

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

Regulated T&D Electric Sales (Gigawatt hours (GWh))	2009	2008	Change
Residential	4,997	5,165	(168	)
Commercial and industrial	8,653	8,826	(173	)
Other	59	59	—
Total Regulated T&D Electric Sales	13,709	14,050	(341	)
Regulated T&D Electric Customers (in thousands)	2009	2008	Change
Residential	1,614	1,605	9
Commercial and industrial	197	198	(1	)
Other	2	2	—
Total Regulated T&D Electric Customers	1,813	1,805	8

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

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

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

Regulated T&D Electric Revenue decreased by $20 million primarily due to:

• A decrease of $17 million in Other Regulated T&D Electric Revenue (offset in Fuel and Purchased Energy and Other Services Cost of Sales) due to the absence of revenues from the resale of energy and capacity purchased under the Panda PPA as the result of the transfer of the Panda PPA to an unaffiliated third party in September 2008.

• A decrease of $5 million due to lower sales as a result of milder weather during the 2009 summer months as compared to 2008.

The aggregate amount of these decreases was partially offset by:

• An increase of $4 million due to higher pass-through revenue primarily resulting from tax rate changes (substantially offset in Other Taxes).

As the result of the adoption of a bill stabilization adjustment (BSA) in the Maryland service territory, changes in customer usage due to weather or other factors no longer affect distribution revenue.

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Default Electricity Supply

Default Supply Revenue	2009		2008		Change
Residential	$	619	$	622	$	(3	)
Commercial and industrial		247		378		(131	)
Other		35		96		(61	)
Total Default Supply Revenue	$	901	$	1,096	$	(195	)

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

Default Electricity Supply Sales (GWh)	2009	2008	Change
Residential	4,804	5,005	(201	)
Commercial and industrial	2,144	2,909	(765	)
Other	23	22	1
Total Default Electricity Supply Sales	6,971	7,936	(965	)
Default Electricity Supply Customers (in thousands)	2009	2008	Change
Residential	1,563	1,564	(1	)
Commercial and industrial	159	167	(8	)
Other	2	2	—
Total Default Electricity Supply Customers	1,724	1,733	(9	)

Default Supply Revenue, which is substantially offset in Fuel and Purchased Energy and Other Services Cost of Sales and Deferred Electric Service Costs, decreased by $195 million primarily due to:

• A decrease of $88 million due to lower sales primarily the result of commercial customer migration to competitive suppliers.

• A decrease of $64 million in wholesale energy revenues due to lower market prices for the sale of electricity purchased from NUGs.

• A decrease of $28 million due to lower sales as a result of milder weather during the 2009 summer months as compared to 2008.

• A decrease of $15 million as the result of lower Default Electricity Supply rates.

The decrease in total Default Supply Revenue includes an increase of $10 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. Accordingly, 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 earnings in the period accrued. While the change in the amount of unbilled revenue from year to year typically is not significant, for the three months ended September 30, 2009 as compared to the comparable period for 2008, BGS unbilled revenue increased by $10 million, which resulted in a $6 million increase in PHI’s net income. The increase was due to higher customer usage and warmer weather during the unbilled revenue period at the end of the quarter as compared to the corresponding period in 2008.

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Gas Operating Revenue

Regulated Gas Revenue	2009		2008		Change
Residential	$	11	$	9	$	2
Commercial and industrial		7		7		—
Transportation and other		2		2		—
Total Regulated Gas Revenue	$	20	$	18	$	2
Regulated Gas Sales (billion cubic feet)	2009		2008		Change
Residential		1		—		1
Commercial and industrial		1		1		—
Transportation and other		1		1		—
Total Regulated Gas Sales		3		2		1
Regulated Gas Customers (in thousands)	2009		2008		Change
Residential		113		112		1
Commercial and industrial		9		10		(1	)
Transportation and other		—		—		—
Total Regulated Gas Customers		122		122		—

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

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

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

Other Gas Revenue

Other Gas Revenue, which is substantially offset in Fuel and Purchased Energy and Other Services Cost of Sales, decreased by $27 million primarily due to lower revenue from off-system sales resulting from:

• A decrease of $23 million due to lower market prices.

• A decrease of $4 million due to lower demand from electric generators and gas marketers.

Conectiv Energy

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

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

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Conectiv Energy Gross Margin

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

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

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Conectiv Energy Gross Margin and Operating Statistics	Three Months Ended September 30,
	2009			2008			Change
Operating Revenue ($ millions):
Merchant Generation & Load Service	$	459		$	442		$	17
Energy Marketing		122			341			(219	)
Total Operating Revenue (a)	$	581		$	783		$	(202	)
Cost of Sales ($ millions):
Merchant Generation & Load Service	$	385		$	329		$	56
Energy Marketing		115			324			(209	)
Total Cost of Sales (b)	$	500		$	653		$	(153	)
Gross Margin ($ millions):
Merchant Generation & Load Service	$	74		$	113		$	(39	)
Energy Marketing		7			17			(10	)
Total Gross Margin	$	81		$	130		$	(49	)
Generation Fuel and Purchased Power Expenses ($ millions) (c):
Generation Fuel Expenses (d),(e)
Natural Gas	$	126		$	98		$	28
Coal		(2	)		16			(18	)
Oil		3			(1	)		4
Other (f)		1			1			—
Total Generation Fuel Expenses	$	128		$	114		$	14
Purchased Power Expenses (e)	$	225		$	259		$	(34	)
Statistics:
Generation Output (Megawatt hours(MWh)):
Base-Load (g)		99,024			437,049			(338,025	)
Mid-Merit (Combined Cycle) (h)		1,230,821			1,318,196			(87,375	)
Mid-Merit (Oil Fired) (i)		11,271			323			10,948
Peaking		21,813			30,681			(8,868	)
Tolled Generation		186,161			64,957			121,204
Total		1,549,090			1,851,206			(302,116	)
Load Service Volume (MWh) (j)		1,502,679			2,907,205			(1,404,526	)
Average Power Sales Price (k) ($/MWh):
Generation Sales (d)	$	44.21		$	117.50		$	(73.29	)
Non-Generation Sales (l)	$	88.52		$	101.70		$	(13.18	)
Total	$	66.07		$	107.65		$	(41.58	)
Average on-peak spot power price at PJM East Hub ($/MWh) (m)	$	43.70		$	107.66		$	(63.96	)
Average around-the-clock spot power price at PJM East Hub ($/MWh) (m)	$	35.89		$	89.62		$	(53.73	)
Average spot natural gas price at market area M3 ($/MMBtu) (n)	$	3.41		$	9.71		$	(6.30	)
Weather (degree days at Philadelphia Airport): (o)
Heating degree days		19			12			7
Cooling degree days		885			942			(57	)

Notes:

(a) Includes $91 million and $115 million of affiliate transactions for 2009 and 2008, respectively.

(b) Includes $2 million of affiliate transactions for 2009 and 2008, respectively. Also, excludes depreciation and amortization expense of $10 million and $9 million, respectively.

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

(d) Includes tolled generation.

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(e) Includes associated hedging gains and losses.

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

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

(h) Hay Road and Bethlehem, all units.

(i) Edge Moor Unit 5 and Deepwater Unit 1.

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

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

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

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

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

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

Conectiv Energy’s revenue and cost of sales were lower for the three months ended September 30, 2009, primarily due to decreased generation fleet output and lower default electricity supply volumes due to a decreased demand for power driven by the economic recession and mild weather. Conectiv Energy’s ability to take advantage of its fleet of mid-merit and peaking generation assets to generate high margins during peak usage periods was limited by lower demand and low energy commodity prices. In contrast, Conectiv Energy’s gross margins in the third quarter of 2008 were favorably affected by higher energy commodity prices and price volatility during the period.

Merchant Generation & Load Service gross margin decreased approximately $39 million primarily due to:

• A decrease of approximately $44 million of physical generation gross margin resulting from lower run-time (down 16%) and reduced spark spreads and dark spreads (down 57%).

• A decrease of approximately $45 million primarily related to economic fuel hedges that were favorable in the third quarter of 2008 due to high fuel prices and unfavorable in the third quarter of 2009 due to low fuel prices.

• An increase of approximately $27 million resulting from higher gross margins for default electricity supply contracts and associated hedges, primarily due to lower power prices.

• An increase of approximately $23 million due to an increase in capacity gross margin, primarily due to higher RPM clearing prices in the eastern part of PJM.

Energy Marketing gross margin decreased approximately $10 million primarily due to power marketing activities.

Pepco Energy Services

Pepco Energy Services’ operating revenue decreased $105 million primarily due to:

• $94 million decrease due to lower volumes of retail electric load served due to the continuing expiration of existing retail contracts.

• $23 million decrease due to lower construction activities.

• $8 million increase due to higher generation output and higher PJM capacity prices.

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Operating Expenses

Fuel and Purchased Energy and Other Services Cost of Sales

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

	2009			2008			Change
Power Delivery	$	914		$	1,113		$	(199	)
Conectiv Energy		500			653			(153	)
Pepco Energy Services		555			686			(131	)
Corporate and Other		(93	)		(119	)		26
Total	$	1,876		$	2,333		$	(457	)

Power Delivery Business

Power Delivery’s Fuel and Purchased Energy and Other Services Cost of Sales decreased by $199 million primarily due to:

• A decrease of $98 million primarily due to commercial customer migration to competitive suppliers.

• A decrease of $28 million due to lower electricity sales primarily as a result of milder weather during the 2009 summer months as compared to 2008.

• A decrease of $26 million in the cost of gas purchases for off-system sales, the result of lower average gas prices and volumes purchased.

• A decrease of $25 million due to lower average electricity costs under new Default Electricity Supply contracts.

• A decrease of $17 million due to the transfer of the Panda PPA.

The aggregate amount of these decreases was partially offset by:

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

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

Conectiv Energy

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

Pepco Energy Services

Pepco Energy Services’ Fuel and Purchased Energy and Other Services Cost of Sales decreased $131 million primarily due to:

• $110 million decrease due to lower volumes of electricity purchased to serve decreased retail customer load.

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• $15 million decrease due to lower construction activities.

Other Operation and Maintenance

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

	2009			2008			Change
Power Delivery	$	198		$	190		$	8
Conectiv Energy		28			30			(2	)
Pepco Energy Services		24			22			2
Other Non-Regulated		—			1			(1	)
Corporate and Other		(10	)		(2	)		(8	)
Total	$	240		$	241		$	(1	)

Other Operation and Maintenance expense for Power Delivery increased by $8 million; however, excluding a decrease of $6 million primarily related to administrative and bad debt expenses that are deferred and recoverable, Other Operation and Maintenance expense increased by $14 million. The $14 million increase was primarily due to:

• An increase of $6 million in employee-related costs, primarily due to higher pension and other postretirement benefit expenses.

• An increase of $6 million primarily due to higher emergency restoration and tree trimming costs.

In the third quarter of 2008, DPL recorded an adjustment to correct errors in Other Operation and Maintenance expenses for prior periods dating back to May 2006 for which late payment fees were incorrectly recognized. This adjustment resulted in an increase in Other Operation and Maintenance expenses for the three months ended September 30, 2008 of $4 million. Also in the third quarter of 2008, PHI identified an error in the accounting for certain of its restricted stock awards granted under the Long-Term Incentive Plan (LTIP) which resulted in an understatement of stock-based compensation expense in 2006 and 2007. This error was corrected in the third quarter of 2008, resulting in an increase in Other Operation and Maintenance expenses for the three months ended September 30, 2008 of $9 million. These adjustments were not considered material either individually or in the aggregate.

Deferred Electric Service Costs

Deferred Electric Service Costs, which relate only to ACE, decreased by $44 million, the result of a reduction of expenses of $32 million in 2009, as compared to an increase of expenses of $12 million in 2008. The decrease was primarily due to a lower rate of recovery of costs from energy and capacity purchased under the NUG contracts.

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

Effect of Settlement of Mirant Bankruptcy Claims

In September 2008, Pepco transferred the Panda PPA to an unaffiliated third party. In 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 three months ended September 30, 2009, reflecting the Maryland proceeds retained by Pepco.

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Other Income (Expenses)

Other Expenses (which are net of Other Income) increased by $12 million to a net expense of $88 million in 2009 from a net expense of $76 million in 2008. The increase was primarily due to a $13 million increase in interest expense on long-term debt as the result of a higher amount of outstanding debt.

Income Tax Expense

PHI’s effective tax rates for the three months ended September 30, 2009 and 2008 were 34.4% and 40.2%, respectively. The decrease in the rate primarily resulted from a refund of $6 million (after tax) of state income taxes and the establishment of a state tax benefit carryforward of $7 million (after tax), each related to a change in the tax reporting for the disposition of certain assets in prior years.

The following results of operations discussion is for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008. All amounts in the tables (except sales and customers) are in millions of dollars.

Operating Revenue

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

	2009			2008			Change
Power Delivery	$	3,895		$	4,260		$	(365	)
Conectiv Energy		1,625			2,395			(770	)
Pepco Energy Services		1,828			1,968			(140	)
Other Non-Regulated		40			(73	)		113
Corporate and Other		(264	)		(331	)		67
Total Operating Revenue	$	7,124		$	8,219		$	(1,095	)

Power Delivery Business

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

	2009		2008		Change
Regulated T&D Electric Revenue	$	1,263	$	1,302	$	(39	)
Default Supply Revenue		2,379		2,658		(279	)
Other Electric Revenue		54		48		6
Total Electric Operating Revenue		3,696		4,008		(312	)
Regulated Gas Revenue		169		146		23
Other Gas Revenue		30		106		(76	)
Total Gas Operating Revenue		199		252		(53	)
Total Power Delivery Operating Revenue	$	3,895	$	4,260	$	(365	)

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

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

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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 consists of revenues for on-system natural gas sales and the transportation of natural gas for customers by DPL within its service territories at regulated rates.

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

Electric Operating Revenue

	2009		2008		Change
Regulated T&D Electric Revenue
Residential	$	464	$	460	$	4
Commercial and industrial		611		598		13
Other		188		244		(56	)
Total Regulated T&D Electric Revenue	$	1,263	$	1,302	$	(39	)

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

	2009	2008	Change
Regulated T&D Electric Sales (GWh)
Residential	13,219	13,324	(105	)
Commercial and industrial	23,965	24,783	(818	)
Other	185	185	—
Total Regulated T&D Electric Sales	37,369	38,292	(923	)
	2009	2008	Change
Regulated T&D Electric Customers (in thousands)
Residential	1,614	1,605	9
Commercial and industrial	197	198	(1	)
Other	2	2	—
Total Regulated T&D Electric Customers	1,813	1,805	8

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

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

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

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

• A decrease of $53 million in Other Regulated T&D Electric Revenue (offset in Fuel and Purchased Energy and Other Services Cost of Sales) due to the absence of revenues from the resale of energy and capacity purchased under the Panda PPA as the result of the transfer of the Panda PPA to an unaffiliated third party in September 2008.

• A decrease of $10 million due to lower non-weather related customer usage.

The aggregate amount of these decreases was partially offset by:

• An increase of $16 million due to a distribution rate change as part of a higher New Jersey Societal Benefit Charge that became effective in June 2008 (substantially offset in Deferred Electric Service Costs).

• An increase of $13 million due to higher pass-through revenue primarily resulting from tax rate changes (substantially offset in Other Taxes).

Default Electricity Supply

	2009		2008		Change
Default Supply Revenue
Residential	$	1,519	$	1,461	$	58
Commercial and industrial		739		928		(189	)
Other		121		269		(148	)
Total Default Supply Revenue	$	2,379	$	2,658	$	(279	)

Other Default Supply Revenue consists primarily of revenue from the resale by ACE in the PJM RTO market of energy and capacity purchased under contracts with unaffiliated NUGs.

	2009	2008	Change
Default Electricity Supply Sales (GWh)
Residential	12,770	12,901	(131	)
Commercial and industrial	6,764	7,854	(1,090	)
Other	71	72	(1	)
Total Default Electricity Supply Sales	19,605	20,827	(1,222	)
	2009	2008	Change
Default Electricity Supply Customers (in thousands)
Residential	1,563	1,564	(1	)
Commercial and industrial	159	167	(8	)
Other	2	2	—
Total Default Electricity Supply Customers	1,724	1,733	(9	)

Default Supply Revenue, which is substantially offset in Fuel and Purchased Energy and Other Services Cost of Sales and Deferred Electric Service Costs, decreased by $279 million primarily due to:

• A decrease of $147 million in wholesale energy revenues due to lower market prices for the sale of electricity purchased from NUGs.

