Pepco 10-Q 2009 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

THE SECURITIES EXCHANGE ACT OF 1934

For the quarter ended June 30, 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 ACEmeet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with reduced disclosure format specified in General Instruction H(2) of Form 10-Q.

Registrant	Number of Shares of Common Stock of             the Registrant Outstanding at June 30, 2009
Pepco Holdings	220,820,630 ($.01 par value)
Pepco	100 ($.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	100
Item 3.	- Quantitative and Qualitative Disclosures About Market Risk	159
Item 4.	- Controls and Procedures	161
Item 4T.	- Controls and Procedures	161
PART II	OTHER INFORMATION	162
Item 1.	- Legal Proceedings	162
Item 1A.	- Risk Factors	163
Item 2.	- Unregistered Sales of Equity Securities and Use of Proceeds	166
Item 3.	- Defaults Upon Senior Securities	166
Item 4.	- Submission of Matters to a Vote of Security Holders	167
Item 5.	- Other Information	168
Item 6.	- Exhibits	169
Signatures		170

GLOSSARY OF TERMS

Term	Definition
2005 Permit	December 2005 Title V operating permit issued by the NJDEP for Deepwater
2007 Maryland Rate Order	MPSC order approving new electric service distribution base rates for DPL in Maryland, effective in June 2007
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
AOCL	Accumulated other comprehensive (loss) income
APB	Accounting Principles Board
April 2007 Order	Administrative Order and Notice of Civil Administrative Penalty Assessment concerning Deepwater issued in April 2007 by NJDEP
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
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
EITF	Emerging Issues Task Force
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
FAS	Financial Accounting Standards
FASB	Financial Accounting Standards Board
February 2008 Revocation Order	Administrative Order of Revocation and Notice of Civil Administrative Penalty Assessment concerning Deepwater issued in February 2008 by NJDEP
FERC	Federal Energy Regulatory Commission

i

Term	Definition
FHACA	Flood Hazard Area Control Act
FIN	FASB Interpretation Number
FSP	FASB Staff Position
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
HCl	Hydrogen chloride
HCl Settlement	Settlement agreement between Conectiv Energy and NJDEP to resolve the HCl violations alleged in the February 2008 Revocation Order and the September 2008 Revocation Order
IRS	Internal Revenue Service
ISDA	International Swaps and Derivatives Association
ISONE	Independent System Operator - New England
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
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
September 2008 Revocation Order	Administrative Order of Revocation and Notice of Civil Administrative Penalty Assessment concerning Deepwater issued in September 2008 by NJDEP
SFAS	Statement of Financial Accounting Standards
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
Standard Offer Service revenue or SOS revenue	Revenue Pepco and DPL, respectively, receive for the procurement of energy for its SOS customers
Stipulation	Stipulation of Partial Settlement entered into by NJDEP and Conectiv Energy in May 2009
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
TSP	Total suspended particles
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	48	65	85
Consolidated Statements of Comprehensive Income	3	N/A	N/A	N/A
Consolidated Balance Sheets	4	49	66	86
Consolidated Statements of Cash Flows	6	51	68	88
Notes to Consolidated Financial Statements	7	52	69	89

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

1

PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	(millions of dollars, except per share data)
Operating Revenue
Power Delivery	$	1,095		$	1,297		$	2,467		$	2,592
Competitive Energy		958			1,329			2,097			2,657
Other		12			(108	)		21			(90	)
Total Operating Revenue		2,065			2,518			4,585			5,159
Operating Expenses
Fuel and purchased energy		1,491			1,832			3,378			3,650
Other services cost of sales		82			180			178			360
Other operation and maintenance		237			231			473			450
Depreciation and amortization		95			93			191			184
Other taxes		90			85			181			173
Deferred electric service costs		(57	)		(17	)		(84	)		8
Effect of settlement of Mirant bankruptcy claims		—			—			(14	)		—
Gain on sale of assets		—			—			—			(3	)
Total Operating Expenses		1,938			2,404			4,303			4,822
Operating Income		127			114			282			337
Other Income (Expenses)
Interest and dividend income		2			5			3			12
Interest expense		(96	)		(80	)		(186	)		(161	)
Gain (Loss) from equity investments		2			—			1			(2	)
Other income		4			4			8			10
Other expenses		(1	)		—			(1	)		(1	)
Total Other Expenses		(89	)		(71	)		(175	)		(142	)
Income Before Income Tax Expense		38			43			107			195
Income Tax Expense		13			28			37			81
Net Income		25			15			70			114
Retained Earnings at Beginning of Period		1,257			1,238			1,271			1,193
Dividends Paid on Common Stock (Note 14)		(60	)		(55	)		(119	)		(109	)
Retained Earnings at End of Period	$	1,222		$	1,198		$	1,222		$	1,198
Basic and Diluted Share Information
Weighted average shares outstanding		220			201			220			201
Earnings per share of common stock	$	.11		$	.07		$	.32		$	.57

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

2

PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	(millions of dollars)
Net income	$	25		$	15		$	70		$	114
Gains (losses) on commodity derivatives designated as cash flow hedges:
(Losses) gains arising during period		(26	)		427			(282	)		639
Less: amount of (losses) gains reclassified into income		(108	)		67			(212	)		82
Net gains (losses) on commodity derivatives		82			360			(70	)		557
Losses on Treasury Rate Locks reclassified into income		2			1			3			3
Amortization of gains and losses for prior service costs		(10	)		(5	)		(10	)		(5	)
Other comprehensive income (losses), before taxes		74			356			(77	)		555
Income tax expense (benefit)		31			147			(31	)		227
Other comprehensive income (losses), net of income taxes		43			209			(46	)		328
Comprehensive income	$	68		$	224		$	24		$	442

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

3

PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30, 2009			December 31, 2008
	(millions of dollars)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	120		$	384
Restricted cash equivalents		9			10
Accounts receivable, less allowance for uncollectible accounts of $43 million and $37 million, respectively		1,158			1,392
Inventories		282			333
Derivative assets		83			98
Prepayments of income taxes		238			294
Prepaid expenses and other		165			115
Total Current Assets		2,055			2,626
INVESTMENTS AND OTHER ASSETS
Goodwill		1,411			1,411
Regulatory assets		1,993			2,088
Investment in finance leases held in trust		1,362			1,335
Income taxes receivable		314			191
Restricted cash equivalents		69			108
Assets and accrued interest related to uncertain tax positions		115			178
Derivative assets		29			9
Other		204			215
Total Investments and Other Assets		5,497			5,535
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		13,298			12,926
Accumulated depreciation		(4,737	)		(4,612	)
Net Property, Plant and Equipment		8,561			8,314
TOTAL ASSETS	$	16,113		$	16,475

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

4

PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30, 2009			December 31, 2008
	(millions of dollars, except shares)
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Short-term debt	$	640		$	465
Current maturities of long-term debt and project funding		502			85
Accounts payable and accrued liabilities		658			847
Capital lease obligations due within one year		7			6
Taxes accrued		62			62
Interest accrued		69			71
Liabilities and accrued interest related to uncertain tax positions		4			71
Derivative liabilities		138			144
Other		302			279
Total Current Liabilities		2,382			2,030
DEFERRED CREDITS
Regulatory liabilities		754			893
Deferred income taxes, net		2,306			2,269
Investment tax credits		38			40
Pension benefit obligation		469			626
Other postretirement benefit obligations		447			461
Income taxes payable		186			176
Liabilities and accrued interest related to uncertain tax positions		175			163
Derivative liabilities		79			59
Other		151			184
Total Deferred Credits		4,605			4,871
LONG-TERM LIABILITIES
Long-term debt		4,502			4,859
Transition bonds issued by ACE Funding		385			401
Long-term project funding		18			19
Capital lease obligations		96			99
Total Long-Term Liabilities		5,001			5,378
COMMITMENTS AND CONTINGENCIES (NOTE 14)
EQUITY
Common stock, $.01 par value, 400,000,000 shares authorized, 220,820,630 shares and 218,906,220 shares outstanding, respectively		2			2
Premium on stock and other capital contributions		3,203			3,179
Accumulated other comprehensive loss		(308	)		(262	)
Retained earnings		1,222			1,271
Total Shareholders’ Equity		4,119			4,190
Noncontrolling interest		6			6
Total Equity		4,125			4,196
TOTAL LIABILITIES AND EQUITY	$	16,113		$	16,475

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

5

PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended June 30,
	2009			2008
	(millions of dollars)
OPERATING ACTIVITIES
Net income	$	70		$	114
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		191			184
Gain on sale of assets		—			(3	)
Effect of settlement of Mirant bankruptcy claims		(14	)		—
Non-cash rents received from cross-border energy lease investments under income earned		(27	)		(37	)
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		38			5
Deferred income taxes		82			1
Net unrealized losses (gains) on commodity derivatives accounted for at fair value		49			(31	)
Changes in:
Accounts receivable		224			(201	)
Inventories		23			(58	)
Prepaid expenses		(59	)		(47	)
Regulatory assets and liabilities		(82	)		(9	)
Accounts payable and accrued liabilities		(241	)		229
Pension contributions		(220	)		—
Pension and other postretirement benefit obligations, excluding contributions		63			16
Cash collateral related to derivative activities		(104	)		395
Taxes accrued		19			5
Interest accrued		(2	)		(1	)
Other assets and liabilities		(3	)		7
Net Cash From Operating Activities		7			693
INVESTING ACTIVITIES
Investment in property, plant and equipment		(388	)		(366	)
Proceeds from sale of assets		—			51
Changes in restricted cash equivalents		1			(48	)
Net other investing activities		5			2
Net Cash Used By Investing Activities		(382	)		(361	)
FINANCING ACTIVITIES
Dividends paid on common stock		(119	)		(109	)
Common stock issued for the Dividend Reinvestment Plan		15			14
Issuances of common stock		11			15
Issuances of long-term debt		110			400
Reacquisition of long-term debt		(67	)		(405	)
Issuances of short-term debt, net		175			20
Cost of issuances		(4	)		(11	)
Net other financing activities		(10	)		(20	)
Net Cash From (Used By) Financing Activities		111			(96	)
Net (Decrease) Increase in Cash and Cash Equivalents		(264	)		236
Cash and Cash Equivalents at Beginning of Period		384			55
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	120		$	291
NONCASH ACTIVITIES
Asset retirement obligations associated with removal costs transferred to regulatory liabilities	$	6		$	2
Recoverable pension/other postretirement benefit costs included in regulatory assets	$	(24	)	$	95
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash (received) paid for income taxes, net	$	(66	)	$	76

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 (SOS) 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 “Impact of the Recent Capital and Credit Market Disruptions – 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 June 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). 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 June 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 six months ended June 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 August 6, 2009, the date of issuance of the consolidated financial statements to which these Notes relate.