• A decrease of $91 million due to lower sales primarily the result of commercial customer migration to competitive suppliers.

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• A decrease of $37 million due to lower non-weather related customer usage.

• A decrease of $20 million due to lower sales as a result of milder weather during the 2009 summer months as compared to 2008.

The aggregate amount of these decreases was partially offset by:

• An increase of $26 million as the result of higher Default Electricity Supply rates.

The decrease in total Default Supply Revenue includes a decrease of $4 million in unbilled revenue attributable to ACE’s BGS. Under the BGS terms approved by the NJBPU, ACE is entitled to recover from its customers all of its costs of providing BGS. Accordingly, 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 earnings in the period 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, 2009 as compared to the comparable period for 2008, BGS unbilled revenue decreased by $4 million, which resulted in a $2 million decrease in PHI’s net income. The decrease was due to increased customer migration and milder weather during the unbilled revenue period at the end of the nine months ended September 30, 2009 as compared to the corresponding period in 2008.

Gas Operating Revenue

	2009		2008		Change
Regulated Gas Revenue
Residential	$	103	$	86	$	17
Commercial and industrial		60		54		6
Transportation and other		6		6		—
Total Regulated Gas Revenue	$	169	$	146	$	23
	2009		2008		Change
Regulated Gas Sales (billion cubic feet)
Residential		6		5		1
Commercial and industrial		4		4		—
Transportation and other		4		5		(1	)
Total Regulated Gas Sales		14		14		—
	2009		2008		Change
Regulated Gas Customers (in thousands)
Residential		113		112		1
Commercial and industrial		9		10		(1	)
Transportation and other		—		—		—
Total Regulated Gas Customers		122		122		—

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

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

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

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Regulated Gas Revenue increased by $23 million primarily due to:

• An increase of $19 million primarily due to the Gas Cost Rate changes effective November 2008 and March 2009.

• An increase of $10 million due to higher sales as a result of colder weather during the 2009 winter heating season as compared to 2008.

The aggregate amount of these increases was partially offset by:

• A decrease of $10 million due to lower non-weather related customer usage.

Other Gas Revenue

Other Gas Revenue, which is substantially offset in Fuel and Purchased Energy and Other Services Cost of Sales, decreased by $76 million primarily due to lower revenue from off-system sales resulting from:

• A decrease of $64 million due to lower market prices.

• A decrease of $12 million due to lower demand from electric generators and gas marketers.

Conectiv Energy

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

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

Conectiv Energy Gross Margin

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

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

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Conectiv Energy Gross Margin and Operating Statistics	Nine Months Ended September 30,
	2009		2008		Change
Operating Revenue ($ millions):
Merchant Generation & Load Service	$	1,170	$	1,436	$	(266	)
Energy Marketing		455		959		(504	)
Total Operating Revenue (a)	$	1,625	$	2,395	$	(770	)
Cost of Sales ($ millions):
Merchant Generation & Load Service	$	1,035	$	1,123	$	(88	)
Energy Marketing		421		919		(498	)
Total Cost of Sales (b)	$	1,456	$	2,042	$	(586	)
Gross Margin ($ millions):
Merchant Generation & Load Service	$	135	$	313	$	(178	)
Energy Marketing		34		40		(6	)
Total Gross Margin	$	169	$	353	$	(184	)
Generation Fuel and Purchased Power Expenses ($ millions) (c):
Generation Fuel Expenses (d),(e)
Natural Gas	$	185	$	199	$	(14	)
Coal		6		45		(39	)
Oil		21		26		(5	)
Other (f)		3		1		2
Total Generation Fuel Expenses	$	215	$	271	$	(56	)
Purchased Power Expenses (e)	$	706	$	742	$	(36	)
Statistics:
Generation Output (MWh):
Base-Load (g)		509,993		1,371,003		(861,010	)
Mid-Merit (Combined Cycle) (h)		1,914,019		2,281,981		(367,962	)
Mid-Merit (Oil Fired) (i)		42,452		64,720		(22,268	)
Peaking		29,572		75,838		(46,266	)
Tolled Generation		492,151		100,396		391,755
Total		2,988,187		3,893,938		(905,751	)
Load Service Volume (MWh) (j)		4,997,198		8,175,573		(3,178,375	)
Average Power Sales Price (k) ($/MWh):
Generation Sales (d)	$	49.90	$	117.77	$	(67.87	)
Non-Generation Sales (l)	$	88.23	$	91.88	$	(3.65	)
Total	$	73.97	$	99.26	$	(25.29	)
Average on-peak spot power price at PJM East Hub ($/MWh) (m)	$	48.31	$	100.40	$	(52.09	)
Average around-the-clock spot power price at PJM East Hub ($/MWh) (m)	$	41.97	$	84.10	$	(42.13	)
Average spot natural gas price at market area M3 ($/MMBtu) (n)	$	4.57	$	10.65	$	(6.08	)
Weather (degree days at Philadelphia Airport): (o)
Heating degree days		2,966		2,744		222
Cooling degree days		1,218		1,335		(117	)

(a) Includes $252 million and $311 million of affiliate transactions for 2009 and 2008, respectively.

(b) Includes less than $1 million and $6 million of affiliate transactions for 2009 and 2008, respectively. Also, excludes depreciation and amortization expense of $29 million and $28 million, respectively.

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

(d) Includes tolled generation.

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(e) Includes associated hedging gains and losses.

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

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

(h) Hay Road and Bethlehem, all units.

(i) Edge Moor Unit 5 and Deepwater Unit 1.

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

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

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

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

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

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

Conectiv Energy’s revenue and cost of sales were lower for the nine months ended September 30, 2009 primarily due to decreased generation fleet output and lower default electricity supply volumes due to a decreased demand for power driven by the economic recession and mild weather. Conectiv Energy’s ability to take advantage of its fleet of mid-merit and peaking generation assets to generate high margins during peak usage periods was limited by lower demand and low energy commodity prices. In contrast, Conectiv Energy’s gross margins in 2008 were favorably affected by higher energy commodity prices and price volatility during the period.

Merchant Generation & Load Service gross margin decreased approximately $178 million primarily due to:

• A decrease of approximately $123 million of physical generation margin resulting from significantly lower run-time (down 23%) and reduced spark spreads and dark spreads (down 58%).

• A decrease of approximately $112 million primarily related to economic fuel hedges that were favorable in the first nine months of 2008 due to rising fuel prices and unfavorable in the first nine months of 2009 due to falling fuel prices.

• An increase of approximately $16 million resulting from higher gross margins from default electricity supply contracts and associated hedges, primarily due to lower power prices.

• An increase of approximately $41 million due to an increase in capacity margin, primarily due to higher RPM clearing prices in the eastern part of PJM.

Energy Marketing gross margin decreased approximately $6 million primarily due to gas marketing activities.

Pepco Energy Services

Pepco Energy Services’ operating revenue decreased $140 million primarily due to:

• $66 million decrease due to lower construction activities.

• $58 million decrease due to lower volumes of retail electric load served due to the continuing expiration of existing retail contracts.

• $8 million decrease due to lower generation output due to milder than normal weather and lower overall load levels for the PJM control area.

• $7 million decrease due to lower retail natural gas prices partially offset by higher customer load from customer acquisitions.

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Other Non-Regulated

Other Non-Regulated revenues increased by $113 million from $(73) million for the nine months ended September 30, 2008 to $40 million for the nine months ended September 30, 2009. This was primarily the result of a non-cash charge of $124 million that was recorded in the quarter ended June 30, 2008 as a result of revised assumptions regarding the estimated timing of tax benefits from PCI’s cross-border energy lease investments. In accordance with FASB guidance on leases (ASC 840), the charge was recorded as a reduction to lease revenue from these transactions, which is included in Other Non-Regulated revenues.

Operating Expenses

Fuel and Purchased Energy and Other Services Cost of Sales

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

	2009			2008			Change
Power Delivery	$	2,560		$	2,776		$	(216	)
Conectiv Energy		1,456			2,042			(586	)
Pepco Energy Services		1,674			1,852			(178	)
Corporate and Other		(258	)		(327	)		69
Total	$	5,432		$	6,343		$	(911	)

Power Delivery Business

Power Delivery’s Fuel and Purchased Energy and Other Services Cost of Sales decreased by $216 million primarily due to:

• A decrease of $142 million primarily due to commercial customer migration to competitive suppliers.

• A decrease of $73 million in the cost of gas purchases for off-systems sales, the result of lower average gas prices and volumes purchased.

• A decrease of $53 million due to the transfer of the Panda PPA.

• A decrease of $20 million in the cost of gas purchases for system sales, the result of lower average gas prices and volumes purchased.

• A decrease of $18 million due to lower average electricity costs under new Default Electricity Supply contracts.

• A decrease of $18 million due to lower electricity sales as a result of milder weather during the 2009 summer months as compared to 2008.

The aggregate amount of these decreases was partially offset by:

• An increase of $69 million due to a higher rate of recovery of electric supply costs resulting in a change in the Default Electricity Supply deferral balance.

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• An increase of $41 million from the settlement of financial hedges entered into as part of DPL’s hedge program for regulated natural gas.

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

Conectiv Energy

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

Pepco Energy Services

Pepco Energy Services’ Fuel and Purchased Energy and Other Services Cost of Sales decreased $178 million primarily due to:

• $102 million decrease due to lower volumes of electricity purchased to serve decreased retail customer load from the continuing expiration of existing retail contracts.

• $44 million decrease due to lower construction activities.

• $25 million decrease due to lower wholesale natural gas prices partially offset by higher retail customer load from customer acquisitions.

• $8 million decrease due to lower generation output.

Other Operation and Maintenance

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

	2009			2008			Change
Power Delivery	$	569		$	534		$	35
Conectiv Energy		98			105			(7	)
Pepco Energy Services		68			62			6
Other Non-Regulated		2			2			—
Corporate and Other		(24	)		(12	)		(12	)
Total	$	713		$	691		$	22

Other Operation and Maintenance expense for Power Delivery increased by $35 million; however, excluding a decrease of $2 million primarily related to administrative expenses that are deferred and recoverable, Other Operation and Maintenance expense increased by $37 million. The $37 million increase was primarily due to:

• An increase of $31 million in employee-related costs, primarily due to higher pension and other postretirement benefit expenses.

• An increase of $5 million in regulatory expenses primarily incurred in connection with the District of Columbia distribution rate case.

• An increase of $4 million due to higher non-deferrable bad debt expenses.

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In the second quarter of 2008, Pepco recorded an adjustment to correct errors in Other Operation and Maintenance expenses for prior periods dating back to February 2005 for which late payment fees were incorrectly recognized. This adjustment resulted in an increase in Other Operation and Maintenance expenses for the nine months ended September 30, 2008 of $3 million. In the third quarter of 2008, DPL also recorded an adjustment to correct errors in Other Operation and Maintenance expenses for prior periods dating back to May 2006 for which late payment fees were incorrectly recognized. This adjustment resulted in an increase in Other Operation and Maintenance expenses for the nine months ended September 30, 2008 of $3 million. Also in the third quarter of 2008, PHI identified an error in the accounting for certain of its restricted stock awards granted under the LTIP which resulted in an understatement of stock-based compensation expense in 2006 and 2007. This error was corrected in the third quarter of 2008, resulting in an increase in Other Operation and Maintenance expenses for the nine months ended September 30, 2008 of $9 million. These adjustments were not considered material either individually or in the aggregate.

Depreciation and Amortization

Depreciation and Amortization expenses increased by $11 million to $294 million in 2009 from $283 million in 2008 primarily due to an increase of $10 million due to utility plant additions, partially offset by a decrease of $5 million due to lower amortization by ACE of stranded costs primarily as the result of an October 2008 Market Transition Charge Tax rate decrease (offset in Default Supply Revenue).

Other Taxes

Other Taxes increased by $9 million to $282 million in 2009 from $273 million in 2008. The increase was primarily due to increased pass-throughs experienced by Power Delivery resulting from tax rate changes (substantially offset in Regulated T&D Electric Revenue).

Deferred Electric Service Costs

Deferred Electric Service Costs, which relate only to ACE, decreased by $136 million, the result of a reduction of expenses of $116 million in 2009 as compared to an increase in expenses of $20 million in 2008. The decrease was primarily due to:

• A decrease of $171 million due to a lower rate of recovery of costs from energy and capacity purchased under the NUG contracts.

The decrease was partially offset by:

• An increase of $17 million due to a higher rate of recovery of deferred energy costs.

• An increase of $14 million due to a higher rate of recovery of New Jersey Societal Benefit program costs.

• An increase of $4 million due to a higher rate of recovery of deferred transmission costs.

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

Effect of Settlement of Mirant Bankruptcy Claims

In September 2008, Pepco transferred the Panda PPA to an unaffiliated third party. In March 2009, the 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 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 three months ended September 30, 2009, reflecting the Maryland proceeds retained by Pepco.

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Gain on Sale of Assets

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

Other Income (Expenses)

Other Expenses (which are net of Other Income) increased by $45 million to a net expense of $263 million in 2009 from a net expense of $218 million in 2008. The increase was primarily due to a $35 million increase in interest expense on long-term debt as the result of a higher amount of outstanding debt.

Income Tax Expense

PHI’s effective tax rates for the nine months ended September 30, 2009 and 2008 were 34.5% and 40.8%, respectively. The decrease in the rate primarily resulted from a refund of $6 million (after tax) of state income taxes and the establishment of a state tax benefit carryforward of $7 million (after tax), each related to a change in the tax reporting for the disposition of certain assets in prior years, and lower permanent and state income tax benefits in 2008 related to the charge taken in the second quarter of 2008 on the cross-border energy lease investments as described in Note (7), “Leasing Activities.”

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, 2009, Pepco Holdings’ current assets on a consolidated basis totaled $2.0 billion and its current liabilities totaled $2.2 billion. At December 31, 2008, Pepco Holdings’ current assets totaled $2.6 billion and its current liabilities totaled $2.0 billion. The decrease in working capital from December 31, 2008 to September 30, 2009 is primarily due to a $300 million pension plan contribution and an increase in the current maturities of long-term debt.

At September 30, 2009, Pepco Holdings’ cash and current cash equivalents totaled $20 million of which $7 million was invested in money market funds that invest in U.S. Treasury obligations, and the balance was held as cash and uncollected funds. Current restricted cash (cash that is available to be used only for designated purposes) totaled $11 million. At December 31, 2008, Pepco Holdings’ cash and current cash equivalents totaled $384 million and its current restricted cash totaled $10 million. See “Capital Requirements – Contractual Arrangements with Credit Rating Triggers or Margining Rights” herein for additional information.

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

	As of September 30, 2009
Type	PHI Parent		Pepco		DPL		ACE		ACE Funding		Conectiv Energy		Pepco Energy Services		PCI		Conectiv		PHI Consolidated
	(millions of dollars)
Variable Rate Demand Bonds	$	—	$	—	$	105	$	23	$	—	$	—	$	21	$	—	$	—	$	149
Commercial Paper		204		—		—		40		—		—		—		—		—		244
Credit Facility Loans		100		—		—		—		—		—		—		—		—		100
Total Short-Term Debt	$	304	$	—	$	105	$	63	$	—	$	—	$	21	$	—	$	—	$	493
Current Maturities of Long-Term Debt and Project Funding	$	450	$	16	$	31	$	1	$	33	$	—	$	3	$	—	$	—	$	534

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

Financing Activity During the Three Months Ended September 30, 2009

PHI and its utility subsidiaries historically have issued commercial paper as required to meet their short-term working capital requirements. As a result of continuing disruptions in the commercial paper market, the companies have borrowed under the $1.5 billion credit facility. At September 30, 2009, PHI had an outstanding loan of $100 million under the credit facility.

In July 2009, Atlantic City Electric Transition Funding LLC (ACE Funding) made principal payments of $5.2 million on Series 2002-1 Bonds, Class A-2, $1.4 million on Series 2003-1 Bonds, Class A-1, and $.7 million on Series 2003-1 Bonds, Class A-2.

In July 2009, DPL repaid, at maturity, the remaining $100 million of a short-term loan in the original amount of $150 million.

In July 2009, PHI’s utility subsidiaries entered into a $30 million line of credit that can be used by these entities for equipment leasing through July 2010.

In July 2009, DPL redeemed $15 million of Series 2003A and $18.2 million of Series 2003B Exempt Facilities Refunding Revenue Bonds issued for the benefit of DPL by The Delaware Economic Development Authority. These tax-exempt bonds were purchased by DPL in 2008 due to the disruptions in the tax-exempt capital markets.

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In July 2009, ACE redeemed $25 million of Series 2004A and $6.5 million of Series 2004B Pollution Control Revenue Refunding Bonds issued for the benefit of ACE by the Pollution Control Financing Authority of Cape May County (collectively, the Cape May Bonds). The Cape May Bonds were purchased by ACE in 2008 due to the disruptions in the tax-exempt capital markets. The Cape May Bonds were insured by bond insurance policies purchased by ACE. At the time of the issuance of the Cape May Bonds, ACE issued to the bond insurer, as security for its reimbursement obligations under the bond insurance policies, a series of senior notes having terms substantially identical to the terms of the respective series of Cape May Bonds. ACE’s obligations under the senior notes were, in turn, secured by a corresponding series of collateral first mortgage bonds issued by ACE under its Mortgage and Deed of Trust. Upon the redemption of the Cape May Bonds, the corresponding series of senior notes and first mortgage bonds were likewise redeemed.

In September 2009, DPL issued $165.5 million of collateral first mortgage bonds in order to secure its reimbursement obligations under bond insurance policies insuring the principal and interest payments on a series of previously issued DPL notes and two series of pollution control bonds previously issued for the benefit of DPL. DPL did not receive any cash proceeds from the issuance of the collateral first mortgage bonds. The payment by DPL of its principal and interest obligations in respect of the DPL notes and the pollution control bonds satisfies the corresponding payment obligations on collateral first mortgage bonds, and accordingly DPL’s outstanding debt did not increase as a result of these transactions.

Financing Activity Subsequent to September 30, 2009

In October 2009, ACE Funding made principal payments of $7 million on Series 2002-1 Bonds, Class A-2, and $2.7 million on Series 2003-1 Bonds, Class A-2.

In October 2009, PHI amended its $400 million unsecured credit facility to extend the termination date to October 15, 2010, as more fully discussed below under the heading, “Credit Facilities.”

Credit Facilities

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

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

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

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.

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In November 2008, PHI entered into a second unsecured credit facility in the amount of $400 million with a syndicate of nine lenders, which was amended and restated in October 2009, to extend the facility termination date to October 15, 2010. Under this facility, PHI may obtain revolving loans and swingline loans over the term of the facility. The facility does not provide for the issuance of letters of credit. The interest rate payable on funds borrowed under the facility is, at PHI’s election, based on either (a) the prevailing Eurodollar rate or (b) the highest of (i) the prevailing prime rate, (ii) the federal funds effective rate plus 0.5% or (iii) the one-month Eurodollar rate plus 1.0%, plus a margin that varies according to the credit rating of PHI. Under the swingline loan sub-facility, PHI may obtain loans for up to seven days in an aggregate principal amount which does not exceed 10% of the aggregate borrowing limit under the facility. In order to obtain loans under the facility, PHI must be in compliance with the same covenants and conditions that it is required to satisfy for utilization of the $1.5 billion primary credit facility. The absence of a material adverse change in PHI’s business, property, and results of operations or financial condition is not a condition to the availability of credit under the facility. The facility does not include any ratings triggers. These two facilities are referred to herein collectively as PHI’s “primary credit facilities.” As of September 30, 2009, each borrower was in compliance with the covenants of each of the primary credit facilities.

Cash and Credit Facilities Available as of September 30, 2009

	Consolidated PHI			PHI Parent			Utility Subsidiaries
	(millions of dollars)
Credit Facilities (Total Capacity)	$	1,950		$	1,325		$	625
Borrowings under Credit Facilities		(100	)		(100	)		—
Letters of Credit		(210	)		(205	)		(5	)
Commercial Paper Outstanding		(244	)		(204	)		(40	)
Remaining Credit Facilities Available		1,396			816			580
Cash Invested in Money Market Funds (a)		7			6			1
Total Cash and Credit Facilities Available	$	1,403		$	822		$	581

(a) Cash and cash equivalents reported on the Balance Sheet total $20 million, which includes the $7 million invested in money market funds and $13 million held in cash and uncollected funds.

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

• In March 2009, Pepco resold $110 million of its Pollution Control Revenue Refunding Bonds, which previously had been issued for the benefit of Pepco by the Maryland Economic Development Corporation.

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

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

• In October 2009, PHI amended its $400 million unsecured credit facility to extend the facility termination date to October 15, 2010.

At September 30, 2009, the amount of cash, plus borrowing capacity under PHI’s primary credit facilities available to meet the future liquidity needs of PHI and its utility subsidiaries on a consolidated basis totaled $1.4 billion, of which $581 million consisted of the combined cash and borrowing capacity under the $1.5 billion credit facility of PHI’s utility subsidiaries in the aggregate. At December 31, 2008, the amount of cash, plus borrowing capacity under PHI’s primary credit facilities available to meet the liquidity needs of PHI on a consolidated basis totaled $1.5 billion, of which $843 million consisted of the combined cash and borrowing capacity under the $1.5 billion credit facility on PHI’s utility subsidaries in the aggregate.

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Collateral Requirements of the Competitive Energy Business

In conducting its retail energy supply business, Pepco Energy Services, during periods of declining energy prices, has been exposed to the asymmetrical risk of having to post collateral under its wholesale purchase contracts without receiving a corresponding amount of collateral from its retail customers. To partially address these asymmetrical collateral obligations, Pepco Energy Services, in the first quarter of 2009, entered into a credit intermediation arrangement with Morgan Stanley Capital Group, Inc. (MSCG). Under this arrangement, MSCG, in consideration for the payment to MSCG of certain fees, (i) has assumed by novation the electricity purchase obligations of Pepco Energy Services in years 2009 through 2011 under several wholesale purchase contracts and (ii) has agreed to supply electricity to Pepco Energy Services on the same terms as the novated transactions, but without imposing on Pepco Energy Services any associated collateral obligations. As of September 30, 2009, approximately 24% of Pepco Energy Services’ wholesale electricity purchase obligations (measured in megawatt hours) were covered by this credit intermediation arrangement with MSCG. The fees incurred by Pepco Energy Services in the amount of $25 million are being amortized into expense in declining amounts over the life of the arrangement based on the fair value of the underlying contracts at the time of the novation. For the three and nine months ended September 30, 2009, approximately $4 million and $12 million, respectively, of the fees have been amortized.

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

Depending on the contract terms, the collateral required to be posted by Pepco Energy Services and Conectiv Energy can be of varying forms, including cash and letters of credit. As of September 30, 2009, Pepco Energy Services and Conectiv Energy had posted net cash collateral of $131 million and $214 million, respectively, and letters of credit of $186 million and $16 million, respectively. At December 31, 2008, Pepco Energy Services and Conectiv Energy had posted net cash collateral of $125 million and $206 million, respectively, and letters of credit of $474 million and $84 million, respectively.

At September 30, 2009, the amount of cash, plus borrowing capacity under PHI’s primary credit facilities available to meet the future liquidity needs of the Competitive Energy business totaled $822 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 increased plan funding requirements.

Based on the results of the 2009 actuarial valuation, which was completed in the second quarter of 2009, PHI expects that its net periodic pension and other postretirement benefit costs will be approximately $149 million in 2009 versus $65 million in 2008. The utility subsidiaries are generally responsible for approximately 80% to 85% of the total PHI net periodic pension and other postretirement benefit costs. Approximately 30% of net periodic pension and other postretirement benefit costs are capitalized. PHI currently estimates that its net periodic pension and other postretirement benefit expense will be approximately $101 million in 2009, as compared to $45 million in 2008. For the three months ended September 30, 2009 and 2008, PHI’s pension and other postretirement benefit expense was $24 million and $11 million, respectively. For the nine months ended September 30, 2009 and 2008, PHI’s pension and other postretirement benefit expense was $76 million and $33 million, respectively.

During 2009, PHI has made discretionary tax-deductible contributions totaling $300 million to PHI’s noncontributory retirement plan which are expected to bring plan assets to at least the funding target level for 2009 under the Pension Protection Act. Of this amount, $240 million was contributed through tax-deductible contributions from Pepco, ACE and DPL in the amounts of $170 million, $60 million and $10 million, respectively. The remaining $60 million contribution was made through tax-deductible contributions from the PHI Service Company.

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Cash Flow Activity

PHI’s cash flows for the nine months ended September 30, 2009 and 2008 are summarized below:

	Cash (Use) Source
	2009			2008
	(millions of dollars)
Operating Activities	$	308		$	469
Investing Activities		(590	)		(538	)
Financing Activities		(82	)		241
Net (decrease) increase in cash and cash equivalents	$	(364	)	$	172

Operating Activities

Cash flows from operating activities during the nine months ended September 30, 2009 and 2008 are summarized below:

	Cash Source
	2009			2008
	(millions of dollars)
Net Income	$	194		$	233
Non-cash adjustments to net income		270			330
Pension contributions		(300	)		—
Changes in cash collateral related to derivative activities		4			(88	)
Changes in other assets and liabilities		140			(6	)
Net cash from operating activities	$	308		$	469

Net cash from operating activities was $161 million lower for the nine months ended September 30, 2009, compared to the same period in 2008. A portion of this decrease is attributable to the year-over-year decrease in net income after adjusting for non-cash items (including a non-cash charge taken in 2008 on the cross-border energy lease investments described in the “Earnings Overview” section above). In addition, pension plan contributions of $300 million were made during the nine months ended September 30, 2009, whereas no pension plan contributions were made during the nine months ended September 30, 2008. Also, there was 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. Offsetting these decreases was the release from restricted cash of $102 million related to the Mirant settlement (previously discussed in the “Earnings Overview” section above).

In October 2009, PHI filed a claim with the IRS requesting a Federal income tax refund of approximately $138 million, a substantial portion of which is associated with PHI’s utility subsidiaries. The refund results from the carry back of a 2008 net operating loss for tax reporting purposes that reflected, among other things, significant tax deductions related to accelerated depreciation, the pension plan contributions paid in 2009 (which were deductible for 2008) and the cumulative effect of adopting a new method of tax reporting for certain repairs. The timing of receipt of the refund is uncertain, however, after a 45-day period, interest would begin to accrue on the amount of the refund.

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Investing Activities

Cash flows from investing activities during the nine months ended September 30, 2009 and 2008 are summarized below:

	Cash Use
	2009			2008
	(millions of dollars)
Construction expenditures	$	(595	)	$	(561	)
Cash proceeds from sale of assets		4			52
All other investing cash flows, net		1			(29	)
Net cash used by investing activities	$	(590	)	$	(538	)

Net cash used by investing activities increased $52 million for the nine months ended September 30, 2009 compared to the same period in 2008. The change is a result of a $58 million increase in Conectiv Energy capital expenditures due to the construction of new generating facilities offset by lower capital expenditures by Power Delivery and Pepco Energy Services. Cash proceeds from the sale of assets in 2008 consisted of $51 million received from DPL’s sale of its retail electric distribution assets and its wholesale electric transmission assets in Virginia.

Financing Activities

Cash flows from financing activities during the nine months ended September 30, 2009 and 2008 are summarized below:

	Cash (Use) Source
	2009			2008
	(millions of dollars)
Dividends paid on common and preferred stock	$	(178	)	$	(163	)
Common stock issued under the Shareholder Dividend Reinvestment Plan		23			25
Issuance of common stock		14			15
Issuances of long-term debt		110			400
Reacquisition of long-term debt		(75	)		(438	)
Issuances of short-term debt, net		28			441
All other financing cash flows, net		(4	)		(39	)
Net cash (used) provided by financing activities	$	(82	)	$	241

Net cash from financing activities decreased $323 million for the nine months ended September 30, 2009, compared to the same period in 2008, principally due to the 2008 borrowings under the $1.5 billion credit facility.

Common Stock Dividends

Common stock dividend payments were $178 million and $163 million for the nine months ended September 30, 2009 and 2008, respectively. The increase in common dividends paid in 2009 was the result of additional shares outstanding, primarily from PHI’s sale of 16.1 million shares of common stock in November 2008.

Changes in Outstanding Common Stock

Proceeds from the issuance of stock decreased by $3 million due to lower stock prices in 2009 as compared to 2008, which more than offset an increase in the number of shares issued. Under the Long-Term Incentive Plan, PHI issued 171,279 shares of common stock during the nine months ended September 30, 2009, and 548,216 shares of common stock during the nine months ended September 30, 2008. Under PHI’s Shareholder Dividend Reinvestment Plan, 1,685,873 shares of common stock were issued during the nine months ended September 30, 2009 and 881,443 were issued during the nine months ended September 30, 2008.

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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, 2009 and for the nine months ended September 30, 2008 are summarized in the charts below:

	2009		2008
Issuances	(millions of dollars)
Pepco
6.5% Senior notes due 2037 (a)	$	—	$	250
6.2% Tax-exempt bonds due 2022 (b)		110		—
		110		250
DPL
Unsecured two-year bank loan		—		150
Total issuances of long-term debt	$	110	$	400

(a) Secured by an outstanding series of collateral first mortgage bonds issued by Pepco that has a maturity date, optional redemption provisions, interest rate and interest payment dates that are identical to the terms of the senior notes. Payments of principal and interest on the senior notes satisfy the corresponding payment obligations on the first mortgage bonds.

(b) Consists of Pollution Control Revenue Refunding Bonds (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 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 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 Bonds. The payment by Pepco of its obligations in respect of the Bonds satisfies the corresponding payment obligations on the senior notes and first mortgage bonds.

	2009		2008
Reacquisitions	(millions of dollars)
Pepco
6.5% First mortgage bonds due 2008	$	—	$	78
Auction rate, tax-exempt bonds due 2022 (a)		—		110
6.25% Medium-term notes		50		—
		50		188
DPL
6.95% First mortgage bonds due 2008		—		4
Auction rate, tax-exempt bonds (b)		—		58
Auction rate, tax-exempt bonds due 2023 (b)		—		18
Auction rate, tax-exempt bonds due 2030-2031 (b)		—		36
		—		116
ACE
6.79% Medium-term notes due 2008		—		15
Auction rate, tax-exempt bonds (b)		—		25
Auction rate, tax-exempt bonds due 2029 (b)		—		30
6.77% Medium-term notes due 2008		—		1
Securitization bonds due 2008-2009		23		21
6.73% - 6.75% Medium-term notes due 2008		—		25
6.71% - 6.73% Medium-term notes due 2008		—		9
		23		126
Pepco Energy Services		2		8
Total reacquisition of long-term debt	$	75	$	438

(a) Consists of Pollution Control Revenue Refunding Bonds (Bonds) issued by the Maryland Economic Development Corporation for the benefit of Pepco. Upon the purchase of the Bonds, Pepco’s obligations in respect of the Bonds were considered extinguished for accounting purposes. The Bonds were resold by Pepco to the public in March 2009.

(b) Consists of tax-exempt bonds issued for the benefit of the indicated company, which were held by such company pending resale to the public or redemption by the company.

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Changes in Short-Term Debt

Cash flows from the issuance of short-term debt has decreased during the nine months ended September 30, 2009 as compared to the nine months ended September 30, 2008, primarily due to the 2008 borrowings under the $1.5 billion credit facility. During September 2008, PHI borrowed $200 million, Pepco borrowed $100 million and ACE borrowed $135 million. As of September 30, 2009, PHI only has $100 million that remains outstanding under the $1.5 billion credit facility.

Sale of Virginia Retail Electric Distribution and Wholesale Transmission Assets

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

Proceeds from Settlement of Mirant Bankruptcy Claims

In 2000, Pepco sold substantially all of its electricity generating assets to Mirant. As part of the sale, Pepco and Mirant entered into a “back-to-back” arrangement, whereby Mirant agreed to purchase from Pepco the 230 megawatts of electricity and capacity that Pepco was obligated to purchase annually through 2021 from Panda under the Panda PPA at the purchase price Pepco was obligated to pay to Panda. In 2003, Mirant commenced a voluntary bankruptcy proceeding in which it sought to reject certain obligations that it had undertaken in connection with the asset sale. As part of the settlement of Pepco’s claims against Mirant arising from the bankruptcy, Pepco agreed not to contest the rejection by Mirant of its obligations under the “back-to-back” arrangement in exchange for the payment by Mirant of damages corresponding to the estimated amount by which the purchase price that Pepco was obligated to pay Panda for the energy and capacity exceeded the market price. In 2007, Pepco received as damages $414 million in net proceeds from the sale of shares of Mirant common stock issued to it by Mirant. In September 2008, Pepco transferred the Panda PPA to Sempra Energy Trading LLC (Sempra), along with a payment to Sempra, thereby terminating all further rights, obligations and liabilities of Pepco under the Panda PPA. In March 2009, the DCPSC issued an order approving Pepco’s sharing proposal for the District of Columbia under which approximately $24 million was distributed to District of Columbia customers as a one-time billing credit. As a result of this decision, Pepco recorded a pre-tax gain of approximately $14 million for the quarter ended March 31, 2009. On July 2, 2009, the MPSC approved a settlement agreement among Pepco, the Maryland Office of People’s Counsel and the MPSC staff under which Pepco distributed approximately $39 million to Maryland customers during the billing month of August 2009 through a one-time billing credit. As a result of this decision, Pepco recorded a pre-tax gain of approximately $26 million in the quarter ended September 30, 2009. The final resolution of this matter allowed for the release of $64 million previously accounted for as restricted cash and the extinguishment of the corresponding regulatory liability.