Change in Accounting Principle

Since PHI’s adoption of Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets”, PHI has conducted its annual impairment review of goodwill as of July 1. After the completion of the July 1, 2009 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.

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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 Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46(R), “Consolidation of Variable Interest Entities” (FIN 46(R)), Pepco Holdings consolidates those variable interest entities where Pepco Holdings or a subsidiary has been determined to be the primary beneficiary. FIN 46(R) 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 FIN 46(R) 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 June 30, 2009, PHI was unable to obtain sufficient information to conduct the analysis required under FIN 46(R) to determine whether these three entities were variable interest entities or if the Pepco Holdings subsidiaries were the primary beneficiary. As a result, Pepco Holdings has applied the scope exemption from the application of FIN 46(R) 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 June 30, 2009 and 2008, were approximately $61 million and $82 million, respectively, of which approximately $59 million and $74 million, respectively, consisted of power purchases under the PPAs. Net purchase activities under the PPAs for the six months ended June 30, 2009 and 2008, were approximately $144 million and $171 million, respectively, of which approximately $131 million and $150 million, respectively, consisted of power purchases under the PPAs. Pepco Holdings does not have 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 six months ended June 30, 2008, were approximately $22 million and $42 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 onshore facilities and one of the PPAs is with an offshore facility. 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 onshore contracts, 2010 for the other two onshore contracts, and 2014 for the offshore contract.

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 could result in delays in the construction of the wind facilities and the operational start dates for these wind facilities. If the wind facilities are not operational by specified dates, DPL has the right to terminate the PPAs.

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DPL concluded that consolidation is not required for any of these PPAs under FIN 46(R). 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 historically has tested its goodwill for impairment annually as of July 1, and whenever an event occurs or circumstances change in the interim that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Factors that may result in an interim impairment test include, but are not limited to: a change in the identified reporting units; an adverse change in business conditions; a 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. PHI performed its annual impairment test as of July 1, 2009 prior to the issuance of the June 30, 2009 Form 10-Q to ensure no impairment charge should be recorded as of June 30, 2009. As described in Note (6), “Goodwill,” no impairment charge has been recorded. As further described above under the heading “Change in Accounting Principle,” after the completion of the July 1, 2009 impairment test, PHI changed the annual impairment testing date to November 1, and will perform its next annual impairment test on November 1, 2009.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in Pepco Holdings’ gross revenues were $77 million and $74 million for the three months ended June 30, 2009 and 2008, respectively and $154 million and $148 million for the six months ended June 30, 2009 and 2008, respectively.

Reclassifications and Adjustments

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

Income Tax Adjustments

During the second quarter of 2009, DPL recorded an adjustment to correct certain income tax errors related to prior periods. The adjustment, which is not considered material, resulted in a decrease in income tax expense of $1 million for the three and six months ended June 30, 2009.

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 an increase in income tax expense of $1 million for the three months ended June 30, 2009, and a decrease in income tax expense of $1 million for the six months ended June 30, 2009.

(3)NEWLY ADOPTED ACCOUNTING STANDARDS

Statement of Financial Accounting Standards (SFAS) No. 141(R), “Business Combinations—a Replacement of FASB Statement No. 141” (SFAS No. 141 (R))

SFAS No. 141(R) replaces FASB Statement No. 141, “Business Combinations,” and retains the fundamental requirements that the acquisition method of accounting be used for all business combinations and for an acquirer to be identified for each business combination. However, SFAS No. 141(R) expands the definition of a business and amends FASB Statement No. 109, “Accounting for Income Taxes,” to require 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.

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On April 1, 2009, the FASB issued FASB Staff Position (FSP) Financial Accounting Standards (FAS) 141(R)-1, “Accounting for Assets and Liabilities Assumed in a Business Combination that Arise from Contingencies” (FSP FAS 141(R)-1), 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. FSP FAS 141(R)-1 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 in accordance with SFAS No. 157. If the acquisition date fair value cannot be determined, then the asset or liability would be measured in accordance with SFAS No. 5, “Accounting for Contingencies,” and FIN No. 14, “Reasonable Estimate of the Amount of Loss.”

SFAS No. 141(R) and the guidance provided in FSP FAS 141(R)-1 applies prospectively to business combinations for which the acquisition date is on or after January 1, 2009. PHI adopted SFAS No. 141(R) on January 1, 2009, and it did not have a material impact on PHI’s overall financial condition, results of operations, or cash flows.

FSP 157-2, “Effective Date of FASB Statement No. 157” (FSP 157-2)

FSP 157-2 deferred the effective date of SFAS No. 157, “Fair Value Measurements,” (SFAS No. 157) for all nonrecurring fair value measurements of non-financial assets and non-financial liabilities until January 1, 2009 for PHI. The adoption of SFAS No. 157 did not have a material impact on the fair value measurements of PHI’s non-financial assets and non-financial liabilities.

SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements—an Amendment of ARB No. 51” (SFAS No. 160)

SFAS No. 160 establishes 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. It clarifies 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.

SFAS No. 160 establishes accounting and reporting standards that require (i) the ownership interests and the related consolidated net income in subsidiaries held by parties other than the parent be clearly identified, labeled, and presented in the consolidated balance sheets within equity, but separate from the parent’s equity, and presented separately on the face of the consolidated statements of income, (ii) the changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for as equity transactions, and (iii) when a subsidiary is deconsolidated, any retained non-controlling equity investment in the former subsidiary must be initially measured at fair value.

SFAS No. 160 is 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 SFAS No. 160, and reclassified $6 million of non-controlling interests from the minority interest line item of its balance sheet to a component of equity. Otherwise, SFAS No. 160 did not have a material impact on PHI’s overall financial condition, results of operations, or cash flows.

SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities—an Amendment of FASB Statement No. 133” (SFAS No. 161)

SFAS No. 161 enhances the disclosure requirements for derivative instruments and hedging activities. Some of the new disclosures include derivative objectives and strategies, derivative volumes by product type, location and gross fair values of derivative assets and liabilities, location and amounts of gains and losses on derivatives and related hedged items, and credit-risk-related contingent features in derivatives.

SFAS No. 161 is effective for financial statement reporting periods beginning January 1, 2009 for PHI. SFAS No. 161 encourages but does not require disclosures for earlier periods presented for comparative purposes at initial adoption. PHI

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adopted the provisions of SFAS No. 161 beginning with its March 31, 2009 financial statements with comparative disclosures for prior periods. The disclosures for the current financial statements are included within Footnote (12), “Derivative Instruments and Hedging Activities.”

FSP Emerging Issues Task Force (EITF) No. 03-6-1, “Determining whether Instruments Granted in Share-Based Payment Transactions are Participating Securities” (FSP EITF 03-6-1)

In June 2008, the FASB issued FSP EITF 03-6-1, which addresses 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) under the two-class method described in SFAS No. 128, “Earnings per Share.”

FSP EITF 03-6-1 is effective for financial reporting periods beginning January 1, 2009 for PHI. All prior period EPS data presented was adjusted retrospectively to conform with the provisions of FSP EITF 03-6-1. As of January 1, 2009, PHI adopted the provisions of FSP EITF 03-6-1 for the presentation of EPS data in the consolidated statements of income and Footnote (11), “Earnings Per Share.” The adoption did not result in a change in the reported EPS for prior periods presented therein.

EITF Issue No. 08-5, “Issuer’s Accounting for Liabilities Measured at Fair Value with a Third Party Credit Enhancement” (EITF 08-5)

In September 2008, the FASB issued EITF 08-5 to provide guidelines for the determination of the unit of accounting for a liability issued with an inseparable third-party credit enhancement when it is measured or disclosed at fair value on a recurring basis. EITF 08-5 applies to entities that incur liabilities with inseparable third-party credit enhancements or guarantees that are recognized or disclosed at fair value. This would include guaranteed debt obligations, 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 is 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.

EITF 08-5 is effective on a prospective basis for reporting periods beginning on and after January 1, 2009 for PHI. As of January 1, 2009, PHI adopted the provisions of EITF 08-5, and it did not have a material impact on PHI’s overall financial condition, results of operations, or cash flows.

EITF Issue No. 08-6, “Equity Method Investment Accounting Consideration” (EITF 08-6)

In November 2008, the FASB issued EITF 08-6 to address 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 an equity method investee’s issuance of shares should be accounted for. The EITF provides that the initial carrying value of an equity method investment can be determined using the accumulation model in SFAS 141(R), “Business Combination (revised 2007),” and other-than-temporary impairments should be recognized in accordance with paragraph 19(h) of Accounting Principles Board Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.”

This EITF is effective for PHI beginning January 1, 2009. As of January 1, 2009, PHI adopted the provisions of EITF 08-6, and concluded that based on its review of equity investments, there is no material impact on PHI’s overall financial condition, results of operations, or cash flows.

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FSP FAS 107-1 and Accounting Principles Board (APB) 28-1, “Interim Disclosures about Fair Value of Financial Instruments” (FSP FAS 107-1 and APB 28-1)

In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1, which require quarterly disclosures of the fair values of financial instruments. This FSP is effective for interim reporting periods ending after June 15, 2009. The disclosures for prior reporting periods are required.

PHI adopted the disclosure requirements in its second quarter 2009 reporting. The primary impact of the new standard is disclosing the fair value of debt issued by PHI and its utilities on a quarterly basis as presented in Footnote (13), “Fair Value Disclosures.”

FSP FAS 157-4, “Determining Whether a Market is Not Active and a Transaction is Not Distressed” (FSP FAS 157-4)

In April 2009, the FASB issued FSP FAS 157-4, which 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. This FSP is effective for interim reporting periods ending after June 15, 2009.

PHI adopted the provisions of this FSP in the second quarter of 2009. The standard would primarily apply 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. FSP FAS 157-4 did not have a material impact on PHI’s overall financial condition, results of operations, or cash flows.

FSP FAS 115-2 and FAS 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments” (FSP FAS 115-2 and FAS 124-2)

In April 2009, the FASB issued FSP FAS 115-2 and FAS 124-2, which provided additional guidance on other-than-temporary impairment (OTTI) of debt and equity securities. They require 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 the provisions of this FSP as of April 1, 2009, and concluded that none of its debt and equity securities investments were within its scope. The FSP, therefore, did not have a material impact on PHI’s overall financial condition, results of operations, or cash flows.

Statement of Financial Accounting Standards (SFAS) No. 165, “Subsequent Events” (SFAS No. 165)

In May 2009, the FASB issued SFAS No. 165 to establish guidelines for the accounting and disclosures of events that occur after the balance sheet reporting date but before the financial statements are issued. The statement has not resulted in any significant changes from U.S. Auditing Standards “AU” 560,Subsequent Events;however, it places the responsibility on the reporting entity and not just the auditors to assess the impact of subsequent events on the financial statements. The statement was effective for interim or annual financial periods ending after June 15, 2009, which for PHI was the second quarter of 2009. PHI addresses subsequent events in Footnote (2), “Significant Accounting Policies.”