Capital Requirements

Capital Expenditures

Pepco Holdings’ total capital expenditures for the nine months ended September 30, 2009 totaled $595 million, of which $196 million was incurred by Pepco, $125 million was incurred by DPL, $98 million was incurred by ACE, $148 million was incurred by Conectiv Energy and $8 million was incurred by Pepco Energy Services. The remainder was incurred primarily by the PHI Service Company. The Power Delivery expenditures were primarily related to capital costs associated with new customer services, distribution reliability, and transmission.

Due to a reduced near-term load forecast for the region, PJM recommended a one-year delay for the Mid-Atlantic Power Pathway’s (MAPP) in-service date. Based on these changes by PJM, PHI has updated the projected capital expenditures for the Power Delivery segment as presented in PHI’s Form 10-K for the year ended December 31, 2008. The following table shows the updated projected capital expenditures on a combined basis for the five-year period 2009-2013. Pepco Holdings expects to fund these expenditures through internally generated cash and external financing.

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	For the Year
	2009		2010		2011		2012		2013		Total
	(millions of dollars)
Power Delivery
Distribution	$	427	$	416	$	433	$	496	$	532	$	2,304
Distribution - Blueprint for the Future		49		71		5		112		87		324
Transmission		135		183		249		200		204		971
Transmission - MAPP		56		136		295		317		233		1,037
Gas Delivery		21		21		20		21		19		102
Other		39		52		61		57		38		247
Total for Power Delivery Business		727		879		1,063		1,203		1,113		4,985
Conectiv Energy		281		118		39		12		13		463
Pepco Energy Services		11		12		14		15		15		67
Corporate and Other		5		4		4		4		3		20
Total PHI	$	1,024	$	1,013	$	1,120	$	1,234	$	1,144	$	5,535

Stimulus Funds Related to Blueprint for the Future

On October 27, 2009, PHI was informed by the U.S. Department of Energy (DOE) that, subject to final negotiations, two of its subsidiaries were awarded $168 million in federal stimulus funds to help build an integrated smart grid, a key aspect of PHI’s Blueprint for the Future initiative. The awards are intended to be used to help offset projected Blueprint for the Future capital expenditures of Pepco in the District of Columbia and Maryland, and ACE in New Jersey.

MAPP Project

In October 2007, the PJM Board of Managers approved PHI’s proposed MAPP transmission project for construction of a new 230-mile, 500-kilovolt interstate transmission project at a then-estimated cost of $1 billion. This MAPP project is part of PJM’s Regional Transmission Expansion Plan required to address the reliability objectives of the PJM RTO system. At that time, the MAPP project was to originate at Possum Point substation in northern Virginia, connect into three substations across southern Maryland, cross the Chesapeake Bay, tie into two substations across the Delmarva Peninsula and terminate at Salem substation in southern New Jersey. On December 4, 2008, the PJM Board approved a direct-current technology for segments of the project including the Chesapeake Bay Crossing. On May 20, 2009, the PJM Board revised its Regional Transmission Expansion Plan as a result of updating its load forecast for the region. PJM determined that the line segment from Possum Point substation to the second substation on the Delmarva Peninsula (Indian River substation) is now required to be operational by June 1, 2014 and the Indian River to Salem portion of the MAPP project was not required at the present time. With these modifications, the cost of the MAPP project currently is estimated at $1.2 billion. PJM will continue to evaluate the need for the Indian River to Salem line in a future planning period.

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

For a discussion of PHI’s third party guarantees, indemnifications, obligations and off-balance sheet arrangements, see Note (14) ”Commitments and Contingencies,” to the consolidated financial statements of PHI included as Part I, Item 1, in this Form 10-Q.

Dividends

On October 22, 2009, Pepco Holdings’ Board of Directors declared a dividend on common stock of 27 cents per share payable December 31, 2009, to shareholders of record on December 10, 2009.

Energy Contract Net Asset Activity

The following table provides detail on changes in the net asset or liability position of the Competitive Energy business (consisting of the activities of the Conectiv Energy and Pepco Energy Services segments) with respect to energy commodity contracts for the nine months ended September 30, 2009. The balances reflected in the table are stated gross, pre-tax and before the netting of collateral as required by FASB guidance on the offsetting of balance sheet accounts (ASC 210-20).

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	Energy Commodity Activities (a)
	(millions of dollars)
Total Fair Value of Energy Contract Net Liabilities at December 31, 2008	$	(314	)
Current period unrealized losses		(16	)
Effective portion of changes in fair value - recorded in Accumulated Other Comprehensive Loss		(292	)
Cash flow hedge ineffectiveness - recorded in income		(1	)
Recognition of realized gains (losses) on settlement of contracts		266
Total Fair Value of Energy Contract Net Liabilities at September 30, 2009	$	(357	)
	Total
Detail of Fair Value of Energy Contract Net Liabilities at September 30, 2009 (see above)
Derivative assets (current assets)	$	33
Derivative assets (non-current assets)		33
Total Fair Value of Energy Contract Assets		66
Derivative liabilities (current liabilities)		(323	)
Derivative liabilities (non-current liabilities)		(100	)
Total Fair Value of Energy Contract Liabilities		(423	)
Total Fair Value of Energy Contract Net Liabilities	$	(357	)

Notes:

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

The $357 million net liability on energy contracts at September 30, 2009 was primarily attributable to losses on power swaps and natural gas futures and swaps designated as hedges of future energy purchases or production under FASB guidance on derivatives and hedging (ASC 815). Prices of electricity and natural gas declined during the first three quarters of 2009, which resulted in unrealized losses on the energy contracts of the Competitive Energy business. Competitive Energy recorded unrealized losses of $292 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.

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, 2009 and are subject to change as a result of changes in these factors:

	Fair Value of Contracts at September 30, 2009 Maturities
Source of Fair Value	2009			2010			2011			2012 and Beyond			Total Fair Value
	(millions of dollars)
Energy Commodity Activities, net (a)
Actively Quoted (i.e., exchange-traded) prices	$	(26	)	$	(84	)	$	(11	)	$	(1	)	$	(122	)
Prices provided by other external sources (b)		(65	)		(140	)		(35	)		(17	)		(257	)
Modeled (c)		2			4			4			12			22
Total	$	(89	)	$	(220	)	$	(42	)	$	(6	)	$	(357	)

Notes:

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

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

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

Contractual Arrangements with Credit Rating Triggers or Margining Rights

Under certain contractual arrangements entered into by PHI’s subsidiaries in connection with the Competitive Energy business and other transactions, the subsidiary may be required to provide cash collateral or letters of credit as security for its contractual obligations if the credit ratings of the subsidiary are downgraded. In the event of a downgrade, the amount required to be posted would depend on the amount of the underlying contractual obligation existing at the time of the downgrade. Based on contractual provisions in effect at September 30, 2009, a one-level downgrade in the unsecured debt credit ratings of PHI and each of its rated subsidiaries, which would decrease PHI’s rating to below “investment grade,” would increase the collateral obligation of PHI and its subsidiaries by up to $487 million, $255 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 $232 million of the collateral obligation that would be incurred in the event PHI was downgraded to below investment grade is attributable primarily to energy services contracts and accounts payable to independent system operators and distribution companies on full requirements contracts entered into by Pepco Energy Services. PHI believes that it and its utility subsidiaries currently have sufficient liquidity to fund their operations and meet their financial obligations.

Many of the contractual arrangements entered into by PHI’s subsidiaries in connection with Competitive Energy and Default Electricity Supply activities include margining rights pursuant to which the PHI subsidiary or a counterparty may request collateral if the market value of the contractual obligations reaches levels in excess of the credit thresholds established in the applicable arrangements. Pursuant to these margining rights, the affected PHI subsidiary may receive, or be required to post, collateral due to energy price movements. As of September 30, 2009, Pepco Holdings’ subsidiaries engaged in Competitive Energy activities and Default Electricity Supply activities provided net cash collateral in the amount of $361 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, 2008. There have been no material changes to PHI’s critical accounting policies as disclosed in the Form 10-K, except that the following critical accounting policy supersedes the critical accounting policy with the same heading in the Form 10-K:

Goodwill Impairment Evaluation

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

Substantially all of PHI’s goodwill was generated by Pepco’s acquisition of Conectiv in 2002 and is allocated to the Power Delivery reporting unit for purposes of assessing impairment under FASB guidance on goodwill and other intangibles (ASC 350). Management has identified Power Delivery as a single reporting unit based on the aggregation of components. The first step of the goodwill impairment test compares the fair value of the reporting unit with its carrying amount, including goodwill. Management uses its best judgment to make reasonable projections of future cash flows for Power Delivery when estimating the reporting unit’s fair value. In addition, PHI selects a discount rate for the associated

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risk with those estimated cash flows. These judgments are inherently uncertain, and actual results could vary from those used in PHI’s estimates. The impact of such variations could significantly alter the results of a goodwill impairment test, which could materially impact the estimated fair value of Power Delivery and potentially the amount of any impairment recorded in the financial statements.

PHI has tested its goodwill for impairment annually as of July 1 from 2002 to 2009, and on an interim basis whenever an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. After completion of the July 1, 2009 test, PHI changed the date of its annual test to November 1, and accordingly PHI will perform its next annual impairment test as of November 1, 2009. Factors that may result in an interim impairment test include, but are not limited to: a change in identified reporting units; an adverse change in business conditions; a protracted decline in stock price causing market capitalization to fall below book value; an adverse regulatory action; or impairment of long-lived assets in the reporting unit.

PHI’s July 1, 2009 annual impairment test indicated that its goodwill was not impaired. See Note (6), “Goodwill,” to the consolidated financial statements of Pepco Holdings, set forth in Part I, Item 1 of this Form 10-Q. PHI performed an interim test of goodwill for impairment as of March 31, 2009 which updated an interim test performed as of December 31, 2008 as its market capitalization was below its book value at both points in time and its market capitalization relative to book value had declined significantly from the December 31, 2008 market capitalization. PHI concluded that its goodwill was not impaired at either March 31, 2009 or December 31, 2008. Although PHI’s market capitalization remained below book value as of September 30, 2009, PHI did not perform an interim goodwill impairment test because its market capitalization relative to book value improved compared to earlier periods and there were no other indicators of potential impairment.

In order to estimate the fair value of the Power Delivery reporting unit, PHI reviews the results from two discounted cash flow models. The models differ in the method used to calculate the terminal value of the reporting unit. One model estimates terminal value based on a constant annual cash flow growth rate that is consistent with Power Delivery’s long-term view of the business, and the other model estimates terminal value based on a multiple of earnings before interest, taxes, depreciation, and amortization (EBITDA) that management believes is consistent with EBITDA multiples for comparable utilities. The models use a cost of capital appropriate for a regulated utility as the discount rate for the estimated cash flows associated with the reporting unit. PHI has consistently used this valuation model to estimate the fair value of Power Delivery.

The estimation of fair value is dependent on a number of factors that are sourced from the Power Delivery reporting unit’s business forecast, including but not limited to interest rates, growth assumptions, returns on rate base, operating and capital expenditure requirements, and other factors, changes in which could materially impact the results of impairment testing. Assumptions and methodologies used in the models were consistent with historical experience. A hypothetical 10 percent decrease in fair value of the Power Delivery reporting unit at July 1, 2009 would have resulted in the Power Delivery reporting unit failing the first step of the impairment test, as defined in the guidance, as the estimated fair value of the reporting unit would be below its carrying value by approximately $100 million. If this had occurred, PHI would have been required to perform the second step of the impairment test prescribed by the guidance. This step would have involved allocating the fair value of the Power Delivery reporting unit, as determined in the first step, to all of the assets and liabilities of the Power Delivery reporting unit based on their fair value to determine the implied fair value of goodwill. The fair value of the Power Delivery reporting unit in excess of the amount allocated to the fair value of the assets and liabilities in the reporting unit is the implied fair value of goodwill. An impairment charge must be recorded to the extent that the implied fair value of goodwill is less than the carrying value of goodwill. This impairment charge may be more or less than the amount by which the carrying value of the Power Delivery reporting unit exceeded its fair value as determined by the first step of the impairment test.

At March 31, 2009, a hypothetical 10 percent decrease in the estimate of the fair value would have resulted in the Power Delivery reporting unit failing the first step of the impairment test, as the estimated fair value of the reporting unit would be below its carrying value by approximately $150 million. At December 31, 2008, a hypothetical 10 percent decrease in the estimate of the fair value would not have resulted in the Power Delivery reporting unit failing the first step of the impairment test. The decrease in the estimated fair value of the Power Delivery reporting unit from December 31, 2008 to July 1, 2009 was primarily due to updates in the assumptions used to calculate cash flow from operations and market assumptions used to calculate fair value. Further deterioration of the market-related factors or significant changes in other

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impairment test variables could result in an impairment charge, which could be material. Sensitive, interrelated and uncertain variables that could decrease the estimated fair value of the Power Delivery reporting unit include utility sector market performance, sustained adverse business conditions, change in forecasted revenues, higher operating and capital expenditure requirements, a significant increase in the cost of capital, and other factors.

New Accounting Standards and Pronouncements

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

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Forward-Looking Statements

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

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

• Prevailing governmental policies and regulatory actions affecting the energy industry, including allowed rates of return, industry and rate structure, acquisition and disposal of assets and facilities, operation and construction of plant facilities, recovery of purchased power expenses, and present or prospective wholesale and retail competition;

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

• Weather conditions;

• Population growth rates and demographic patterns;

• Competition for retail and wholesale customers;

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

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

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

• Changes in accounting standards or practices;

• Changes in project costs;

• Unanticipated changes in operating expenses and capital expenditures;

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

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

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

• Pace of entry into new markets;

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

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

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

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

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

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

Potomac Electric Power Company

General Overview

Potomac Electric Power Company (Pepco) is engaged in the transmission and distribution of electricity in Washington, D.C. and major portions of Montgomery County and Prince George’s County in suburban Maryland. Pepco also provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its service territories who do not elect to purchase electricity from a competitive supplier. Default Electricity Supply is known as Standard Offer Service in both the District of Columbia and Maryland. Pepco’s service territory covers approximately 640 square miles and has a population of approximately 2.1 million. As of September 30, 2009, approximately 57% of delivered electricity sales were to Maryland customers and approximately 43% were to Washington, D.C. customers.

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

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

Results Of Operations

The following results of operations discussion compares the nine months ended September 30, 2009, to the nine months ended September 30, 2008. Other than this disclosure, information under this item has been omitted in accordance with General Instruction H to the Form 10-Q. All amounts in the tables (except sales and customers) are in millions of dollars.

Operating Revenue

	2009		2008		Change
Regulated T&D Electric Revenue	$	725	$	764	$	(39	)
Default Supply Revenue		993		1,002		(9	)
Other Electric Revenue		25		26		(1	)
Total Operating Revenue	$	1,743	$	1,792	$	(49	)

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

Regulated T&D Electric Revenue includes revenue from the delivery of electricity, including the delivery of Default Electricity Supply, to Pepco’s customers within its service territory at regulated rates. Regulated T&D Electric Revenue also includes transmission service revenue that Pepco receives as a transmission owner from PJM Interconnection, LLC (PJM).

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

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

Regulated T&D Electric

Regulated T&D Electric Revenue	2009		2008		Change
Residential	$	212	$	209	$	3
Commercial and industrial		435		423		12
Other		78		132		(54	)
Total Regulated T&D Electric Revenue	$	725	$	764	$	(39	)

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

Regulated T&D Electric Sales (Gigawatt hours (GWh))	2009	2008	Change
Residential	5,995	5,991	4
Commercial and industrial	14,229	14,441	(212	)
Other	114	114	—
Total Regulated T&D Electric Sales	20,338	20,546	(208	)
Regulated T&D Electric Customers (in thousands)	2009	2008	Change
Residential	695	688	7
Commercial and industrial	73	74	(1	)
Other	—	—	—
Total Regulated T&D Electric Customers	768	762	6

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

• A decrease of $53 million in Other Regulated T&D Electric Revenue (offset in Purchased Energy) due to the absence of revenues from the resale of energy and capacity purchased under the power purchase agreement between Panda-Brandywine, L.P. (Panda) and Pepco (the Panda PPA) as the result of the transfer of the Panda PPA to an unaffiliated third party in September 2008.

The decrease was partially offset by:

• An increase of $13 million due to higher pass-through revenue primarily resulting from tax rate changes (substantially offset in Other Taxes).

Default Electricity Supply

Default Supply Revenue	2009		2008		Change
Residential	$	670	$	615	$	55
Commercial and industrial		316		381		(65	)
Other		7		6		1
Total Default Supply Revenue	$	993	$	1,002	$	(9	)

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Default Electricity Supply Sales (GWh)	2009	2008	Change
Residential	5,623	5,665	(42	)
Commercial and industrial	2,996	3,150	(154	)
Other	7	6	1
Total Default Electricity Supply Sales	8,626	8,821	(195	)
Default Electricity Supply Customers (in thousands)	2009	2008	Change
Residential	652	655	(3	)
Commercial and industrial	50	53	(3	)
Other	—	—	—
Total Default Electricity Supply Customers	702	708	(6	)

Default Supply Revenue, which is substantially offset in Purchased Energy, decreased by $9 million primarily due to:

• A decrease of $20 million due to lower sales, primarily the result of commercial customer migration to competitive suppliers.

• A decrease of $11 million due to lower sales as a result of milder weather during the 2009 summer months as compared to 2008.

The aggregate amount of these decreases was partially offset by:

• An increase of $21 million as the result of higher Default Electricity Supply rates.

The following table shows the percentages of Pepco’s total distribution sales by jurisdiction that are derived from customers receiving Default Electricity Supply from Pepco. Amounts are for the nine months ended September 30.

	2009		2008
Sales to District of Columbia customers	33	%	33	%
Sales to Maryland customers	50	%	50	%

Operating Expenses

Purchased Energy

Purchased Energy, which is primarily associated with Default Electricity Supply sales, decreased by $61 million to $972 million in 2009 from $1,033 million in 2008. The decrease was primarily due to the following:

• A decrease of $53 million due to the transfer of the Panda PPA.

• A decrease of $32 million due to lower average electricity costs under new Default Electricity Supply contracts.

• A decrease of $17 million primarily due to commercial customer migration to competitive suppliers.

• A decrease of $10 million due to lower electricity sales as a result of milder weather during the 2009 summer months as compared to 2008.

The aggregate amount of these decreases was partially offset by:

• An increase of $51 million due to a higher rate of recovery of electric supply costs resulting in a change in the Default Electricity Supply deferral balance.

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

Other Operation and Maintenance

Other Operation and Maintenance increased by $17 million to $244 million in 2009 from $227 million in 2008. The increase was primarily due to the following:

• An increase of $11 million in employee-related costs, primarily due to higher pension and other postretirement benefit expenses.

• An increase of $4 million in regulatory expenses primarily incurred in connection with the District of Columbia distribution rate case.

• An increase of $4 million due to higher non-deferrable bad debt expenses.

In the second quarter of 2008, Pepco recorded an adjustment to correct errors in Other Operation and Maintenance expenses for prior periods dating back to February 2005 for which late payment fees were incorrectly recognized. This adjustment resulted in an increase in Other Operation and Maintenance expenses for the nine months ended September 30, 2008 of $3 million. In the third quarter of 2008, PHI identified an error in the accounting for certain of its restricted stock awards granted under the Long-Term Incentive Plan which resulted in an understatement of Pepco’s stock-based compensation expense in 2006 and 2007. This error was corrected in the third quarter of 2008, resulting in an increase in Pepco’s Other Operation and Maintenance expenses for the nine months ended September 30, 2008 of $3 million. These adjustments were not considered material either individually or in the aggregate.

Other Taxes

Other Taxes increased by $11 million to $230 million in 2009 from $219 million in 2008. The increase was primarily due to increased pass-throughs resulting from tax rate changes (substantially offset in Regulated T&D Electric Revenue).

Effect of Settlement of Mirant Bankruptcy Claims

In September 2008, Pepco transferred the Panda PPA to an unaffiliated third party. In March 2009, the District of Columbia Public Service Commission approved an allocation between Pepco and its District of Columbia customers of the District of Columbia portion of the Mirant Corporation (Mirant) bankruptcy settlement proceeds remaining after the transfer of the Panda PPA. As a result, Pepco recorded a pre-tax gain of $14 million reflecting the District of Columbia proceeds retained by Pepco. In July 2009, 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 three months ended September 30, 2009, reflecting the Maryland proceeds retained by Pepco.

Other Income (Expenses)

Other Expenses (which are net of Other Income) increased by $10 million to a net expense of $68 million in 2009 from a net expense of $58 million in 2008. The increase was primarily due to a $15 million increase in interest expense on long-term debt as the result of a higher amount of outstanding debt.

Income Tax Expense

Pepco’s effective tax rates for the nine months ended September 30, 2009 and 2008 were 41.6% and 39.1%, respectively. The increase in the rate primarily resulted from the change in estimates and interest related to uncertain tax positions which was the result of the reduction in previously accrued interest and estimates resulting from the settlement of the mixed service cost issue. Also contributing to the increase in the rate was the 2008 benefit recorded for interest received on the state income tax refund.

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Capital Requirements

Liquidity

The disruptions in the capital and credit markets, combined with the volatility of energy prices, had an impact on the borrowing capacity and liquidity of Pepco. Since the third quarter of 2008, to address the challenges posed by the current capital and credit market environment and to ensure that Pepco will continue to have sufficient access to cash to meet its liquidity needs, Pepco has taken several measures to reduce expenditures, issued $250 million of 6.5% senior notes due in 2037 and resold $110 million of Pollution Control Revenue Refunding Bonds previously issued for the benefit of Pepco by the Maryland Economic Development Corporation, which Pepco purchased in 2008.

Capital Expenditures

Pepco’s capital expenditures for the nine months ended September 30, 2009, totaled $196 million. These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission.

Due to a reduced near-term load forecast for the region, PJM recommended a one-year delay for the Mid-Atlantic Power Pathway’s (MAPP) in-service date. Based on this change by PJM, Pepco has updated its projected capital expenditures as presented in Pepco’s Form 10-K for the year ended December 31, 2008. The following table shows the updated projected capital expenditures for Pepco on a combined basis for the five-year period 2009-2013. Pepco expects to fund these expenditures through internally generated cash and from external financing and capital contributions from PHI.

	For the Year
	2009		2010		2011		2012		2013		Total
	(millions of dollars)
Pepco
Distribution	$	209	$	207	$	221	$	267	$	302	$	1,206
Distribution - Blueprint for the Future		9		16		3		72		79		179
Transmission		45		112		157		94		49		457
Transmission - MAPP		46		100		141		150		60		497
Other		14		15		25		26		15		95
	$	323	$	450	$	547	$	609	$	505	$	2,434

Stimulus Funds Related to Blueprint for the Future

On October 27, 2009, Pepco was informed by the U.S. Department of Energy (DOE) that, subject to final negotiations, it was awarded $149 million in federal stimulus funds to help build an integrated smart grid, a key aspect of PHI’s Blueprint for the Future initiative. Pepco intends to use the award to help offset projected Blueprint for the Future capital expenditures in the District of Columbia and Maryland.

MAPP Project

In October 2007, the PJM Board of Managers approved PHI’s proposed MAPP transmission project for construction of a new 230-mile, 500-kilovolt interstate transmission project at a then-estimated cost of $1 billion. This MAPP project is part of PJM’s Regional Transmission Expansion Plan required to address the reliability objectives of the PJM RTO system. At that time, the MAPP project was to originate at Possum Point substation in northern Virginia, connect into three substations across southern Maryland, cross the Chesapeake Bay, tie into two substations across the Delmarva Peninsula and terminate at Salem substation in southern New Jersey. On December 4, 2008, the PJM Board approved a direct-current technology for segments of the project including the Chesapeake Bay Crossing. On May 20, 2009, the PJM Board revised its Regional Transmission Expansion Plan as a result of updating their load forecast for the region. PJM determined that the line segment from Possum Point substation to the second substation on the Delmarva Peninsula (Indian River substation) is now required to be operational by June 1, 2014 and the Indian River to Salem portion of the MAPP project was not required at the present time. With these modifications, the cost of the MAPP project currently is estimated at $1.2 billion. PJM will continue to evaluate the need for the Indian River to Salem line in a future planning period.

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PEPCO

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

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

• Weather conditions;

• Population growth rates and demographic patterns;

• Competition for retail and wholesale customers;

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

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

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

• Changes in accounting standards or practices;

• Changes in project costs;

• Unanticipated changes in operating expenses and capital expenditures;

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

• Rules and regulations imposed by federal and/or state regulatory commissions, PJM, the North American Electric Reliability Corporation and other applicable electric reliability organizations;

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

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

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

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

Any forward-looking statements speak only as to the date of this Quarterly Report and Pepco undertakes no obligation to update any forward-looking statements to reflect events or circumstances after the date on which such statements are made or to reflect the occurrence of 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.

147

DPL

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

Delmarva Power & Light Company

General Overview

Delmarva Power & Light Company (DPL) is engaged in the transmission and distribution of electricity in Delaware and portions of Maryland. DPL also provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its service territories who do not elect to purchase electricity from a competitive supplier. Default Electricity Supply is known as Standard Offer Service in both Delaware and Maryland. DPL’s electricity distribution service territory covers approximately 5,000 square miles and has a population of approximately 1.3 million. As of September 30, 2009, 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 January 2, 2008, DPL sold its Virginia retail electric distribution assets and its Virginia wholesale electric transmission assets.

In connection with its approval of new electric service distribution base rates for DPL in Maryland, effective in June 2007, the Maryland Public Service Commission approved a bill stabilization adjustment mechanism (BSA) for retail customers. For customers to which the BSA applies, DPL recognizes distribution revenue based on the approved distribution charge per customer. From a revenue recognition standpoint, this has the effect of decoupling distribution revenue recognized in a reporting period from the amount of power delivered during the period. As a consequence, the only factors that will cause distribution revenue in Maryland to fluctuate from period to period are changes in the number of customers and changes in the approved distribution charge per customer. For customers to which the BSA applies, changes in customer usage (such as due to weather conditions, energy prices, energy efficiency programs or other reasons) from period to period have no impact on reported revenue.

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

Results Of Operations

The following results of operations discussion compares the nine months ended September 30, 2009, to the nine months ended September 30, 2008. Other than this disclosure, information under this item has been omitted in accordance with General Instruction H to the Form 10-Q. All amounts in the tables (except sales and customers) are in millions of dollars.

Electric Operating Revenue

	2009		2008		Change
Regulated T&D Electric Revenue	$	259	$	266	$	(7	)
Default Supply Revenue		606		650		(44	)
Other Electric Revenue		18		16		2
Total Electric Operating Revenue	$	883	$	932	$	(49	)

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

Regulated T&D Electric Revenue includes revenue from the delivery of electricity, including the delivery of Default Electricity Supply, to DPL’s customers within its service territory at regulated rates. Regulated T&D Electric Revenue also includes transmission service revenue that DPL receives as a transmission owner from PJM Interconnection, LLC (PJM).

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DPL

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

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

Regulated T&D Electric

Regulated T&D Electric Revenue	2009		2008		Change
Residential	$	125	$	127	$	(2	)
Commercial and industrial		76		80		(4	)
Other		58		59		(1	)
Total Regulated T&D Electric Revenue	$	259	$	266	$	(7	)

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

Regulated T&D Electric Sales (Gigawatt hours (GWh))	2009	2008	Change
Residential	3,848	3,881	(33	)
Commercial and industrial	5,693	6,027	(334	)
Other	38	37	1
Total Regulated T&D Electric Sales	9,579	9,945	(366	)
Regulated T&D Electric Customers (in thousands)	2009	2008	Change
Residential	438	437	1
Commercial and industrial	59	59	—
Other	1	1	—
Total Regulated T&D Electric Customers	498	497	1

Regulated T&D Electric Revenue decreased by $7 million primarily due to lower non-weather related customer usage.

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

Default Electricity Supply

Default Supply Revenue	2009		2008		Change
Residential	$	434	$	424	$	10
Commercial and industrial		166		219		(53	)
Other		6		7		(1	)
Total Default Supply Revenue	$	606	$	650	$	(44	)
Default Electricity Supply Sales (GWh)	2009		2008		Change
Residential		3,771		3,784		(13	)
Commercial and industrial		1,585		2,026		(441	)
Other		31		32		(1	)
Total Default Electricity Supply Sales		5,387		5,842		(455	)

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DPL

Default Electricity Supply Customers (in thousands)	2009	2008	Change
Residential	430	429	1
Commercial and industrial	47	49	(2	)
Other	1	1	—
Total Default Electricity Supply Customers	478	479	(1	)

Default Supply Revenue, which is substantially offset in Purchased Energy, decreased by $44 million primarily due to:

• A decrease of $38 million due to lower sales, primarily the result of commercial and industrial customer migration to competitive suppliers.

• A decrease of $18 million due to lower non-weather related customer usage.

The aggregate amount of these decreases was partially offset by:

• An increase of $10 million as the result of higher Default Electricity Supply rates.

• An increase of $4 million due to higher sales as a result of colder weather during the 2009 winter heating season as compared to 2008.

The following table shows the percentages of DPL’s total distribution sales by jurisdiction that are derived from customers receiving Default Electricity Supply distribution from DPL. Amounts are for the nine months ended September 30:

	2009		2008
Sales to Delaware customers	52	%	56	%
Sales to Maryland customers	64	%	65	%

Natural Gas Operating Revenue

	2009		2008		Change
Regulated Gas Revenue	$	169	$	146	$	23
Other Gas Revenue		30		106		(76	)
Total Natural Gas Operating Revenue	$	199	$	252	$	(53	)

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

Regulated Gas Revenue

Regulated Gas Revenue	2009		2008		Change
Residential	$	103	$	86	$	17
Commercial and industrial		60		54		6
Transportation and other		6		6		—
Total Regulated Gas Revenue	$	169	$	146	$	23
Regulated Gas Sales (billion cubic feet)	2009		2008		Change
Residential		6		5		1
Commercial and industrial		4		4		—
Transportation and other		4		5		(1	)
Total Regulated Gas Sales		14		14		—

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DPL

Regulated Gas Customers (in thousands)	2009	2008	Change
Residential	113	112	1
Commercial and industrial	9	10	(1	)
Transportation and other	—	—	—
Total Regulated Gas Customers	122	122	—

Regulated Gas Revenue increased by $23 million primarily due to:

• An increase of $19 million due to the Gas Cost Rate changes effective November 2008 and March 2009.

• An increase of $10 million due to higher sales as a result of colder weather during the 2009 winter heating season as compared to 2008.

The aggregate amount of these increases was partially offset by:

• A decrease of $10 million due to lower non-weather related customer usage.

Other Gas Revenue

Other Gas Revenue, which is substantially offset in Gas Purchased expense, decreased by $76 million primarily due to lower revenue from off-system sales resulting from:

• A decrease of $64 million due to lower market prices.

• A decrease of $12 million due to lower demand from electric generators and gas marketers.

Operating Expenses

Purchased Energy

Purchased Energy, which is primarily associated with Default Electricity Supply sales, decreased by $39 million to $591 million in 2009 from $630 million in 2008. The decrease was primarily due to:

• A decrease of $54 million primarily due to commercial and industrial customer migration to competitive suppliers.

• A decrease of $7 million due to lower average electricity costs under new Default Electricity Supply contracts.

The aggregate amount of these decreases was partially offset by:

• An increase of $18 million due to a higher rate of recovery of electric supply costs resulting in a change in the Default Electricity Supply deferral balance.

• An increase of $5 million due to higher electricity sales as a result of colder weather during the 2009 winter heating season as compared to 2008.

Purchased Energy expense is substantially offset in Default Supply Revenue.

Gas Purchased

Total Gas Purchased, which is primarily offset in Regulated Gas Revenue and Other Gas Revenue, decreased by $53 million to $147 million in 2009 from $200 million in 2008. The decrease was primarily due to:

• A decrease of $73 million in the cost of gas purchases for off-system sales, the result of lower average gas prices and volumes purchased.

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DPL

• A decrease of $20 million in the cost of gas purchases for system sales, the result of lower average gas prices and volumes purchased.