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(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

FSP FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets” (FSP FAS 132(R)-1)

In December 2008, the FASB issued FSP FAS 132(R)-1 to provide guidance on an employer’s disclosures about plan assets of a defined benefit pension or other postretirement plan. The required disclosures under this FSP would expand current disclosures under SFAS No. 132(R), “Employers’ Disclosures about Pensions and Other Postretirement Benefits—an amendment of FASB Statements No. 87, 88, and 106,” to be in line with SFAS No. 157 required 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 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 (Level 3 as defined in SFAS No. 157) on changes in the value of plan assets for the period.

The new disclosures are required starting with financial statement reporting periods ending December 31, 2009 for PHI and earlier application is permitted. Comparative disclosures under this provision are not required for earlier periods presented. PHI is evaluating the impact that it will have on PHI’s financial statement footnote disclosures for year end reporting.

Statement of Financial Accounting Standards (SFAS) No. 166, “Accounting for Transfers of Financial Assets—an amendment of SFAS No. 140” (SFAS No. 166)

In June 2009, the FASB issued SFAS No. 166 to remove the concept of a qualifying special-purpose entity (“QSPE”) from SFAS No. 140 and the QSPE scope exception in FIN 46(R). The statement changes 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 it will have on its overall financial condition and financial statements.

Statement of Financial Accounting Standards (SFAS) No. 167, “Consolidation of Variable Interest Entities—an amendment of FIN 46(R)” (SFAS No. 167)

In June 2009, the FASB issued SFAS No. 167 to amend FIN 46(R), Consolidation of Variable Interest Entities, which 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 standard, 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 standard retained the provision in FIN 46(R) 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 provision are encouraged but not required for earlier periods presented. PHI is evaluating the impact that it will have on its overall financial condition and financial statements.

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Statement of Financial Accounting Standards (SFAS) No. 168, “The FASB Accounting Standards Codification^TM and the Hierarchy of Generally Accepted Accounting Principles” (SFAS No. 168)

In June 2009, the FASB issued SFAS No. 168 to identify the sources of accounting principles and the framework for selecting the principles used in the preparation of non-governmental financial statements that are presented under U.S. GAAP. In addition, SFAS No. 168 replaces the current reference system for standards and guidance with a new numerical designation system known as the Codification. The Codification will be the single source reference system for all authoritative non-governmental GAAP. The Codification is numerically organized by topic, subtopic, section, and subsection.

SFAS No. 168 replaces SFAS No. 162,The Hierarchy of Generally Accepted Accounting Principles and is effective for financial statements issued for interim and annual periods ending after September 15, 2009. There is an option to early adopt beginning with interim periods ending after June 15, 2009. PHI has not elected to early adopt and, therefore, the Codification referencing required by SFAS No. 168 will become effective in its September 30, 2009 financial statements. Entities are not required to revise previous financial statements for the change in references.

The adoption of SFAS No. 168 is not expected to result in a change in accounting for PHI. Therefore, the provisions of SFAS No. 168 are not expected to have a material impact on PHI’s overall financial condition, results of operations, or cash flows. However, there will be a change in how accounting standards are referenced in the financial statements.

(5) SEGMENT INFORMATION

Based on the provisions of SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information,” Pepco Holdings’ management has identified its operating segments at June 30, 2009 as Power Delivery, Conectiv Energy, Pepco Energy Services, and Other Non-Regulated. Segment information for the three and six months ended June 30, 2009 and 2008, is as follows:

	Three Months Ended June 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	$	1,095		$	469	(b)	$	560	$	14	$	(73	)	$	2,065
Operating Expense (c)		995	(b)		487			531		1		(76	)		1,938
Operating Income		100			(18	)		29		13		3			127
Interest Income		1			1			1		1		(2	)		2
Interest Expense		53			7			12		3		21			96
Other Income		3			—			—		1		1			5
Income Tax Expense (Benefit)		20			(10	)		8		4		(9	)		13
Net Income (Loss)		31			(14	)		10		8		(10	)		25
Total Assets		10,254			1,995			743		1,516		1,605			16,113
Construction Expenditures	$	149		$	50		$	3	$	—	$	6		$	208

Notes:

(a) Includes unallocated Pepco Holdings’ (parent company) capital costs, such as acquisition financing costs, and the depreciation and amortization 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 $(73) million for Operating Revenue, $(71) million for Operating Expense, $(20) million for Interest Income, and $(19) million for Interest Expense.

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(b) Power Delivery purchased electric energy and capacity and natural gas from Conectiv Energy in the amount of $62 million for the three months ended June 30, 2009.

(c) Includes depreciation and amortization of $95 million, consisting of $79 million for Power Delivery, $10 million for Conectiv Energy, $5 million for Pepco Energy Services, and $1 million for Corp. & Other.

	Three Months Ended June 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	$	1,297		$	789	(b)	$	631	$	(105	)(d)	$	(94	)	$	2,518
Operating Expense (c)		1,144	(b)		748			606		1			(95	)		2,404
Operating Income		153			41			25		(106	)		1			114
Interest Income		3			1			1		1			(1	)		5
Interest Expense		46			6			—		5			23			80
Other Income (Expense)		3			—			1		(1	)		1			4
Income Tax Expense (Benefit)		38			15			11		(27	)(d)		(9	)		28
Net Income (Loss)		75			21			16		(84	)(d)		(13	)		15
Total Assets		10,054			2,431			1,000		1,464			1,417			16,366
Construction Expenditures	$	134		$	44		$	12	$	—		$	5		$	195

Notes:

(a) Includes unallocated Pepco Holdings’ (parent company) capital costs, such as acquisition financing costs, and the depreciation and amortization 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, $(12) million for Interest Income, and $(11) million for Interest Expense.

(b) Power Delivery purchased electric energy and capacity and natural gas from Conectiv Energy in the amount of $87 million for the three months ended June 30, 2008.

(c) Includes depreciation and amortization of $93 million, consisting of $79 million for Power Delivery, $9 million for Conectiv Energy, $3 million for Pepco Energy Services, $1 million for Other Non-Regulated and $1 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.

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	Six Months Ended June 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	$	2,467		$	1,044	(b)	$	1,217	$	27	$	(170	)	$	4,585
Operating Expense (c)		2,253	(b)(d)		1,048			1,173		2		(173	)		4,303
Operating Income		214			(4	)		44		25		3			282
Interest Income		2			1			1		2		(3	)		3
Interest Expense		106			15			16		7		42			186
Other Income		6			—			1		—		1			8
Preferred Stock Dividends		—			—			—		1		(1	)		—
Income Tax Expense (Benefit)		43			(8	)		12		5		(15	)		37
Net Income (Loss)		73			(10	)		18		14		(25	)		70
Total Assets		10,254			1,995			743		1,516		1,605			16,113
Construction Expenditures	$	281		$	91		$	6	$	—	$	10		$	388

Notes:

(a) Includes unallocated Pepco Holdings’ (parent company) capital costs, such as acquisition financing costs, and the depreciation and amortization 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 $(170) million for Operating Revenue, $(165) million for Operating Expense, $(44) million for Interest Income, $(42) 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 $145 million for the six months ended June 30, 2009.

(c) Includes depreciation and amortization of $191 million, consisting of $158 million for Power Delivery, $19 million for Conectiv Energy, $9 million for Pepco Energy Services, $1 million for Other Non-Regulated and $4 million for Corp. & Other.

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

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	Six Months Ended June 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	$	2,592		$	1,612	(b)	$	1,252	$	(87	)(d)	$	(210	)	$	5,159
Operating Expense (c)		2,335	(b)		1,484			1,213		2			(212	)		4,822
Operating Income		257			128			39		(89	)		2			337
Interest Income		9			1			1		2			(1	)		12
Interest Expense		94			12			1		9			45			161
Other Income (Expense)		7			—			2		(3	)		1			7
Preferred Stock Dividends		—			—			—		1			(1	)		—
Income Tax Expense (Benefit)		57			48			16		(26	)(d)		(14	)		81
Net Income (Loss)		122			69			25		(74	)(d)		(28	)		114
Total Assets		10,054			2,431			1,000		1,464			1,417			16,366
Construction Expenditures	$	282		$	59		$	17	$	—		$	8		$	366

Notes:

(a) Includes unallocated Pepco Holdings’ (parent company) capital costs, such as acquisition financing costs, and the depreciation and amortization 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 $(210) million for Operating Revenue, $(207) million for Operating Expense, $(28) million for Interest Income, $(27) 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 $185 million for the six months ended June 30, 2008.

(c) Includes depreciation and amortization of $184 million, consisting of $155 million for Power Delivery, $18 million for Conectiv Energy, $6 million for Pepco Energy Services, $1 million for Other Non-Regulated, and $4 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 six month period ended June 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 SFAS No. 142.

PHI’s July 1, 2009 annual impairment test completed prior to the issuance of the June 30, 2009 Form 10-Q, indicated that its goodwill was not impaired. PHI performed interim impairment tests as of December 31, 2008 and March 31, 2009, as its market capitalization was below book value at December 31, 2008 and its market capitalization declined further below book value at March 31, 2009. PHI concluded that its goodwill was not impaired at both December 31, 2008 and March 31, 2009, and again at June 30, 2009 with the completion of the July 1, 2009 annual impairment test.

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 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 approach to estimate the fair value of Power Delivery since the adoption of SFAS No. 142.

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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 business segments (Conectiv Energy, Pepco Energy Services, Other Non-Regulated, and Corporate & Other) at July 1, 2009. The sum of the fair value of all business segments 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 segments exceeded the market capitalization of PHI at July 1, 2009. PHI believes that the excess of the estimated fair value of PHI’s segments 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 the Power Delivery reporting unit’s business, PHI does not believe the declines in its stock price in recent periods indicate 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 June 30, 2009 and December 31, 2008, Pepco Holdings had cross-border energy lease investments of $1.4 billion and $1.3 billion, 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 two quarters of 2009.

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

	June 30, 2009			December 31, 2008
	(millions of dollars)
Scheduled lease payments, net of non-recourse debt	$	2,281		$	2,281
Less: Unearned and deferred income		(919	)		(946	)
Investment in finance leases held in trust		1,362			1,335
Less: Deferred income taxes		(656	)		(679	)
Net investment in finance leases held in trust	$	706		$	656

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

	Three Months Ended June 30,					Six Months Ended June 30,
	2009		2008			2009		2008
	(millions of dollars)
Pre-tax income from PHI’s cross-border energy lease investments (included in “Other Revenue”)	$	13	$	18		$	27	$	37
Non-cash charge to reduce equity value of PHI’s cross-border energy lease investments		—		(124	)		—		(124	)
Pre-tax income (loss) from PHI’s cross-border energy lease investments after adjustment		13		(106	)		27		(87	)
Income tax expense (benefit)		3		(34	)		7		(29	)
Net income (loss) from PHI’s cross-border energy lease investments	$	10	$	(72	)	$	20	$	(58	)

(8) PENSIONS AND OTHER POSTRETIREMENT BENEFITS

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

	Pension Benefits						Other Postretirement Benefits
	2009			2008			2009			2008
	(millions of dollars)
Service cost	$	9		$	8		$	1		$	2
Interest cost		28			28			10			11
Expected return on plan assets		(23	)		(32	)		(3	)		(6	)
Prior service credit component -		—			—			(1	)		(1	)
Loss component		17			2			6			4
Net periodic benefit cost	$	31		$	6		$	13		$	10

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

	Pension Benefits						Other Postretirement Benefits
	2009			2008			2009			2008
	(millions of dollars)
Service cost	$	18		$	18		$	3		$	4
Interest cost		56			54			20			20
Expected return on plan assets		(51	)		(65	)		(7	)		(8	)
Prior service credit component		—			—			(2	)		(2	)
Loss component		29			5			9			6
Net periodic benefit cost	$	52		$	12		$	23		$	20

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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, $220 million was contributed prior to June 30, 2009, through tax-deductible contributions from Pepco, ACE and DPL in the amounts of $150 million, $60 million and $10 million, respectively. The remaining $80 million contribution was made in July 2009 through tax-deductible contributions from Pepco of $20 million and $60 million from the PHI Service Company. No contributions were made in 2008.

(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.

In November 2008, PHI entered into a second unsecured credit facility in the amount of $400 million with a syndicate of nine lenders. Under the facility, PHI may obtain revolving loans and swingline loans over the term of the facility, which expires on November 6, 2009. 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.”

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 create a cash reserve for future short-term operating needs. At June 30, 2009, PHI had an outstanding loan of $150 million and DPL had an outstanding loan of $50 million under the credit facility. DPL repaid its loan in July 2009.

At June 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 on a consolidated basis totaled $1.5 billion, of which the combined cash and borrowing capacity under the $1.5 billion credit facility of PHI’s utility subsidiaries was $549 million and $843 million, respectively.

Other Financing Activities

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

• In April 2009, Atlantic City Electric Transition Funding LLC (ACE Funding) made principal payments of $5.3 million on Series 2002-1 Bonds, Class A-2, and $2.1 million on Series 2003-1 Bonds, Class A-1.

• In April 2009, Pepco repaid, prior to maturity, a $25 million short-term loan.

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• In April 2009, DPL resold $9 million of its Pollution Control Revenue Refunding Bonds, which previously had been issued for the benefit of DPL by the Delaware Economic Development Authority. These bonds were repurchased by DPL in November 2008 in response to disruption in the tax-exempt bond market that made it difficult for the remarketing agent to successfully remarket the bonds. As the owner of the bonds, DPL received the proceeds of the sale, which it intends to use for general corporate purposes.

• In April 2009, PHI and its utility subsidiaries entered into a $25 million line of credit that can be used by these entities for equipment leasing through February 2010. As of June 30, 2009, $7 million of this line of credit has been utilized.

• In May 2009, DPL repaid, prior to maturity, $50 million of a $150 million short-term loan, which matured in July 2009.

• 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 June 2009, ACE completed the remarketing of approximately $23 million of Pollution Control Revenue Refunding Bonds which previously had been issued for the benefit of ACE by The Pollution Control Financing Authority of Salem County, New Jersey. The bonds were purchased during late 2008 and early 2009 by the Bank of New York Mellon pursuant to a standby bond purchase agreement in response to disruption in the municipal variable rate demand bond market that made it difficult for the remarketing agent to successfully remarket the bonds. The proceeds of the remarketing were used to reimburse the Bank of New York Mellon.

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

In July 2009, 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 $0.7 million on Series 2003-1 Bonds, Class A-2.

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

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 the $15 million Series 2003 A and $18.2 million Series 2003 B Delaware Economic Development Authority tax exempt bonds that were repurchased in 2008 due to the disruptions in the tax exempt capital markets.

In July 2009, ACE redeemed the $25 million Series 2004 A and $6.5 million Series 2004 B Pollution Control Financing Authority of Cape May County tax exempt bonds that were repurchased in 2008 due to the disruptions in the tax exempt capital markets.

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 June 30, 2009, approximately 32% 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 six months ended June 30, 2009, approximately $7 million and $8 million, respectively, of the fees have been amortized.

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In addition to Pepco Energy Service’s 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 June 30, 2009, the Competitive Energy business (including Pepco Energy Service’s retail energy supply business) had posted net cash collateral of $443 million and letters of credit of $182 million. At December 31, 2008, the Competitive Energy business had posted net cash collateral of $331 million and letters of credit of $558 million.

At June 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 $915 million and $684 million, respectively.

(10) INCOME TAXES

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

	For The Three Months Ended June 30,				For The Six Months Ended June 30,
	2009		2008		2009		2008
Federal statutory rate	35.0	%	35.0	%	35.0	%	35.0	%
Increases (decreases) resulting from:
Depreciation	3.7		3.9		2.7		1.7
State income taxes, net of federal effect	5.5		22.2		5.7		9.1
Tax credits	(2.6	)	(2.5	)	(2.0	)	(1.1	)
Leveraged leases	(3.4	)	9.0		(2.5	)	1.1
Change in estimates and interest related to uncertain and effectively settled tax positions	1.1		3.9		(1.8	)	(2.7	)
Interest on state income tax refund, net of federal effect	—		(5.3	)	—		(1.2	)
Permanent differences related to deferred compensation funding	(3.4	)	1.4		(.7	)	1.0
Other, net	(1.7	)	(2.3	)	(1.8	)	(1.5	)
Consolidated Effective Income Tax Rate	34.2	%	65.3	%	34.6	%	41.4	%

PHI’s effective tax rates for the three months ended June 30, 2009 and 2008 were 34.2% and 65.3%, respectively. The decrease in the rate resulted from the second quarter 2008 charge related to the cross-border energy lease investments described in Note (7), and corresponding state tax benefits related to the charge, a 2008 benefit for interest received on a state income tax refund, and a 2009 change in deductions related to deferred compensation funding.

PHI’s effective tax rates for the six months ended June 30, 2009 and 2008 were 34.6% and 41.4%, respectively. The decrease in the rate resulted from the second quarter 2008 charge related to the cross-border energy lease investments described in Note (7) and corresponding state tax benefits related to the charge.

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

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

(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 June 30 ,
	2009		2008
	(millions of dollars, except per share data)
Income (Numerator):
Earnings Applicable to Common Stock	$	25	$	15
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	$	.11	$	.07
Diluted earnings per share of common stock	$	.11	$	.07

Notes:

(a) The number of options to purchase shares of common stock that were excluded from the calculation of diluted EPS as they are considered to be anti-dilutive were 369,904 and 5,000 for the three months ended June 30, 2009 and 2008, respectively.

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	For the Six Months Ended June 30,
	2009		2008
	(millions of dollars, except per share data)
Income (Numerator):
Earnings Applicable to Common Stock	$	70	$	114
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	$	.32	$	.57
Diluted earnings per share of common stock	$	.32	$	.57

Notes:

(a) The number of options to purchase shares of common stock that were excluded from the calculation of diluted EPS as they are considered to be anti-dilutive were 358,366 and 5,000 for the six months ended June 30, 2009 and 2008, respectively.

(12) DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

PHI accounts for its derivative activities in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” (SFAS No. 133) as amended by subsequent pronouncements.

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 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 under SFAS No. 133.

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

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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 under SFAS No. 133.

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 SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” 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.

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

	As of June 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)	$	309		$	1,789		$	2,098		$	(2,015	)	$	83
Derivative Assets (non-current assets)		99			85			184			(155	)		29
Total Derivative Assets		408			1,874			2,282			(2,170	)		112
Derivative Liabilities (current liabilities)		(758	)		(1,782	)		(2,540	)		2,402			(138	)
Derivative Liabilities (non-current liabilities)		(129	)		(100	)		(229	)		150			(79	)
Total Derivative Liabilities		(887	)		(1,882	)		(2,769	)		2,552			(217	)
Net Derivative (Liability) Asset	$	(479	)	$	(8	)	$	(487	)	$	382		$	(105	)

	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	)

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Under FSP FIN 39-1, PHI offsets the fair value amounts recognized for derivative instruments and the fair value amounts recognized for related collateral positions executed with the same counterparty under master netting agreements. The amount of cash collateral that was offset against these derivative positions is as follows:

	June 30, 2009			December 31, 2008
	(millions of dollars)
Cash collateral pledged to counterparties with the right to reclaim (a)	$	393		$	326
Cash collateral received from counterparties with the obligation to return		(11	)		(52	)

(a) Includes cash deposits on commodity brokerage accounts

As of June 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.

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 six months ended June 30, 2009 and 2008 is provided in the tables below:

	Three Months Ended June 30,
	2009			2008
	(millions of dollars)
Amount of net pre-tax (loss) gain arising during the period included in accumulated other comprehensive (loss) income	$	(26	)	$	427
Amount of net pre-tax (loss) gain reclassified into income:
Effective portion:
Competitive Energy Revenue		27			26
Fuel and Purchased Energy		(138	)		34
Total		(111	)		60
Ineffective portion:
Competitive Energy Revenue		—			4
Fuel and Purchased Energy		3			3
Total		3			7
Total net (loss) gain reclassified into income		(108	)		67
Net pre-tax gain on commodity derivatives included in other comprehensive (loss) income	$	82		$	360

Included in the above table is a loss of $1 million for the three months ended June 30, 2009, which was reclassified from AOCL to income because the forecasted hedged transactions were deemed no longer probable.

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	Six Months Ended June 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)	$	(282	)	$	639
Amount of net (loss) gain reclassified into income:
Effective portion:
Competitive Energy Revenue		31			44
Fuel and Purchased Energy		(240	)		28
Total		(209	)		72
Ineffective portion:
Competitive Energy Revenue		(1	)		1
Fuel and Purchased Energy		(2	)		9
Total		(3	)		10
Total net (loss) gain reclassified into income		(212	)		82
Net pre-tax (loss) gain on commodity derivatives included in other comprehensive (loss) income	$	(70	)	$	557

(a) Included in the $282 million loss is a $4 million loss realized on the derivative transaction but not yet recognized into income.