The aggregate amount of these decreases was partially offset by:

• An increase of $41 million from the settlement of financial hedges entered into as part of DPL’s regulated natural gas hedge program.

Other Operation and Maintenance

Other Operation and Maintenance increased by $9 million to $182 million in 2009 from $173 million in 2008. Excluding a decrease of $3 million primarily related to administrative expenses that are deferred and recoverable, Other Operation and Maintenance expense increased by $12 million. The $12 million increase was primarily due to an increase in employee related pension and other postretirement benefit expenses.

In the third quarter of 2008, DPL recorded an adjustment to correct errors in Other Operation and Maintenance expenses for prior periods dating back to May 2006 for which late payment fees were incorrectly recognized. This adjustment resulted in an increase in Other Operation and Maintenance expenses for the nine months ended September 30, 2008 of $3 million. In the third quarter of 2008, PHI identified an error in the accounting for certain of its restricted stock awards granted under the Long-Term Incentive Plan which resulted in an understatement of DPL’s stock-based compensation expense in 2006 and 2007. This error was corrected in the third quarter of 2008, resulting in an increase in DPL’s Other Operation and Maintenance expenses for the nine months ended September 30, 2008 of $2 million. These adjustments were not considered material either individually or in the aggregate.

Gain on Sale of Assets

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

Other Income (Expense)

Other Expenses (which are net of Other Income) increased by $9 million to a net expense of $32 million in 2009 from a net expense of $23 million in 2008. The increase was primarily due to an $8 million increase in interest expense on long-term debt as the result of a higher amount of outstanding debt.

Income Tax Expense

DPL’s effective tax rates for the nine months ended September 30, 2009 and 2008 were 14.9 % and 32.6%, respectively. The decrease in the rate primarily resulted from the refund of $6 million (after tax) of state income taxes and the establishment of a state tax benefit carryforward of $7 million (after tax), each related to a change in the tax reporting for the disposition of certain assets in prior years. This decrease is partially offset by the changes in estimates and interest related to uncertain and effectively settled tax positions and the non-recurring adjustments to prior years’ taxes.

Capital Requirements

Liquidity

The disruptions in the capital and credit markets, combined with the volatility of energy prices, had an impact on the borrowing capacity and liquidity of DPL. Since the third quarter of 2008, to address the challenges posed by the current capital and credit market environment and to ensure that DPL will continue to have sufficient access to cash to meet its liquidity needs, DPL has taken several measures to reduce expenditures, issued $250 million of 6.4% first mortgage bonds due in 2013 and resold $9 million of Pollution Control Revenue Refunding Bonds previously issued for the benefit of DPL by the Delaware Economic Development Authority, which DPL purchased in 2008.

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DPL

Capital Expenditures

DPL’s capital expenditures for the nine months ended September 30, 2009, totaled $125 million. These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission.

Due to a reduced near-term load forecast for the region, PJM recommended a one-year delay for the Mid-Atlantic Power Pathway’s (MAPP) in-service date. Based on these changes by PJM, DPL has updated its projected capital expenditures as presented in DPL’s Form 10-K for the year ended December 31, 2008. The following table shows the updated projected capital expenditures for DPL on a combined basis for the five-year period 2009-2013. DPL expects to fund these expenditures through internally generated cash and from external financing and capital contributions from PHI.

	For the Year
	2009		2010		2011		2012		2013		Total
	(millions of dollars)
DPL
Distribution	$	108	$	98	$	108	$	120	$	119	$	553
Distribution - Blueprint for the Future		34		47		1		40		—		122
Transmission		62		46		60		72		122		362
Transmission - MAPP		10		36		154		167		173		540
Gas Delivery		21		21		20		21		19		102
Other		17		23		18		14		11		83
	$	252	$	271	$	361	$	434	$	444	$	1,762

MAPP Project

In October 2007, the PJM Board of Managers approved PHI’s proposed MAPP transmission project for construction of a new 230-mile, 500-kilovolt interstate transmission project at a then-estimated cost of $1 billion. This MAPP project is part of PJM’s Regional Transmission Expansion Plan required to address the reliability objectives of the PJM Regional Transmission Organization system. At that time, the MAPP project was to originate at Possum Point substation in northern Virginia, connect into three substations across southern Maryland, cross the Chesapeake Bay, tie into two substations across the Delmarva Peninsula and terminate at Salem substation in southern New Jersey. On December 4, 2008, the PJM Board approved a direct-current technology for segments of the project including the Chesapeake Bay Crossing. On May 20, 2009, the PJM Board revised its Regional Transmission Expansion Plan as a result of updating their load forecast for the region. PJM determined that the line segment from Possum Point substation to the second substation on the Delmarva Peninsula (Indian River substation) is now required to be operational by June 1, 2014 and the Indian River to Salem portion of the MAPP project was not required at the present time. With these modifications, the cost of the MAPP project currently is estimated at $1.2 billion. PJM will continue to evaluate the need for the Indian River to Salem line in a future planning period.

153

DPL

Forward-Looking Statements

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

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

• Prevailing governmental policies and regulatory actions affecting the energy industry, including allowed rates of return, industry and rate structure, acquisition and disposal of assets and facilities, operation and construction of plant facilities, recovery of purchased power expenses, and present or prospective wholesale and retail competition;

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

• Weather conditions;

• Population growth rates and demographic patterns;

• Competition for retail and wholesale customers;

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

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

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

• Changes in accounting standards or practices;

• Changes in project costs;

• Unanticipated changes in operating expenses and capital expenditures;

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

• Rules and regulations imposed by federal and/or state regulatory commissions, PJM, the North American Electric Reliability Corporation and other applicable electric reliability organizations;

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

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

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

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

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

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

154

ACE

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

Atlantic City Electric Company

General Overview

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

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

Results Of Operations

The following results of operations discussion compares the nine months ended September 30, 2009, to the nine months ended September 30, 2008. Other than this disclosure, information under this item has been omitted in accordance with General Instruction H to the Form 10-Q. All amounts in the tables (except sales and customers) are in millions of dollars.

Operating Revenue

	2009		2008		Change
Regulated T&D Electric Revenue	$	279	$	272	$	7
Default Supply Revenue		780		1,006		(226	)
Other Electric Revenue		13		10		3
Total Operating Revenue	$	1,072	$	1,288	$	(216	)

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

Regulated T&D Electric Revenue includes revenue from the delivery of electricity, including the delivery of Default Electricity Supply, to ACE’s customers within its service territory at regulated rates. Regulated T&D Electric Revenue also includes transmission service revenue that ACE receives as a transmission owner from PJM Interconnection, LLC (PJM).

Default Supply Revenue is the revenue received for Default Electricity Supply. The costs related to Default Electricity Supply are included in Purchased Energy. Default Supply Revenue also includes revenue from Transition Bond Charges and other restructuring related revenues.

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

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ACE

Regulated T&D Electric

Regulated T&D Electric Revenue	2009		2008		Change
Residential	$	127	$	124	$	3
Commercial and industrial		100		95		5
Other		52		53		(1	)
Total Regulated T&D Electric Revenue	$	279	$	272	$	7

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

Regulated T&D Electric Sales (Gigawatt hours (GWh))	2009	2008	Change
Residential	3,376	3,452	(76	)
Commercial and industrial	4,043	4,315	(272	)
Other	33	34	(1	)
Total Regulated T&D Electric Sales	7,452	7,801	(349	)
Regulated T&D Electric Customers (in thousands)	2009	2008	Change
Residential	481	480	1
Commercial and industrial	65	65	—
Other	1	1	—
Total Regulated T&D Electric Customers	547	546	1

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

• An increase of $16 million due to a distribution rate change as part of a higher New Jersey Societal Benefit Charge that became effective in June 2008 (substantially offset in Deferred Electric Service Costs).

The increase was partially offset by:

• A decrease of $6 million due to lower non-weather related customer usage.

• A decrease of $3 million due to lower sales as a result of milder weather during the 2009 spring and summer months as compared to 2008.

Default Electricity Supply

Default Supply Revenue	2009		2008		Change
Residential	$	415	$	422	$	(7	)
Commercial and industrial		257		328		(71	)
Other		108		256		(148	)
Total Default Supply Revenue	$	780	$	1,006	$	(226	)

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

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ACE

Default Electricity Supply Sales (GWh)	2009	2008	Change
Residential	3,376	3,452	(76	)
Commercial and industrial	2,183	2,678	(495	)
Other	33	34	(1	)
Total Default Electricity Supply Sales	5,592	6,164	(572	)
Default Electricity Supply Customers (in thousands)	2009	2008	Change
Residential	481	480	1
Commercial and industrial	62	65	(3	)
Other	1	1	—
Total Default Electricity Supply Customers	544	546	(2	)

Default Supply Revenue, which is substantially offset in Purchased Energy and Deferred Electric Service Costs, decreased by $226 million primarily due to:

• A decrease of $147 million in wholesale energy revenues due to lower market prices for the sale of electricity purchased from NUGs.

• A decrease of $38 million due to lower sales, primarily the result of commercial customer migration to competitive suppliers.

• A decrease of $17 million due to lower non-weather related customer usage.

• A decrease of $13 million due to lower sales as a result of milder weather during the 2009 spring and summer months as compared to 2008.

• A decrease of $9 million as the result of lower Default Electricity Supply rates.

The decrease in total Default Supply Revenue includes a decrease of $4 million in unbilled revenue attributable to ACE’s BGS. Under the BGS terms approved by the NJBPU, ACE is entitled to recover from its customers all of its costs of providing BGS. Accordingly, 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 earnings in the period 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, 2009 as compared to the comparable period for 2008, BGS unbilled revenue decreased by $4 million, which resulted in a $2 million decrease in ACE’s net income. The decrease was due to increased customer migration and milder weather during the unbilled revenue period at the end of the nine months ended September 30, 2009 as compared to the corresponding period in 2008.

For the nine months ended September 30, 2009 and 2008, the percentage of ACE’s total distribution sales that are derived from customers receiving Default Electricity Supply are 75% and 79% respectively.

Operating Expenses

Purchased Energy

Purchased Energy, which is primarily associated with Default Electricity Supply sales, decreased by $63 million to $850 million in 2009 from $913 million in 2008. The decrease was primarily due to:

• A decrease of $72 million primarily due to commercial customer migration to competitive suppliers.

• A decrease of $13 million due to lower electricity sales as a result of milder weather during the 2009 spring and summer months as compared to 2008.

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ACE

The aggregate amount of these decreases was partially offset by:

• An increase of $22 million due to higher average electricity costs under new Default Electricity Supply contracts.

Purchased Energy is substantially offset in Default Supply Revenue and Deferred Electric Service Costs.

Other Operation and Maintenance

Other Operation and Maintenance increased by $6 million to $145 million in 2009 from $139 million in 2008. Excluding an increase of $1 million primarily related to bad debt expenses that are deferred and recoverable, Other Operation and Maintenance expense increased by $5 million primarily due to an increase of $8 million in employee related pension and other postretirement benefit expenses.

In the third quarter of 2008, PHI identified an error in the accounting for certain of its restricted stock awards granted under the Long-Term Incentive Plan which resulted in an understatement of ACE’s stock-based compensation expense in 2006 and 2007. This error was corrected in the third quarter of 2008, resulting in an increase in ACE’s Other Operation and Maintenance expenses for the nine months ended September 30, 2008 of $1 million. This adjustment was not considered material.

Deferred Electric Service Costs

Deferred Electric Service Costs decreased by $136 million, the result of a reduction of expenses of $116 million in 2009 as compared to an increase in expenses of $20 million in 2008. The decrease was primarily due to:

• A decrease of $171 million due to a lower rate of recovery of costs from energy and capacity purchased under the NUG contracts.

The decrease was partially offset by:

• An increase of $17 million due to a higher rate of recovery of deferred energy costs.

• An increase of $14 million due to a higher rate of recovery of New Jersey Societal Benefit program costs.

• An increase of $4 million due to a higher rate of recovery of deferred transmission costs.

Deferred Electric Service Costs are substantially offset in Regulated T&D Electric Revenue, Default Supply Revenue and Purchased Energy.

Other Income (Expense)

Other Expenses (which are net of Other Income) increased by $9 million to a net expense of $49 million in 2009 from a net expense of $40 million in 2008. The increase was primarily due to a $12 million increase in interest expense on long-term debt as the result of a higher amount of outstanding debt.

Income Tax Expense

ACE’s consolidated effective tax rates for the nine months ended September 30, 2009 and 2008 were 34.0% and 31.4%, respectively. The increase in the rate resulted from changes in estimates and interest related to uncertain and effectively settled tax positions and the impact of certain permanent state tax differences as a percentage of pre-tax income, partially offset by the non-recurring adjustments to prior year taxes and amortization of tax credits.

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ACE

Income Tax Adjustment

During the first and second quarters of 2009, ACE recorded adjustments to correct certain income tax errors related to prior periods. These adjustments, which are not considered material, resulted in a decrease in income tax expense of $1 million for the nine months ended September 30, 2009.

Capital Requirements

Liquidity

The disruptions in the capital and credit markets, combined with the volatility of energy prices, had an impact on the borrowing capacity and liquidity of ACE. Since the third quarter of 2008, to address the challenges posed by the current capital and credit market environment and to ensure that ACE will continue to have sufficient access to cash to meet its liquidity needs, ACE has taken several measures to reduce expenditures and issued $250 million in 7.75% first mortgage bonds due in 2018.

Capital Expenditures

ACE’s capital expenditures for the nine months ended September 30, 2009, totaled $98 million. These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission.

Due to a reduced near-term load forecast for the region, PJM recommended a one-year delay for the Mid-Atlantic Power Pathway’s in-service date. Based on this change by PJM, ACE has updated its projected capital expenditures as presented in ACE’s Form 10-K for the year ended December 31, 2008. The following table shows the updated projected capital expenditures for ACE on a combined basis for the five-year period 2009-2013. ACE expects to fund these expenditures through internally generated cash and from external financing and capital contributions from PHI.

	For the Year
	2009		2010		2011		2012		2013		Total
	(millions of dollars)
ACE
Distribution	$	110	$	111	$	104	$	109	$	111	$	545
Distribution - Blueprint for the Future		6		8		1		—		8		23
Transmission		28		25		32		34		33		152
Other		8		14		18		17		12		69
	$	152	$	158	$	155	$	160	$	164	$	789

Stimulus Funds Related to Blueprint for the Future

On October 27, 2009, ACE was informed by the U.S. Department of Energy (DOE) that, subject to final negotiations, it was awarded $19 million in federal stimulus funds to help build an integrated smart grid, a key aspect of PHI’s Blueprint for the Future initiative. ACE intends to use the award to help offset projected Blueprint for the Future capital expenditures in New Jersey.

Distribution

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

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ACE

Forward-Looking Statements

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

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

• Prevailing governmental policies and regulatory actions affecting the energy industry, including allowed rates of return, industry and rate structure, acquisition and disposal of assets and facilities, operation and construction of plant facilities, recovery of purchased power expenses, and present or prospective wholesale and retail competition;

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

• Weather conditions;

• Population growth rates and demographic patterns;

• Competition for retail and wholesale customers;

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

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

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

• Changes in accounting standards or practices;

• Changes in project costs;

• Unanticipated changes in operating expenses and capital expenditures;

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

• Rules and regulations imposed by federal and/or state regulatory commissions, PJM, the North American Electric Reliability Corporation and other applicable electric reliability organizations;

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

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

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

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

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

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

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Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Risk management policies for PHI and its subsidiaries are determined by PHI’s Corporate Risk Management Committee, the members of which are PHI’s Chief Risk Officer, Chief Operating Officer, Chief Financial Officer, General Counsel, Chief Information Officer and other senior executives. The Corporate Risk Management Committee monitors interest rate fluctuation, commodity price fluctuation, and credit risk exposure, and sets risk management policies that establish limits on unhedged risk and determine risk reporting requirements. See 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. For information about PHI’s derivative activities, other than the information disclosed herein, refer to Note (2), “Significant Accounting Policies - Accounting For Derivatives,” Note (17), “Use of Derivatives in Energy and Interest Rate Hedging Activities,” and Item 7A, “Quantitative and Qualitative Disclosures About Market Risk” in the Consolidated Financial Statements of PHI included in its Annual Report on Form 10-K for the year ended December 31, 2008.

Pepco Holdings, Inc.