Included in the above table is a loss of $3 million for the six months ended June 30, 2009, which was reclassified from AOCL to income because the forecasted hedged transactions were deemed no longer probable.

As of June 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	June 30, 2009	December 31, 2008
Forecasted Purchases Hedges
Coal (Tons)	195,000	120,000
Natural gas (One Million British Thermal Units (MMBtu))	91,662,500	85,034,233
Electricity (Megawatt hours (MWh))	25,048,685	27,856,037
Electric capacity (MW-Days)	480,000	1,400,400
Heating oil (Barrels)	170,000	128,000
Forecasted Sales Hedges
Coal (Tons)	150,000	—
Electricity (MWh)	15,777,659	19,808,191
Electric capacity (MW-Days)	231,240	308,220
Financial transmission rights (MWh)	25,776	—

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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 gains and losses related to hedging activities, are deferred under SFAS No. 71 until recovered based on the fuel adjustment clause approved by the DPSC. The following table indicates the amounts deferred as regulatory assets or liabilities and the location in the consolidated statements of income of amounts reclassified to income through the fuel adjustment clause for the three and six months ended June 30, 2009 and 2008:

	Three Months Ended June 30,					Six Months Ended June 30,
	2009			2008		2009			2008
	(millions of dollars)
Net Gain Deferred as a Regulatory Asset/Liability	$	11		$	4	$	11		$	10
Net (Loss) Gain Reclassified from Regulatory Asset/Liability to Fuel and Purchased Energy Expense		(10	)		2		(26	)		1

As of June 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	June 30, 2009	December 31, 2008
Forecasted Purchases Hedges:
Natural Gas (MMBtu)	8,225,000	10,805,000

Cash Flow Hedges Included in Accumulated Other Comprehensive Loss

The table below provides details regarding effective cash flow hedges under SFAS No. 133 included in PHI’s consolidated balance sheet as of June 30, 2009. Under SFAS No. 133, 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)	$	(269	)	$	(113	)	59 months
Interest Rate		(23	)		(3	)	278 months
Total	$	(292	)	$	(116	)

(a) Accumulated Other Comprehensive Loss on PHI’s consolidated balance sheet as of June 30, 2009, includes a $16 million balance related to minimum pension liability. 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 SFAS No. 133 Paragraph 10 (b), 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 six months ended June 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 June 30,										Six Months Ended June 30,
	2009			2008			2009		2008		2009			2008			2009			2008
	(millions of dollars)
Competitive Energy Revenue	$	(4	)	$	(19	)	$	5	$	16	$	(4	)	$	(27	)	$	5		$	24
Fuel and Purchased Energy Expense		(1	)		(5	)		1		5		1			(8	)		(1	)		8
Total	$	(5	)	$	(24	)	$	6	$	21	$	(3	)	$	(35	)	$	4		$	32

As of June 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	June 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 SFAS No. 133, these derivatives are recorded at fair value through income with corresponding adjustments on the balance sheet.

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

	Three Months Ended June 30, 2009								Three Months Ended June 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 (losses) gains	$	(15	)	$	2	$	(13	)	$	46	$	(39	)	$	7
Unrealized mark-to-market (losses) gains		(9	)		—		(9	)		3		—			3
Total net mark-to-market (losses) gains	$	(24	)	$	2	$	(22	)	$	49	$	(39	)	$	10

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	Six Months Ended June 30, 2009									Six Months Ended June 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)	$	48		$	(14	)	$	34		$	109	$	(84	)	$	25
Unrealized mark-to-market (losses) gains		(49	)		—			(49	)		31		—			31
Total net mark-to-market (losses) gains	$	(1	)	$	(14	)	$	(15	)	$	140	$	(84	)	$	56

As of June 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:

	June 30, 2009		December 31, 2008
Commodity	Quantity	Net Position	Quantity	Net Position
Coal (Tons)	160,000	Long	30,000	Short
Natural gas (MMBtu)	5,404,943	Long	578,443	Short
Natural gas basis (MMBtu)	12,877,500	Long	18,300,000	Long
Heating oil (Barrels)	189,000	Short	556,000	Short
#6 Oil (Barrels)	75,000	Short	—	—
Light sweet crude oil (Barrels)	—	—	361,988	Short
RBOB UL gasoline (Barrels)	39,000	Short	67,000	Short
Electricity (MWh)	359,505	Short	287,159	Short
Financial transmission rights (MWh)	1,114,916	Long	3,986,759	Long

Power Delivery

DPL holds certain derivatives that do not qualify as hedges. Under SFAS No. 133, these derivatives are recorded at fair value on the balance sheet with the gain or loss recorded in income. In accordance with SFAS No. 71, offsetting regulatory assets or regulatory liabilities are recorded on the balance sheet and the recognition of the gain or recovery of the loss is deferred. For the three and six months ended June 30, 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 June 30,					Six Months Ended June 30,
	2009			2008		2009			2008
	(millions of dollars)
Gain (Loss) Deferred as a Regulatory Asset/Liability	$	4		$	12	$	(10	)	$	16
Gain (Loss) Reclassified from Regulatory Asset/Liability to Fuel and Purchased Energy Expense		(2	)		—		(5	)		—

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

	June 30, 2009		December 31, 2008
Commodity	Quantity	Net Position	Quantity	Net Position
Natural Gas (MMBtu)	10,727,069	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 under SFAS No. 133. 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 June 30, 2009, was $475 million. As of that date, PHI had posted cash collateral of $42 million in the normal course of business against the gross derivative liability resulting in a net liability of $433 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 June 30, 2009, would have been approximately $295 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 June 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 $1.5 billion, of which $915 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 SFAS No. 157 which established a framework for measuring fair value and expanded disclosures about fair value measurements.

As defined in SFAS No. 157, 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

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minimize the use of unobservable inputs. PHI is able to classify fair value balances based on the observability of those inputs. SFAS No. 157 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 defined by SFAS No. 157 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 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 June 30, 2009 and December 31, 2008. As required by SFAS No. 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. PHI’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

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	Fair Value Measurements at June 30, 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	$	102	$	8		$	74	(a)	$	20
Cash equivalents		174		174			—			—
Executive deferred compensation plan assets		71		11			41			19
	$	347	$	193		$	115		$	39
LIABILITIES
Derivative instruments	$	587	$	226	(b)	$	322		$	39
Executive deferred compensation plan liabilities		30		—			30			—
	$	617	$	226		$	352		$	39

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

(b) Includes a contra-liability balance of $13 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

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

	Six Months Ended June 30, 2009
	Net Derivative Instruments Assets (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		4			2
Included in accumulated other comprehensive (loss) income		9			—
Included in regulatory liabilities		(15	)		—
Purchases and issuances		—			(1	)
Settlements		5			—
Transfers in and/or out of Level 3		—			—
Ending balance as of June 30, 2009	$	(19	)	$	19

	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	$	4	$	2
Change in unrealized gains (losses) relating to assets still held at reporting date	$	4	$	2

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	Six Months Ended June 30, 2008
	Net Derivative Instruments Assets (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		15			2
Included in accumulated other comprehensive (loss) income		4			—
Included in regulatory liabilities		16			—
Purchases and issuances		—			(1	)
Settlements		(1	)		—
Transfers in and/or out of Level 3		(10	)		—
Ending balance as of June 30, 2008	$	21		$	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	$	15		$	2
Change in unrealized gains (losses) relating to assets still held at reporting date	$	15		$	2

Fair Value of Debt Instruments

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

	June 30, 2009				December 31, 2008
	(millions of dollars)
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	4,969	$	5,036	$	4,910	$	4,736
Transition Bonds issued by ACE Funding		418		434		433		431
Long-Term Project Funding		20		20		21		21
Redeemable Serial Preferred Stock		6		4		6		4

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

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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 will distribute 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 expects to record a pre-tax gain between $26 million and $28 million in the quarter ending September 30, 2009.

As of June 30, 2009, approximately $64 million in remaining proceeds from the Mirant settlement was accounted for as restricted cash and as a regulatory liability. In the third quarter of 2009, the restricted cash will be released and the regulatory liability will be extinguished as a consequence of the MPSC order.

Rate Proceedings

In recent electric service and natural gas distribution base rate cases, PHI’s utility subsidiaries have proposed the adoption of a bill stabilization adjustment mechanism (BSA) for retail customers. To date:

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

• A method of revenue decoupling similar to a BSA, referred to as a modified fixed variable rate design (MFVRD), has been approved for DPL electric and natural gas service in Delaware, which will be implemented in the context of DPL’s next Delaware base rate case.

• A proposed BSA remains pending for Pepco in the District of Columbia and ACE in New Jersey.

Under the BSA, customer delivery rates are subject to adjustment (through a surcharge or credit 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

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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. 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 Hearing Examiner’s report recommending approval of the settlement agreement was issued on July 21, 2009. DPSC approval of the settlement agreement is pending.

On June 25, 2009, DPL filed two applications requesting approval 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.

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 January 2, 2009, the DCPSC issued an order designating the issues and establishing a procedural schedule for the BSA proceeding. Hearings were held on May 12, 2009, followed by post-hearing briefs filed on May 29, 2009 and June 12, 2009. A decision by the DCPSC is pending.

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. Pepco expects a decision by the end of the third quarter 2009.

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, if the BSA is approved in Phase II of the rate case filed in December 2006, 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.

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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 each appealed the MPSC’s July 2007, July 2008 and August 2008 orders. The case currently is pending before the Circuit Court for Baltimore City, which issued an order consolidating the appeals on January 27, 2009. 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. The MPSC and OPC filed briefs on April 23, 2009 and oral arguments were held on May 12, 2009. A decision by the Circuit Court is pending.

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 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 $4 million. Hearings are scheduled for September 21 through September 24, 2009, with a decision expected from the MPSC 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. Under New Jersey law, the NJBPU is required to approve, modify or deny the application within 180 days. The NJBPU has advised ACE that the 180-day period commenced on February 23, 2009 and, therefore, unless otherwise extended by the parties by consent, ACE anticipates that NJBPU will act on ACE’s application by late August 2009.

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 June 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.

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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 June 30, 2009), as well as its District of Columbia jurisdictional transmission and distribution-related ADITC balance ($3 million as of June 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.

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 are 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.

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

General Litigation

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

Since the initial filings in 1993, additional individual suits have been filed against Pepco, and significant numbers of cases have been dismissed. As a result of two motions to dismiss, numerous hearings and meetings and one motion for summary judgment, Pepco has had approximately 400 of these cases successfully dismissed with prejudice, either voluntarily by the plaintiff or by the court. As of June 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

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

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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.

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 the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA), and that the sales transactions may have constituted an arrangement for the disposal or treatment of hazardous substances at the site, which could be a basis for liability under CERCLA. The EPA’s letter also states that as of the date of the letter, EPA’s expenditures for response measures at the site exceed $6 million. EPA estimates approximately $6 million as the cost for future response measures it recommends. ACE understands that the EPA sent similar general notice letters to three other companies and various individuals.

ACE believes that the B.L. England boiler slag sold to MDC was a valuable material with various industrial applications, and therefore, the sale was not an arrangement for the disposal or treatment of any hazardous substances as would be necessary to constitute a basis for liability under CERCLA. ACE intends to contest any 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 is helpful to 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 alleges that Pepco arranged for disposal or treatment of hazardous substances sent to 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.

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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. ACE, DPL and Pepco have not yet been served with the complaint.

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 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 resolved Conectiv Energy’s challenge to the 2005 and 2008 Permits’ provision limiting annual fuel use in favor of Conectiv Energy and resolved Conectiv Energy’s challenge to an annual stack test requirement in favor of NJDEP. 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 had resolved. 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 recommended decision incorporating its October 2007 order (as amended July 23, 2009) and the Stipulation, and transmitting the matter back to the NJDEP Commissioner for a final decision adopting, rejecting or modifying the OAL recommended decision. The OAL’s July 29 recommended decision resolves all of the outstanding issues that were the subject of Conectiv Energy appeals, subject to the final decision from the NJDEP Commissioner.

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.

In February 2008, NJDEP issued an Administrative Order of Revocation and Notice of Civil Administrative Penalty Assessment (the February 2008 Revocation Order) revoking the 2008 Permit. The February 2008 Revocation Order contended that Deepwater Unit 6/8 operated in violation of its emission limit for hydrogen chloride (HCl) and total suspended particles (TSP) during a December 2007 stack test, and assessed a $20,000 penalty for the alleged HCl incident and a $10,000 penalty for the alleged TSP incident. In September 2008, NJDEP issued an Administrative Order of Revocation and Notice of Civil Administrative Penalty Assessment (the September 2008 Revocation Order) requiring Conectiv Energy to operate Deepwater Unit 6/8 in compliance with its HCl limit or in the alternative revoking Unit 6/8’s 2008 Permit. The September 2008 Revocation Order contended that Unit 6/8 violated the HCl limit on 106 days between December 2007 and April 2008 stack tests, and assessed a penalty of approximately $5 million. Conectiv Energy filed timely appeals of the February 2008 Revocation Order and the September 2008 Revocation Order with the OAL. In January 2009, Conectiv Energy and NJDEP entered into a settlement agreement with the NJDEP to resolve the $10,000 penalty for the TSP violations alleged in the February 2008 Revocation Order (the TSP Settlement). Under the terms of the TSP Settlement, NJDEP agreed to not assess an additional $16,000 administrative penalty for an alleged violation of the TSP limit during an April 4, 2008 stack test and Conectiv Energy agreed to pay a $20,800 penalty. On May 29, 2009, Conectiv Energy entered into a settlement agreement with NJDEP to resolve the HCl violations alleged in the February

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2008 Revocation Order and the September 2008 Revocation Order (the HCl Settlement). Under the terms of the HCl Settlement, Deepwater Unit 6/8 is required to (1) utilize hydrated lime injection technology to control HCl emissions, (2) comply with the agreed upon hourly HCl emission limit, (3) demonstrate compliance with that limit for each stack test run without averaging stack test results, and (4) pay a $500,000 penalty. Conectiv Energy paid the $500,000 penalty on June 16, 2009. Subsequent stack tests have confirmed that Unit 6/8 currently complies with its TSP and HCl limits.

In July 2008, NJDEP issued an Administrative Order of Revocation and Notice of Civil Administrative Penalty Assessment (the July 2008 Revocation Order) revoking the 2008 Permit. The July 2008 Revocation Order contended that Deepwater Unit 6/8 operated in violation of its emission limit for particulate matter less than 10 microns (PM-10) during the December 2007 stack test and assessed a $10,000 penalty. Conectiv Energy filed a timely appeal of the July 2008 Revocation Order with the OAL. Conectiv Energy believes that it has strong legal arguments that NJDEP cannot revoke the permit prior to an administrative hearing and believes that the probability of a complete shut-down of the unit is low because Unit 6/8 stack tests subsequently have demonstrated compliance with the PM-10 limit. In addition, Conectiv Energy has asserted a statutory affirmative defense to liability for penalties stating that the December 2007 elevated PM-10 emissions during stack testing were the result of an equipment malfunction. The July 2008 Revocation Order has been stayed by the NJDEP through September 1, 2009.

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 June 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 June 30, 2009, PHI has derived approximately $488 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, which includes the effect of the reassessment discussed below.

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 will be forwarded to the Appeals Office in the near future.

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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 FIN 48, “Accounting for Uncertainty in Income Taxes,” 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 FSP 13-2, “Accounting for a Change in the Timing of Cash Flows Relating to Income Taxes Generated by a Leveraged-lease Transaction,” 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) under FSP 13-2 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 under FIN 48 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 FSP 13-2 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.

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 approximately $346 million consisting of a non-cash charge of $324 million ($293 million after tax) under FSP 13-2 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 under FIN 48 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 (including the $458 million of tax benefits received from 2001 to date) and $63 million of interest (which amounts include $107 million of federal and state income taxes and $10 million of interest referred to earlier in relation to the charge recorded).

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As of June 30, 2009, no changes in the assumptions have occurred that would materially impact the June 30, 2008 estimates.

In the event of the total disallowance of the tax benefits and the imputing of original issue discount income due to the recharacterization of the leases as loans, as of June 30, 2009, PHI would have been obligated to pay approximately $522 million in additional federal and state taxes and $94 million of interest. In addition, the IRS could require PHI to pay a penalty of up to 20% on the amount of additional taxes due. PHI anticipates that any additional taxes that it would be required to pay as a result of the disallowance of prior deductions or a recharacterization of the leases as loans would be recoverable in the form of lower taxes over the remaining term of the investments.

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 has not responded to the global settlement offer.

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.

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.

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

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

As of June 30, 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)	$	175	$	—	$	—	$	—	$	175
Energy procurement obligations of Pepco Energy Services (a)		592		—		—		—		592
Guaranteed lease residual values (b)		—		3		2		1		6
Other (c)		1		—		—		1		2
Total	$	768	$	3	$	2	$	2	$	775

(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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PEPCO HOLDINGS

(b) Subsidiaries of Pepco Holdings have guaranteed residual values in excess of fair value of certain equipment and fleet vehicles held through lease agreements. As of June 30, 2009, obligations under the guarantees were approximately $6 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) Other guarantees consist of:

• 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.

• PCI has guaranteed facility rental obligations related to contracts entered into by Starpower Communications, LLC, a joint venture in which PCI prior to December 2004 had a 50% interest. As of June 30, 2009, the guarantees cover the remaining rental obligations of less than $1 million.

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

Dividends

On July 23, 2009, Pepco Holdings’ Board of Directors declared a dividend on common stock of 27 cents per share payable September 30, 2009, to shareholders of record on September 10, 2009.

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POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	(millions of dollars)
Operating Revenue	$	518		$	539		$	1,095		$	1,064
Operating Expenses
Purchased energy		273			294			622			602
Other operation and maintenance		81			77			160			147
Depreciation and amortization		37			35			72			69
Other taxes		74			69			147			139
Effect of settlement of Mirant bankruptcy claims		—			—			(14	)		—
Total Operating Expenses		465			475			987			957
Operating Income		53			64			108			107
Other Income (Expenses)
Interest and dividend income		—			2			1			6
Interest expense		(25	)		(23	)		(50	)		(47	)
Other income		3			2			5			5
Other expenses		(1	)		—			(1	)		(1	)
Total Other Expenses		(23	)		(19	)		(45	)		(37	)
Income Before Income Tax Expense		30			45			63			70
Income Tax Expense		13			14			27			24
Net Income		17			31			36			46
Retained Earnings at Beginning of Period		643			592			624			597
Dividends Paid to Parent		—			—			—			(20	)
Retained Earnings at End of Period	$	660		$	623		$	660		$	623

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

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POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

(Unaudited)

	June 30, 2009			December 31, 2008
	(millions of dollars)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	69		$	146
Accounts receivable, less allowance for uncollectible accounts of $14 million and $15 million, respectively		359			377
Inventories		46			45
Prepayments of income taxes		67			151
Prepaid expenses and other		22			37
Total Current Assets		563			756
INVESTMENTS AND OTHER ASSETS
Regulatory assets		154			169
Prepaid pension expense		280			142
Investment in trust		24			24
Restricted cash equivalents		64			102
Income taxes receivable		194			166
Assets and accrued interest related to uncertain tax positions		4			35
Other		72			70
Total Investments and Other Assets		792			708
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		5,726			5,607
Accumulated depreciation		(2,428	)		(2,371	)
Net Property, Plant and Equipment		3,298			3,236
TOTAL ASSETS	$	4,653		$	4,700

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

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POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

(Unaudited)

	June 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		150		187
Accounts payable due to associated companies		64		70
Capital lease obligations due within one year		7		6
Taxes accrued		42		44
Interest accrued		18		19
Liabilities and accrued interest related to uncertain tax positions		—		38
Other		133		94
Total Current Liabilities		430		633
DEFERRED CREDITS
Regulatory liabilities		205		239
Deferred income taxes, net		794		788
Investment tax credits		9		10
Other postretirement benefit obligation		49		49
Income taxes payable		133		137
Other		78		65
Total Deferred Credits		1,268		1,288
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		661		611
Retained earnings		660		624
Total Equity		1,321		1,235
TOTAL LIABILITIES AND EQUITY	$	4,653	$	4,700

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

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POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended June 30,
	2009			2008
	(millions of dollars)
OPERATING ACTIVITIES
Net income	$	36		$	46
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		72			69
Effect of settlement of Mirant bankruptcy claims		(14	)		—
Changes in restricted cash related to Mirant		38			5
Deferred income taxes		18			37
Changes in:
Accounts receivable		18			(22	)
Regulatory assets and liabilities, net		(11	)		(33	)
Accounts payable and accrued liabilities		(40	)		53
Pension contributions		(150	)		—
Interest accrued		(1	)		—
Taxes accrued		91			(15	)
Other assets and liabilities		19			5
Net Cash From Operating Activities		76			145
INVESTING ACTIVITIES
Investment in property, plant and equipment		(130	)		(121	)
Changes in restricted cash		—			(17	)
Net other investing activities		1			—
Net Cash Used By Investing Activities		(129	)		(138	)
FINANCING ACTIVITIES
Dividends paid to Parent		—			(20	)
Capital contribution from Parent		50			78
Issuances of long-term debt		110			250
Reacquisition of long-term debt		(50	)		(188	)
Repayments of short-term debt, net		(125	)		(114	)
Net other financing activities		(9	)		(16	)
Net Cash Used by Financing Activities		(24	)		(10	)
Net Decrease in Cash and Cash Equivalents		(77	)		(3	)
Cash and Cash Equivalents at Beginning of Period		146			19
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	69		$	16
NONCASH ACTIVITIES
Asset retirement obligations associated with removal costs transferred to regulatory liabilities	$	3		$	5
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash (received) paid for income taxes (includes payments to PHI for Federal income taxes)	$	(86	)	$	2

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). 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 June 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 six months ended June 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 August 6, 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 six months ended June 30, 2008 were approximately $22 million and $42 million, respectively.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in Pepco’s gross revenues were $62 million and $58 million for the three months ended June 30, 2009 and 2008, respectively and $123 million and $115 million for the six months ended June 30, 2009 and 2008, respectively.