Commodity Price Risk

The Competitive Energy segments actively engage in commodity risk management activities to reduce their financial exposure to changes in the value of their assets and obligations due to commodity price fluctuations. Certain of these risk management activities are conducted using instruments classified as derivatives based on FASB guidance on derivatives and hedging (ASC 815). The Competitive Energy segments also manage commodity risk with contracts that are not classified as derivatives. The Competitive Energy segments’ primary risk management objectives are (1) to manage the spread between the cost of fuel used to operate their electric generating facilities and the revenue received from the sale of the power produced by those plants by selling forward a portion of their projected plant output and buying forward a portion of their projected fuel supply requirements and (2) to manage the spread between wholesale and retail sales commitments and the cost of supply used to service those commitments in order to ensure stable and known cash flows and fix favorable prices and margins when they become available.

PHI’s risk management policies place oversight at the senior management level through the Corporate Risk Management Committee which has the responsibility for establishing corporate compliance requirements for the Competitive Energy business’ energy market participation. PHI collectively refers to these energy market activities, including its commodity risk management activities, as “energy commodity” activities. PHI uses a value-at-risk (VaR) model to assess the market risk of its Competitive Energy segments’ energy commodity activities. PHI also uses other measures to limit and monitor risk in its energy commodity activities, including limits on the nominal size of positions and periodic loss limits. VaR represents the potential fair value loss on energy contracts or portfolios due to changes in market prices for a specified time period and confidence level. In January 2009, PHI changed its VaR estimation model from a delta-normal variance / covariance model to a delta-gamma model. The other parameters, a 95 percent, one-tailed confidence level and a one-day holding period, remained the same. Since VaR is an estimate, it is not necessarily indicative of actual results that may occur. The table below provides the VaR associated with energy contracts for the nine months ended September 30, 2009 in millions of dollars:

	VaR for Competitive Energy Commodity Activity (a)
95% confidence level, one-day holding period, one-tailed Period end	$	5
Average for the period	$	5
High	$	9
Low	$	2

(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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Conectiv Energy economically hedges both the estimated plant output and fuel requirements as the estimated levels of output and fuel needs change. Economic hedge percentages include the estimated electricity output of Conectiv Energy’s generating facilities and any associated financial or physical commodity contracts (including derivative contracts that are classified as cash flow hedges, other derivative instruments, wholesale normal purchase and normal sales contracts, and default electricity supply contracts).

Conectiv Energy maintains a forward 36 month program with targeted ranges for economically hedging its projected plant output combined with its energy purchase commitments. The disclosure shows the percentage of its entire expected plant output and energy purchase commitments for all hours that are hedged. Conectiv Energy is including default electricity supply contracts and associated hedges in the Independent System Operator – New England. The hedge percentages for all expected plant output and purchase commitment (based on the then current forward electricity price curve) are as follows:

Month	Target Range
1-12	50-100%
13-24	25-75%
25-36	0-50%

The primary purpose of the risk management program is to improve the predictability and stability of margins by selling forward a portion of projected plant output, and buying forward a portion of projected fuel supply requirements. Within each period, hedged percentages can vary significantly above or below the average reported percentages.

As of September 30, 2009, the electricity sold forward by Conectiv Energy as a percentage of projected plant output combined with energy purchase commitments was 101%, 81%, and 51% for the 1-12 month, 13-24 month and 25-36 month forward periods, respectively. The amount of forward sales during the 1-12 month period represents 23% of Conectiv Energy’s combined total generating capability and energy purchase commitments. The volumetric percentages for the forward periods can vary and may not represent the amount of expected value hedged.

Not all of the value associated with Conectiv Energy’s generation activities can be hedged such as the portion attributable to ancillary services and fuel switching due to the lack of market products, market liquidity, and other factors. Also, the hedging of locational value can be limited.

Pepco Energy Services purchases electric and natural gas futures, swaps, options and forward contracts to hedge price risk in connection with the purchase of physical natural gas and electricity for delivery to customers. Pepco Energy Services accounts for its futures and swap contracts as cash flow hedges of forecasted transactions. Its options contracts and certain commodity contracts that do not qualify as cash flow hedges are marked-to-market through current earnings. Its forward contracts are accounted for using standard accrual accounting since these contracts meet the requirements for normal purchase and normal sale accounting under FASB guidance on derivatives and hedging.

Credit and Nonperformance Risk

This 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, 2009, in millions of dollars.

Rating (a)	Exposure Before Credit Collateral (b)		Credit Collateral (c)		Net Exposure		Number of Counterparties Greater Than 10% (d)	Net Exposure of Counterparties Greater Than 10%
Investment Grade	$	270	$	1	$	269	3	$	174
Non-Investment Grade		10		2		8	—		—
No External Ratings		26		10		16	—		—
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.

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(b) Exposure before credit collateral - includes the marked to market (MTM) energy contract net assets for open/unrealized transactions, the net receivable/payable for realized transactions and net open positions for contracts not subject to MTM. Amounts due from counterparties are offset by liabilities payable to those counterparties to the extent that legally enforceable netting arrangements are in place. Thus, this column presents the net credit exposure to counterparties after reflecting all allowable netting, but before considering collateral held.

(c) Credit collateral - the face amount of cash deposits, letters of credit and performance bonds received from counterparties, not adjusted for probability of default, and, if applicable, property interests (including oil and gas reserves).

(d) Using a percentage of the total exposure.

For additional information concerning market risk, please refer to Item 3, “Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk” and “Credit and Nonperformance Risk,” and for information regarding “Interest Rate Risk,” please refer to Item 7A, “Quantitative and Qualitative Disclosures About Market Risk,” in Pepco Holdings’ Annual Report on Form 10-K for the year ended December 31, 2008.

INFORMATION FOR THIS ITEM IS NOT REQUIRED FOR PEPCO, DPL, AND ACE AS THEY MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION H(1)(a) AND (b) OF FORM 10-Q AND THEREFORE ARE FILING THIS FORM WITH A REDUCED FILING FORMAT.

Item 4. CONTROLS AND PROCEDURES

Pepco Holdings, Inc.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Under the supervision, and with the participation of management, including the chief executive officer and the chief financial officer, Pepco Holdings has evaluated the effectiveness of the design and operation of its disclosure controls and procedures as of September 30, 2009 and, based upon this evaluation, the chief executive officer and the chief financial officer of Pepco Holdings have concluded that these controls and procedures are effective to provide reasonable assurance that material information relating to Pepco Holdings and its subsidiaries that is required to be disclosed in reports filed with, or submitted to, the Securities and Exchange Commission (SEC) under the Securities Exchange Act of 1934, as amended (the Exchange Act) (i) is recorded, processed, summarized and reported within the time periods specified by the SEC rules and forms and (ii) is accumulated and communicated to management, including its chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

During the three months ended September 30, 2009, there was no change in Pepco Holdings’ internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, Pepco Holdings’ internal controls over financial reporting.

Item 4T. CONTROLS AND PROCEDURES

Potomac Electric Power Company

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Under the supervision, and with the participation of management, including the chief executive officer and the chief financial officer, Pepco has evaluated the effectiveness of the design and operation of its disclosure controls and procedures as of September 30, 2009, 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, 2009, there was no change in Pepco’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, Pepco’s internal controls over financial reporting.

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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, 2009, and, based upon this evaluation, the chief executive officer and the chief financial officer of DPL have concluded that these controls and procedures are effective to provide reasonable assurance that material information relating to DPL that is required to be disclosed in reports filed with, or submitted to, the SEC under the Exchange Act (i) is recorded, processed, summarized and reported within the time periods specified by the SEC rules and forms and (ii) is accumulated and communicated to management, including its chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

During the three months ended September 30, 2009, there was no change in DPL’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, DPL’s internal controls over financial reporting.

Atlantic City Electric Company

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Under the supervision, and with the participation of management, including the chief executive officer and the chief financial officer, ACE has evaluated the effectiveness of the design and operation of its disclosure controls and procedures as of September 30, 2009, and, based upon this evaluation, the chief executive officer and the chief financial officer of ACE have concluded that these controls and procedures are effective to provide reasonable assurance that material information relating to ACE and its subsidiaries that is required to be disclosed in reports filed with, or submitted to, the SEC under the Exchange Act (i) is recorded, processed, summarized and reported within the time periods specified by the SEC rules and forms and (ii) is accumulated and communicated to management, including its chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

During the three months ended September 30, 2009, there was no change in ACE’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, ACE’s internal controls over financial reporting.

Part II OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

Pepco Holdings

Other than ordinary routine litigation incidental to its and its subsidiaries’ business, PHI is not a party to, and its subsidiaries’ property is not subject to, any material pending legal proceedings except as described in Note (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.

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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, 2008. There have been no material changes to Pepco Holdings’ risk factors as disclosed in the Form 10-K, except that:

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

The IRS challenge to cross-border energy sale and lease-back transactions entered into by a PHI subsidiary could result in loss of prior and future tax benefits. (PHI only)

PCI maintains a portfolio of eight cross-border energy lease investments, which as of September 30, 2009, had an equity value of approximately $1.4 billion and from which PHI currently derives approximately $56 million per year in tax benefits in the form of interest and depreciation deductions in excess of rental income. In 2005, the Treasury Department and IRS issued a notice identifying sale-leaseback transactions with certain attributes entered into with tax-indifferent parties as tax avoidance transactions, and the IRS announced its intention to disallow the associated tax benefits claimed by the investors in these transactions. PHI’s cross-border energy lease investments, each of which is with a tax-indifferent party, have been under examination by the IRS as part of the normal PHI federal income tax audits. In connection with the audit of PHI’s 2001 and 2002 income tax returns, the IRS disallowed the depreciation and interest deductions in excess of rental income claimed by PHI with respect to six of its cross-border energy lease investments. In addition, the IRS has sought to recharacterize the six leases as loan transactions as to which PHI would be subject to original issue discount income. On March 31, 2009, the IRS issued its Revenue Agents Report for the calendar years 2003 to 2005 which among other items proposes to disallow the depreciation and interest deductions in excess of rental income claimed by PHI with respect to all eight of its cross-border energy lease investments and recharacterize the eight leases as loan transactions as to which PHI would be subject to original issue discount income. PHI believes that its tax position with regard to its cross-border energy lease investments is appropriate based on applicable statutes, regulations and case law and has filed a protest with respect to these proposed adjustments, which PHI expects will be forwarded to the Appeals Office of the IRS in the near future. 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 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 $695 million estimated obligation for federal and state taxes and interest in the event of a total disallowance of tax benefits and a recharacterization of the transactions as loans. Accordingly, based on current assumptions, the net cash impact to PHI of such a mitigation action would be slightly favorable. If payments of additional taxes and interest preceded the receipt of liquidation proceeds, the payments would be funded by currently available sources of liquidity.

In the event that PHI were not to prevail and were to suffer a total disallowance of the tax benefits and incur imputed original issue discount income due to the recharacterization of the leases as loans, PHI would be required under FASB guidance on leases (ASC 840 & 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 material non-cash charge to earnings.

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For further discussion of this matter, see Part I, Item 1 “Financial Statements — Note (14), “Commitments and Contingencies — Regulatory and Other Matters — PHI’s Cross-Border Energy Lease Investments,” of this Form 10-Q.

(2) The following risk factor supersedes, as it relates to PHI, the risk factor in the Form 10-K with the heading having as its introductory sentence, “PHI and its subsidiaries are dependent on their ability to successfully access capital markets”:

PHI and its subsidiaries are dependent on access to capital markets and bank funding to satisfy their capital and liquidity requirements. The inability to obtain required financing would have an adverse effect on their respective businesses.

PHI, Pepco, DPL and ACE each have significant capital requirements, including the funding of construction expenditures and the refinancing of maturing debt. The companies rely primarily on cash flow from operations and access to the capital markets to meet these financing needs. The operating activities of the companies also require access to short-term money markets and bank financing as sources of liquidity that are not met by cash flow from their operations. Adverse business developments or market disruptions could increase the cost of financing or prevent the companies from accessing one or more financial markets.

The financing costs of each of PHI, Pepco, DPL and ACE are closely linked, directly or indirectly, to its credit rating. The collateral requirements of the Competitive Energy business also depend in part on the unsecured debt rating of PHI. Negative ratings actions by one or more of the credit rating agencies resulting from a change in PHI’s operating results or prospects would increase funding costs and collateral requirements and could make financing more difficult to obtain.

Under the terms of PHI’s primary credit facilities, the consolidated indebtedness of PHI cannot exceed 65% of its consolidated capitalization. If PHI’s equity were to decline to a level that caused PHI’s debt to exceed this limit, lenders would be entitled to refuse any further extension of credit and to declare all of the outstanding debt under the credit facilities immediately due and payable. To avoid such a default, a renegotiation of this covenant would be required which would likely increase funding costs and could result in additional covenants that would restrict PHI’s operational and financing flexibility. Events that could cause a reduction in PHI’s equity include a further write down of PHI’s cross-border energy lease investments or a significant write down of PHI’s goodwill.

Events that could cause or contribute to a disruption of the financial markets include, but are not limited to:

• a recession or an economic slowdown;

• the bankruptcy of one or more energy companies or financial institutions;

• a significant change in energy prices;

• a terrorist attack or threatened attacks; or

• a significant electricity transmission disruption.

In accordance with the requirements of the Sarbanes-Oxley Act of 2002 and the SEC rules thereunder, PHI’s management is responsible for establishing and maintaining internal control over financial reporting and is required to assess annually the effectiveness of these controls. The inability to certify the effectiveness of these controls due to the identification of one or more material weaknesses in these controls also could increase financing costs or could adversely affect the ability to access one or more financial markets.

(3) The following risk factor is an additional risk factor:

PHI has a significant goodwill balance related to its Power Delivery business. A determination that goodwill is impaired could result in a significant charge to earnings.

PHI has a goodwill balance of approximately $1.4 billion primarily attributable to Pepco’s acquisition of Conectiv in 2002. Under generally accepted accounting principles, an impairment charge must be recorded to the extent that the implied fair value of goodwill is less than the carrying value of goodwill, as shown on the consolidated balance sheet. PHI is required to test goodwill for impairment at least annually and whenever events or changes in circumstances indicate that the carrying value may not be recoverable. Factors that may result in an interim impairment test include a protracted decline in stock price causing market capitalization to fall below book value. If PHI were to determine that its goodwill is

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impaired, PHI would be required to reduce its goodwill balance by the amount of the impairment and record a corresponding non-cash charge to earnings. Depending on the amount of the impairment, an impairment determination could have a material adverse effect on PHI’s financial condition and results of operations, but would not have an impact on cash flow.

Pepco

For a discussion of Pepco’s risk factors, please refer to Item 1A, “Risk Factors,” in Pepco’s Annual Report on Form 10-K for the year ended December 31, 2008. There have been no material changes to Pepco’s risk factors as disclosed in the Form 10-K, except that the following risk factor supersedes, as it relates to Pepco, the risk factor in the Form 10-K with the heading having as its introductory sentence, “PHI and its subsidiaries are dependent on their ability to successfully access capital markets”:

Pepco is dependent on access to capital markets and bank funding to satisfy its capital and liquidity requirements. The inability to obtain required financing would have an adverse effect on its business.

Pepco has significant capital requirements, including the funding of construction expenditures and the refinancing of maturing debt. The company relies primarily on cash flow from operations and access to the capital markets to meet these financing needs. The operating activities of the company also require access to short-term money markets and bank financing as sources of liquidity that are not met by cash flow from its operations. Adverse business developments or market disruptions could increase the cost of financing or prevent the company from accessing one or more financial markets.

The financing costs of Pepco are closely linked, directly or indirectly, to its credit rating. Negative ratings actions by one or more of the credit rating agencies resulting from a change in Pepco’s operating results or prospects would increase funding costs and collateral requirements and could make financing more difficult to obtain.

Events that could cause or contribute to a disruption of the financial markets include, but are not limited to:

• a recession or an economic slowdown;

• the bankruptcy of one or more energy companies or financial institutions;

• a significant change in energy prices;

• a terrorist attack or threatened attacks; or

• a significant electricity transmission disruption.

In accordance with the requirements of the Sarbanes-Oxley Act of 2002 and the SEC rules thereunder, Pepco’s management is responsible for establishing and maintaining internal control over financial reporting and is required to assess annually the effectiveness of these controls. The inability to certify the effectiveness of these controls due to the identification of one or more material weaknesses in these controls also could increase financing costs or could adversely affect the ability to access one or more financial markets.

DPL

For a discussion of DPL’s risk factors, please refer to Item 1A, “Risk Factors,” in DPL’s Annual Report on Form 10-K for the year ended December 31, 2008. There have been no material changes to DPL’s risk factors as disclosed in the Form 10-K, except that the following risk factor supersedes, as it relates to DPL, the risk factor in the Form 10-K with the heading as its introductory sentence, “PHI and its subsidiaries are dependent on their ability to successfully access capital markets”:

DPL is dependent on access to capital markets and bank funding to satisfy its capital and liquidity requirements. The inability to obtain required financing would have an adverse effect on its business.