Reclassifications

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

In the second quarter of 2008, Pepco recorded an adjustment to correct errors in other operation and maintenance expenses for prior periods where late payment fees were incorrectly recognized. This adjustment resulted in an increase in other operation and maintenance expenses for the three and six months ended June 30, 2008 of $4 million and $3 million, respectively. These adjustments were not considered material.

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(3)NEWLY ADOPTED ACCOUNTING STANDARDS

Statement of Financial Accounting Standards (SFAS) No. 141(R), “Business Combinations—a Replacement of FASB Statement No. 141” (SFAS No. 141 (R))

SFAS No. 141(R) replaces Financial Accounting Standards Board (FASB) Statement No. 141, “Business Combinations,” and retains the fundamental requirements that the acquisition method of accounting be used for all business combinations and for an acquirer to be identified for each business combination. However, SFAS No. 141(R) expands the definition of a business and amends FASB Statement No. 109, “Accounting for Income Taxes,” to require 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 FASB Staff Position (FSP) Financial Accounting Standards (FAS) 141(R)-1, “Accounting for Assets and Liabilities Assumed in a Business Combination that Arise from Contingencies” (FSP FAS 141(R)-1), 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. FSP FAS 141(R)-1 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 in accordance with SFAS No. 157. If the acquisition date fair value cannot be determined, then the asset or liability would be measured in accordance with SFAS No. 5, “Accounting for Contingencies,” and FASB Interpretation Number 14, “Reasonable Estimate of the Amount of Loss.”

SFAS No. 141(R) and the guidance provided in FSP FAS 141(R)-1 applies prospectively to business combinations for which the acquisition date is on or after January 1, 2009. Pepco adopted SFAS No. 141(R) on January 1, 2009, and it did not have a material impact on Pepco’s overall financial condition, results of operations, or cash flows.

FSP 157-2, “Effective Date of FASB Statement No. 157” (FSP 157-2)

FSP 157-2 deferred the effective date of SFAS No. 157, “Fair Value Measurements,” (SFAS No. 157) for all nonrecurring fair value measurements of non-financial assets and non-financial liabilities until January 1, 2009 for Pepco. The adoption of SFAS No. 157 did not have a material impact on the fair value measurements of Pepco’s non-financial assets and non-financial liabilities.

SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements—an Amendment of ARB No. 51” (SFAS No. 160)

SFAS No. 160 establishes 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. It clarifies 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.

SFAS No. 160 establishes accounting and reporting standards that require (i) the ownership interests and the related consolidated net income in subsidiaries held by parties other than the parent be clearly identified, labeled, and presented in the consolidated balance sheets within equity, but separate from the parent’s equity, and presented separately on the face of the consolidated statements of income, (ii) the changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for as equity transactions, and (iii) when a subsidiary is deconsolidated, any retained non-controlling equity investment in the former subsidiary must be initially measured at fair value.

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SFAS No. 160 is 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 SFAS No. 160, and the provisions did not have a material impact on Pepco’s overall financial condition, results of operations, or cash flows.

FSP FAS 107-1 and Accounting Principles Board (APB) 28-1, “Interim Disclosures about Fair Value of Financial Instruments” (FSP FAS 107-1 and APB 28-1)

In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1, which require quarterly disclosures of the fair values of financial instruments. This FSP is effective for interim reporting periods ending after June 15, 2009. The disclosures for prior reporting periods are required.

Pepco adopted the disclosure requirements in its second quarter 2009 reporting. The primary impact of the new standard is disclosing the fair value of debt issued by Pepco on a quarterly basis as presented in Footnote (9), “Fair Value Disclosures.”

Statement of Financial Accounting Standards (SFAS) No. 165, “Subsequent Events” (SFAS No. 165)

In May 2009, the FASB issued SFAS No. 165 to establish guidelines for the accounting and disclosures of events that occur after the balance sheet reporting date but before the financial statements are issued. The statement has not resulted in any significant changes from U.S. Auditing Standards “AU” 560,Subsequent Events;however, it places the responsibility on the reporting entity and not just the auditors to assess the impact of subsequent events on the financial statements. The statement was effective for interim or annual financial periods ending after June 15, 2009, which for Pepco was the second quarter of 2009. Pepco addresses subsequent events in Footnote (2), “Significant Accounting Policies.”

(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Statement of Financial Accounting Standards (SFAS) No. 166, “Accounting for Transfers of Financial Assets – an amendment of SFAS No. 140” (SFAS No. 166)

In June 2009, the FASB issued SFAS No. 166 to remove the concept of a qualifying special-purpose entity (“QSPE”) from SFAS No. 140 and the QSPE scope exception in FASB Interpretation Number 46(R). The statement changes requirements for de-recognizing 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 it will have on its overall financial condition and financial statements.

Statement of Financial Accounting Standards (SFAS) No. 168, “The FASB Accounting Standards Codification^TM and the Hierarchy of Generally Accepted Accounting Principles” (SFAS No. 168)

In June 2009, the FASB issued SFAS No. 168 to identify the sources of accounting principles and the framework for selecting the principles used in the preparation of non-governmental financial statements that are presented under U.S. GAAP. In addition, SFAS No. 168 replaces the current reference system for standards and guidance with a new numerical designation system known as the Codification. The Codification will be the single source reference system for all authoritative non-governmental GAAP. The Codification is numerically organized by topic, subtopic, section, and subsection.

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SFAS No. 168 replaces SFAS No. 162,The Hierarchy of Generally Accepted Accounting Principles and is effective for financial statements issued for interim and annual periods ending after September 15, 2009. There is an option to early adopt beginning with interim periods ending after June 15, 2009. Pepco has not elected to early adopt and, therefore, the Codification referencing required by SFAS No. 168 will become effective in its September 30, 2009 financial statements. Entities are not required to revise previous financial statements for the change in references.

The adoption of SFAS No. 168 is not expected to result in a change in accounting for Pepco. Therefore, the provisions of SFAS No. 168 are not expected to have a material impact on Pepco’s overall financial condition, results of operations, or cash flows. However, there will be a change in how accounting standards are referenced in the financial statements.

(5) SEGMENT INFORMATION

In accordance with SFAS No. 131 “Disclosures about Segments of an Enterprise and Related Information,” 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 June 30, 2009 before intercompany allocations from the PHI Service Company, of $44 million includes $11 million for Pepco’s allocated share. PHI’s pension and other postretirement net periodic benefit cost for the six months ended June 30, 2009 of $75 million includes $19 million for Pepco’s allocated share. PHI’s pension and other postretirement net periodic benefit cost for the three months ended June 30, 2008, of $17 million, before intercompany allocations, included $6 million for Pepco’s allocated share. PHI’s pension and other postretirement net periodic benefit cost for the six months ended June 30, 2008 of $32 million includes $12 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.

Pepco historically has issued commercial paper to meet its short-term working capital requirements. As a result of disruptions in the commercial paper markets in 2008, Pepco has borrowed under the credit facility to create a cash reserve for future short-term operating needs. At March 31, 2009, Pepco had an outstanding loan of $100 million. The loan was repaid at maturity in April 2009.

At June 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 $549 million and $843 million, respectively.

Other Financing Activity

During the three months ended June 30, 2009, the following financing activity occurred:

In April 2009, Pepco repaid, prior to maturity, a $25 million short-term loan.

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(8) INCOME TAXES

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

	For The Three Months Ended June 30,				For The Six Months Ended June 30,
	2009		2008		2009		2008
Federal statutory rate	35.0	%	35.0	%	35.0	%	35.0	%
Increases (decreases) resulting from:
Depreciation	4.0		2.9		4.0		3.8
Asset removal costs	(2.0	)	(1.3	)	(1.7	)	(3.1	)
State income taxes, net of federal effect	6.0		5.5		5.9		6.1
Software amortization	1.3		1.1		1.3		1.5
Tax credits	(1.3	)	(1.1	)	(1.4	)	(1.4	)
Change in estimates and interest related to uncertain and effectively settled tax positions	4.0		(6.1	)	2.7		(4.9	)
Interest on state income tax refund, net of federal effect	—		(5.0	)	—		(3.2	)
Permanent differences related to deferred compensation funding	(1.0	)	—		(.8	)	.8
Other, net	(2.7	)	.1		(2.1	)	(.2	)
Effective Income Tax Rate	43.3	%	31.1	%	42.9	%	34.4	%

Pepco’s effective tax rates for the three months ended June 30, 2009 and 2008 were 43.3% and 31.1%, respectively. The increase in the rate resulted from the change in estimates and interest related to uncertain tax positions. During the second quarter of 2008, there was a reduction in previously accrued interest and estimates resulting from the settlement of the mixed service cost issue (see Footnote (10), “Commitments and Contingencies” for additional discussion) and a benefit was recorded for interest received on a state income tax refund.

Pepco’s effective tax rates for the six months ended June 30, 2009 and 2008 were 42.9% and 34.4%, respectively. The increase in the rate resulted from the change in estimates and interest related to uncertain tax positions. During the second quarter of 2008, there was a reduction in previously accrued interest and estimates resulting from the settlement of the mixed service cost issue and a benefit was recorded for interest received on a 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.

(9) FAIR VALUE DISCLOSURES

Fair Value of Assets and Liabilities Excluding Debt

Effective January 1, 2008, Pepco adopted SFAS No. 157 which established a framework for measuring fair value and expanded disclosures about fair value measurements.