DPL has significant capital requirements, including the funding of construction expenditures and the refinancing of maturing debt. The company relies primarily on cash flow from operations and access to the capital markets to meet these financing needs. The operating activities of the company also require access to short-term money markets and bank financing as sources of liquidity that are not met by cash flow from its operations. Adverse business developments or market disruptions could increase the cost of financing or prevent the company from accessing one or more financial markets.

167

The financing costs of DPL are closely linked, directly or indirectly, to its credit rating. Negative ratings actions by one or more of the credit rating agencies resulting from a change in DPL’s operating results or prospects would increase funding costs and collateral requirements and could make financing more difficult to obtain.

Events that could cause or contribute to a disruption of the financial markets include, but are not limited to:

• a recession or an economic slowdown;

• the bankruptcy of one or more energy companies or financial institutions;

• a significant change in energy prices;

• a terrorist attack or threatened attacks; or

• a significant electricity transmission disruption.

In accordance with the requirements of the Sarbanes-Oxley Act of 2002 and the SEC rules thereunder, DPL’s management is responsible for establishing and maintaining internal control over financial reporting and is required to assess annually the effectiveness of these controls. The inability to certify the effectiveness of these controls due to the identification of one or more material weaknesses in these controls also could increase financing costs or could adversely affect the ability to access one or more financial markets.

ACE

For a discussion of ACE’s risk factors, please refer to Item 1A, “Risk Factors,” in ACE’s Annual Report on Form 10-K for the year ended December 31, 2008. There have been no material changes to ACE’s risk factors as disclosed in the Form 10-K, except that the following risk factor supersedes, as it relates to ACE, the risk factor in the Form 10-K with the heading having an introductory sentence, “PHI and its subsidiaries are dependent on their ability to successfully access capital markets”:

ACE is dependent on access to capital markets and bank funding to satisfy its capital and liquidity requirements. The inability to obtain required financing would have an adverse effect on its business.

ACE has significant capital requirements, including the funding of construction expenditures and the refinancing of maturing debt. The company relies primarily on cash flow from operations and access to the capital markets to meet these financing needs. The operating activities of the company also require access to short-term money markets and bank financing as sources of liquidity that are not met by cash flow from its operations. Adverse business developments or market disruptions could increase the cost of financing or prevent the company from accessing one or more financial markets.

The financing costs of ACE are closely linked, directly or indirectly, to its credit rating. Negative ratings actions by one or more of the credit rating agencies resulting from a change in ACE’s operating results or prospects would increase funding costs and collateral requirements and could make financing more difficult to obtain.

Events that could cause or contribute to a disruption of the financial markets include, but are not limited to:

• a recession or an economic slowdown;

• the bankruptcy of one or more energy companies or financial institutions;

• a significant change in energy prices;

• a terrorist attack or threatened attacks; or

• a significant electricity transmission disruption.

In accordance with the requirements of the Sarbanes-Oxley Act of 2002 and the SEC rules thereunder, ACE’s management is responsible for establishing and maintaining internal control over financial reporting and is required to assess annually the effectiveness of these controls. The inability to certify the effectiveness of these controls due to the identification of one or more material weaknesses in these controls also could increase financing costs or could adversely affect the ability to access one or more financial markets.

168

Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Pepco Holdings

None.

INFORMATION FOR THIS ITEM IS NOT REQUIRED FOR PEPCO, DPL, AND ACE AS THEY MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION H(1)(a) AND (b) OF FORM 10-Q AND THEREFORE ARE FILING THIS FORM WITH A REDUCED FILING FORMAT.

Item 3. DEFAULTS UPON SENIOR SECURITIES

Pepco Holdings

None.

INFORMATION FOR THIS ITEM IS NOT REQUIRED FOR PEPCO, DPL, AND ACE AS THEY MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION H(1)(a) AND (b) OF FORM 10-Q AND THEREFORE ARE FILING THIS FORM WITH A REDUCED FILING FORMAT.

Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

Pepco Holdings

None.

169

INFORMATION FOR THIS ITEM IS NOT REQUIRED FOR PEPCO, DPL, AND ACE AS THEY MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION H(1)(a) AND (b)  OF FORM 10-Q AND THEREFORE ARE FILING THIS FORM WITH A REDUCED FILING FORMAT.

Item 5. OTHER INFORMATION

Pepco Holdings

None.

Pepco

None.

DPL

None.

ACE

None.

170

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
4	DPL	One Hundred and Fifth Supplemental Indenture, dated as of September 22, 2009, between Delmarva Power & Light Company and The Bank of New York Mellon, as successor trustee	Exhibit 4.4 to DPL’s Form 8-K, 10/1//09
10.1	PHI	Amended and Restated Credit Agreement, dated as of October 16, 2009, by and among, Pepco Holdings, Inc., the lenders party thereto, Bank of America, N.A., as administrative agent and swingline lender, Banc of America Securities LLC, as sole lead arranger and sole book runner, and KeyBank National Association, JPMorgan Chase Bank, N.A., SunTrust Bank, The Bank of Nova Scotia, Morgan Stanley Bank, N.A., Credit Suisse, Cayman Islands Branch, Wells Fargo Bank, N.A. and Manufacturers and Traders Trust Company, as co-documentation agents	Exhibit 10.1 to PHI’s Form 8-K, 10/22//09
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.

171

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, 2009	By	/s/    A.J. KAMERICK
		Anthony J. Kamerick Senior Vice President and Chief Financial Officer, PHI, Pepco and DPL Chief Financial Officer, ACE

172

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

EX-12.1

Exhibit 12.1

Pepco Holdings, Inc.

	Nine Months Ended September 30, 2009			For the Year Ended December 31,
				2008			2007			2006			2005			2004
	(millions of dollars)
Income before extraordinary item (a)	$	192		$	305		$	324		$	245		$	369		$	257
Income tax expense (b)		102			168			188			161			255			167
Fixed charges:
Interest on long-term debt, amortization of discount, premium and expense		288			341			348			343			341			376
Other interest		17			24			25			19			20			21
Preferred dividend requirements of subsidiaries		—			—			—			1			3			3
Total fixed charges		305			365			373			363			364			400
Non-utility capitalized interest		(3	)		(6	)		(2	)		(1	)		(1	)		—
Income before extraordinary item, income tax expense, fixed charges and non-utility capitalized interest	$	596		$	832		$	883		$	768		$	987		$	824
Total fixed charges, shown above		305			365			373			363			364			400
Increase preferred stock dividend requirements of subsidiaries to a pre-tax amount		—			—			—			1			2			2
Fixed charges for ratio computation	$	305		$	365		$	373		$	364		$	366		$	402
Ratio of earnings to fixed charges and preferred dividends		1.95			2.28			2.36			2.11			2.70			2.05

(a) Excludes income/losses from equity investments.

(b) Concurrent with the adoption of FASB guidance on taxes (ASC 740) in 2007, amount includes interest on uncertain tax positions.

EX-12.2

Exhibit 12.2

Potomac Electric Power Company

	Nine Months Ended September 30, 2009		For the Year Ended December 31,
			2008		2007		2006		2005		2004
	(millions of dollars)
Net income	$	94	$	116	$	125	$	85	$	165	$	97
Income tax expense (a)		67		64		62		58		128		56
Fixed charges:
Interest on long-term debt, amortization of discount, premium and expense		78		95		86		77		83		83
Other interest		8		11		12		13		14		14
Total fixed charges		86		106		98		90		97		97
Income before income tax expense, and fixed charges	$	247	$	286	$	285	$	233	$	390	$	250
Ratio of earnings to fixed charges		2.87		2.70		2.91		2.59		4.04		2.57
Total fixed charges, shown above		86		106		98		90		97		97
Preferred dividend requirements, adjusted to a pre-tax amount		—		—		—		2		2		2
Total fixed charges and preferred dividends	$	86	$	106	$	98	$	92	$	99	$	99
Ratio of earnings to fixed charges and preferred dividends		2.87		2.70		2.91		2.54		3.94		2.53

(a) Concurrent with the adoption of FASB guidance on taxes (ASC 740) in 2007, amount includes interest on uncertain tax positions.

EX-12.3

Exhibit 12.3

Delmarva Power & Light Company

	Nine Months Ended September 30, 2009		For the Year Ended December 31,
			2008		2007		2006		2005		2004
	(millions of dollars)
Net income	$	40	$	68	$	45	$	43	$	75	$	63
Income tax expense (a)		7		45		37		32		58		48
Fixed charges:
Interest on long-term debt, amortization of discount, premium and expense		34		41		44		41		35		33
Other interest		2		2		2		3		3		2
Total fixed charges		36		43		46		44		38		35
Income before income tax expense, and fixed charges	$	83	$	156	$	128	$	119	$	171	$	146
Ratio of earnings to fixed charges		2.31		3.63		2.78		2.70		4.48		4.16
Total fixed charges, shown above		36		43		46		44		38		35
Preferred dividend requirements, adjusted to a pre-tax amount		—		—		—		1		2		2
Total fixed charges and preferred dividends	$	36	$	43	$	46	$	45	$	40	$	37
Ratio of earnings to fixed charges and preferred dividends		2.31		3.63		2.78		2.62		4.28		3.96

(a) Concurrent with the adoption of FASB guidance on taxes (ASC 740) in 2007, amount includes interest on uncertain tax positions.

EX-12.4

Exhibit 12.4

Atlantic City Electric Company

	Nine Months Ended September 30, 2009		For the Year Ended December 31,
			2008		2007		2006		2005		2004
	(millions of dollars)
Income from continuing operations	$	33	$	64	$	60	$	60	$	51	$	59
Income tax expense (a)		17		30		41		33		41		41
Fixed charges:
Interest on long-term debt, amortization of discount, premium and expense		52		64		66		65		60		62
Other interest		2		3		3		3		4		3
Total fixed charges		54		67		69		68		64		65
Income before extraordinary item, income tax expense, and fixed charges	$	104	$	161	$	170	$	161	$	156	$	165
Ratio of earnings to fixed charges		1.93		2.40		2.46		2.37		2.45		2.52
Total fixed charges, shown above		54		67		69		68		64		65
Preferred dividend requirements adjusted to a pre-tax amount		—		—		1		1		1		1
Total fixed charges and preferred dividends	$	54	$	67	$	70	$	69	$	65	$	66
Ratio of earnings to fixed charges and preferred dividends		1.93		2.40		2.44		2.35		2.43		2.50

(a) Concurrent with the adoption of FASB guidance on taxes (ASC 740) in 2007, amount includes interest on uncertain tax positions.

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Joseph M. Rigby, certify that:

1. I have reviewed this report on Form 10-Q of Pepco Holdings, Inc.

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal controls over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 29, 2009	/s/    JOSEPH M. RIGBY
	Joseph M. Rigby Chairman of the Board, President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Anthony J. Kamerick, certify that:

1. I have reviewed this report on Form 10-Q of Pepco Holdings, Inc.

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal controls over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 29, 2009	/s/    A.J. KAMERICK
	Anthony J. Kamerick Senior Vice President and Chief Financial Officer

EX-31.3

Exhibit 31.3

CERTIFICATION

I, David M. Velazquez, certify that:

1. I have reviewed this report on Form 10-Q of Potomac Electric Power Company.

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 29, 2009	/s/    DAVID M. VELAZQUEZ
	David M. Velazquez President and Chief Executive Officer

EX-31.4

Exhibit 31.4

CERTIFICATION

I, Anthony J. Kamerick, certify that:

1. I have reviewed this report on Form 10-Q of Potomac Electric Power Company.

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 29, 2009	/s/    A.J. KAMERICK
	Anthony J. Kamerick Senior Vice President and Chief Financial Officer

EX-31.5

Exhibit 31.5

CERTIFICATION

I, David M. Velazquez, certify that:

1. I have reviewed this report on Form 10-Q of Delmarva Power & Light Company.

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 29, 2009	/s/    DAVID M. VELAZQUEZ
	David M. Velazquez President and Chief Executive Officer

EX-31.6

Exhibit 31.6

CERTIFICATION

I, Anthony J. Kamerick, certify that:

1. I have reviewed this report on Form 10-Q of Delmarva Power & Light Company.

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 29, 2009	/s/    A.J. KAMERICK
	Anthony J. Kamerick Senior Vice President and Chief Financial Officer

EX-31.7

Exhibit 31.7

CERTIFICATION

I, David M. Velazquez, certify that:

1. I have reviewed this report on Form 10-Q of Atlantic City Electric Company.

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 29, 2009	/s/    DAVID M. VELAZQUEZ
	David M. Velazquez President and Chief Executive Officer

EX-31.8

Exhibit 31.8

CERTIFICATION

I, Anthony J. Kamerick, certify that:

1. I have reviewed this report on Form 10-Q of Atlantic City Electric Company.

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 29, 2009	/s/    A.J. KAMERICK
	Anthony J. Kamerick Chief Financial Officer

EX-32.1

Exhibit 32.1

Certificate of Chief Executive Officer and Chief Financial Officer

of

Pepco Holdings, Inc.

(pursuant to 18 U.S.C. Section 1350)

I, Joseph M. Rigby, and I, Anthony J. Kamerick, certify that, to the best of my knowledge, (i) the Quarterly Report on Form 10-Q of Pepco Holdings, Inc. for the quarter ended September 30, 2009, filed with the Securities and Exchange Commission on the date hereof fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Pepco Holdings, Inc.

October 29, 2009	/s/    JOSEPH M. RIGBY
	Joseph M. Rigby Chairman of the Board, President and Chief Executive Officer
October 29, 2009	/s/    A.J. KAMERICK
	Anthony J. Kamerick Senior Vice President and Chief Financial Officer

A signed original of this written statement required by Section 906 has been provided to Pepco Holdings, Inc. and will be retained by Pepco Holdings, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

Certificate of Chief Executive Officer and Chief Financial Officer

of

Potomac Electric Power Company

(pursuant to 18 U.S.C. Section 1350)

I, David M. Velazquez, and I, Anthony J. Kamerick, certify that, to the best of my knowledge, (i) the Quarterly Report on Form 10-Q of Potomac Electric Power Company for the quarter ended September 30, 2009, filed with the Securities and Exchange Commission on the date hereof fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Potomac Electric Power Company.

October 29, 2009	/s/    DAVID M. VELAZQUEZ
	David M. Velazquez President and Chief Executive Officer
October 29, 2009	/s/    A.J. KAMERICK
	Anthony J. Kamerick Senior Vice President and Chief Financial Officer

A signed original of this written statement required by Section 906 has been provided to Potomac Electric Power Company and will be retained by Potomac Electric Power Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.3

Exhibit 32.3

Certificate of Chief Executive Officer and Chief Financial Officer

of

Delmarva Power & Light Company

(pursuant to 18 U.S.C. Section 1350)

I, David M. Velazquez, and I, Anthony J. Kamerick, certify that, to the best of my knowledge, (i) the Quarterly Report on Form 10-Q of Delmarva Power & Light Company for the quarter ended September 30, 2009, filed with the Securities and Exchange Commission on the date hereof fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Delmarva Power & Light Company.

October 29, 2009	/s/    DAVID M. VELAZQUEZ
	David M. Velazquez President and Chief Executive Officer
October 29, 2009	/s/    A.J. KAMERICK
	Anthony J. Kamerick Senior Vice President and Chief Financial Officer

A signed original of this written statement required by Section 906 has been provided to Delmarva Power & Light Company and will be retained by Delmarva Power & Light Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.4

Exhibit 32.4

Certificate of Chief Executive Officer and Chief Financial Officer

of

Atlantic City Electric Company

(pursuant to 18 U.S.C. Section 1350)

I, David M. Velazquez, and I, Anthony J. Kamerick, certify that, to the best of my knowledge, (i) the Quarterly Report on Form 10-Q of Atlantic City Electric Company for the quarter ended September 30, 2009, filed with the Securities and Exchange Commission on the date hereof fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Atlantic City Electric Company.

October 29, 2009	/s/    DAVID M. VELAZQUEZ
	David M. Velazquez President and Chief Executive Officer
October 29, 2009	/s/    A.J. KAMERICK
	Anthony J. Kamerick Chief Financial Officer

A signed original of this written statement required by Section 906 has been provided to Atlantic City Electric Company and will be retained by Atlantic City Electric Company and furnished to the Securities and Exchange Commission or its staff upon request.