As defined in SFAS No. 157, 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

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those inputs. SFAS No. 157 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 defined by SFAS No. 157 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. 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 June 30, 2009 and December 31, 2008. As required by SFAS No. 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Pepco’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Fair Value Measurements at June 30, 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	$	89	$	89	$	—	$	—
Executive deferred compensation plan assets		60		7		35		18
	$	149	$	96	$	35	$	18
LIABILITIES
Executive deferred compensation plan liabilities	$	13	$	—	$	13	$	—
	$	13	$	—	$	13	$	—

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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	$	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	$	—

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

	Six Months Ended June 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		2
Included in accumulated other comprehensive (losses) income		—
Purchases and issuances		(1	)
Settlements		—
Transfers in and/or out of Level 3		—
Ending balance as of June 30, 2009	$	18
	Other Operation and Maintenance Expense
	(millions of dollars)
Gains or (losses) (realized and unrealized) included in income for the period above are reported in Other Operation and Maintenance Expense as follows:
Total gains included in income for the period above	$	2
Change in unrealized gains relating to assets still held at reporting date	$	2

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	Six Months Ended June 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		2
Included in accumulated other comprehensive (losses) income		—
Purchases and issuances		(1	)
Settlements		—
Transfers in and/or out of Level 3		—
Ending balance as of June 30, 2008	$	17
	Other Operation and Maintenance Expense
	(millions of dollars)
Gains or (losses) (realized and unrealized) included in income for the period above are reported in Other Operation and Maintenance Expense as follows:
Total gains (losses) included in income for the period above	$	2
Change in unrealized gains (losses) relating to assets still held at reporting date	$	2

Fair Value of Debt Instruments

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

	June 30, 2009				December 31, 2008
	(millions of dollars)
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	1,554	$	1,605	$	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

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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 will distribute 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 expects to record a pre-tax gain between $26 million and $28 million in the quarter ending September 30, 2009.

As of June 30, 2009, approximately $64 million in remaining proceeds from the Mirant settlement was accounted for as restricted cash and as a regulatory liability. In the third quarter of 2009, the restricted cash will be released and the regulatory liability will be extinguished as a consequence of the MPSC order.

Rate Proceedings

In recent electric service and natural gas distribution base rate cases, Pepco has proposed the adoption of a bill stabilization adjustment mechanism (BSA) for retail customers. To date, a BSA has been approved and implemented for Pepco’s electric service in Maryland and a proposed BSA remains pending for Pepco in the District of Columbia. Under the BSA, customer delivery rates are subject to adjustment (through a surcharge or credit 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, 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 January 2, 2009, the DCPSC issued an order designating the issues and establishing a procedural schedule for the BSA proceeding. Hearings were held on May 12, 2009, followed by post-hearing briefs filed on May 29, 2009 and June 12, 2009. A decision by the DCPSC is pending.

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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. Pepco expects a decision by the end of the third quarter 2009.

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, if the BSA is approved in Phase II of the rate case filed in December 2006, 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 appealed the MPSC’s July 2007, July 2008 and August 2008 orders. The case currently is pending before the Circuit Court for Baltimore City. In a brief filed on March 9, 2009, Pepco contended 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. The MPSC and OPC filed briefs on April 23, 2009 and oral arguments were held on May 12, 2009. A decision by the Circuit Court is pending.

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 June 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

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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 June 30, 2009), as well as its District of Columbia jurisdictional transmission and distribution-related ADITC balance ($3 million as of June 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 results of operations for those periods. However, Pepco does not believe 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 are 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.

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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 June 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, Pepco believes the amounts claimed by the remaining plaintiffs are greatly exaggerated. The amount of total liability, if any, and any related insurance recovery cannot be determined at this time; however, based on information and relevant circumstances known at this time, Pepco does not believe these suits will have a material adverse effect on its financial 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 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 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 with respect to the cleanup of the Peck Iron and Metal site in Portsmouth, Virginia, or for costs the EPA has incurred in cleaning up the site. EPA’s letter alleges that Pepco arranged for disposal or treatment of hazardous substances sent to 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 liability under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. 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. Pepco has not yet been served with the complaint.

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.

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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.

(11) RELATED PARTY TRANSACTIONS

PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries, including Pepco. The cost of these services is allocated in accordance with cost allocation methodologies set forth in the service agreement using a variety of factors, including the subsidiaries’ share of employees, operating expenses, assets, and other cost causal methods. These intercompany transactions are eliminated by PHI in consolidation and no profit results from these transactions at PHI. PHI Service Company costs directly charged or allocated to Pepco for the three months ended June 30, 2009 and 2008 were approximately $41 million and $38 million, respectively. PHI Service Company costs directly charged or allocated to Pepco for the six months ended June 30, 2009 and 2008 were approximately $83 million and $77 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 June 30, 2009 and 2008 were approximately $2 million and $3 million, respectively. Amounts charged to Pepco by these companies for the six months ended June 30, 2009 and 2008 were approximately $4 million and $5 million, respectively.

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

	For the Three Months Ended June 30,					For the Six Months Ended June 30,
Income (Expense)	2009		2008			2009		2008
	(millions of dollars)
Intercompany power purchases – Conectiv Energy Supply (a)	$	1	$	(8	)	$	1	$	(23	)

(a) Included in purchased energy expense.

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

	June 30, 2009			December 31, 2008
Liability	(millions of dollars)
Payable to Related Party (current)
PHI Service Company	$	(18	)	$	(17	)
Pepco Energy Services (a)		(45	)		(53	)
The items listed above are included in the “Accounts payable due to associated companies” balances on the Balance Sheets of $64 million and $70 million at June 30, 2009 and December 31, 2008, respectively.
Money Pool Balance with Pepco Holdings (included in cash and cash equivalents)		33			—

(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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STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	(millions of dollars)
Operating Revenue
Electric	$	251		$	289		$	572		$	584
Natural Gas		40			83			171			199
Total Operating Revenue		291			372			743			783
Operating Expenses
Purchased energy		161			192			380			387
Gas purchased		27			69			128			157
Other operation and maintenance		59			54			118			110
Depreciation and amortization		18			18			37			36
Other taxes		9			8			19			18
Gain on sale of assets		—			—			—			(3	)
Total Operating Expenses		274			341			682			705
Operating Income		17			31			61			78
Other Income (Expenses)
Interest and dividend income		—			1			—			2
Interest expense		(11	)		(9	)		(22	)		(19	)
Other income		1			1			1			2
Total Other Expenses		(10	)		(7	)		(21	)		(15	)
Income Before Income Tax Expense		7			24			40			63
Income Tax Expense		2			8			14			21
Net Income		5			16			26			42
Retained Earnings at Beginning of Period		441			431			448			432
Dividends Paid to Parent		—			(15	)		(28	)		(42	)
Retained Earnings at End of Period	$	446		$	432		$	446		$	432

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

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BALANCE SHEETS

(Unaudited)

	June 30, 2009			December 31, 2008
	(millions of dollars)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	115		$	138
Accounts receivable, less allowance for uncollectible accounts of $14 million and $10 million, respectively		170			202
Inventories		41			52
Prepayments of income taxes		54			34
Prepaid expenses and other		23			28
Total Current Assets		403			454
INVESTMENTS AND OTHER ASSETS
Goodwill		8			8
Regulatory assets		214			244
Prepaid pension expense		187			184
Other		47			33
Total Investments and Other Assets		456			469
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		2,724			2,656
Accumulated depreciation		(845	)		(827	)
Net Property, Plant and Equipment		1,879			1,829
TOTAL ASSETS	$	2,738		$	2,752

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

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BALANCE SHEETS

(Unaudited)

	June 30, 2009		December 31, 2008
	(millions of dollars, except shares)
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Short-term debt	$	255	$	246
Accounts payable and accrued liabilities		64		108
Accounts payable due to associated companies		22		34
Taxes accrued		4		7
Interest accrued		6		6
Liabilities and accrued interest related to uncertain tax positions		—		23
Derivative liabilities		11		13
Other		77		56
Total Current Liabilities		439		493
DEFERRED CREDITS
Regulatory liabilities		290		277
Deferred income taxes, net		467		446
Investment tax credits		8		8
Above-market purchased energy contracts and other electric restructuring liabilities		18		19
Derivative liabilities		19		14
Other		61		57
Total Deferred Credits		863		821
LONG-TERM LIABILITIES
Long-term debt		686		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		304		304
Retained earnings		446		448
Total Equity		750		752
TOTAL LIABILITIES AND EQUITY	$	2,738	$	2,752

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

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STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended June 30,
	2009			2008
	(millions of dollars)
OPERATING ACTIVITIES
Net income	$	26		$	42
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		37			36
Gain on sale of assets		—			(3	)
Deferred income taxes		22			31
Changes in:
Accounts receivable		28			(18	)
Regulatory assets and liabilities		38			21
Accounts payable and accrued liabilities		(47	)		31
Pension contributions		(10	)		—
Taxes accrued		(35	)		(21	)
Inventories		11			5
Other assets and liabilities		12			4
Net Cash From Operating Activities		82			128
INVESTING ACTIVITIES
Investment in property, plant and equipment		(84	)		(72	)
Proceeds from sale of assets		—			50
Changes in restricted cash equivalents		—			(32	)
Net Cash Used By Investing Activities		(84	)		(54	)
FINANCING ACTIVITIES
Dividends paid to Parent		(28	)		(42	)
Capital contribution from Parent		—			62
Issuance of long-term debt		—			150
Reacquisitions of long-term debt		—			(98	)
Issuances (repayments) of short-term debt, net		9			(147	)
Net other financing activities		(2	)		(3	)
Net Cash Used By Financing Activities		(21	)		(78	)
Net Decrease in Cash and Cash Equivalents		(23	)		(4	)
Cash and Cash Equivalents at Beginning of Period		138			11
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	115		$	7
NONCASH ACTIVITIES
Asset retirement obligations associated with removal costs transferred to regulatory liabilities	$	3		$	(3	)
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for income taxes (includes payments to PHI for Federal income taxes)	$	28		$	11

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 (SOS) 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). 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 June 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 six months ended June 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 August 6, 2009, the date of issuance of the financial statements to which these Notes relate.

Change in Accounting Principle

Since DPL’s adoption of Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets,” DPL has conducted its annual impairment review of goodwill as of July 1. After the completion of the July 1, 2009 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 PPAs in amounts up to a total of 350 megawatts. Three of the PPAs are with onshore facilities and one of the PPAs is with an offshore facility. 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 onshore contracts, 2010 for the other two onshore contracts, and 2014 for the offshore contract.

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 could result in delays in the construction of the wind facilities and the operational start dates for these wind facilities. If the wind facilities are not operational by specified dates, DPL has the right to terminate the PPAs.

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DPL concluded that consolidation is not required for any of these PPAs under Financial Accounting Standards Board (FASB) Interpretation Number (FIN) 46(R). 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 historically has tested its goodwill for impairment annually as of July 1, 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. 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; an adverse regulatory action; or an impairment of long-lived assets in the reporting unit. DPL performed its annual impairment test as of July 1, 2009 prior to the issuance of the June 30, 2009 Form 10-Q to ensure that no impairment charge should be recorded as of June 30, 2009. As described in Note (6), “Goodwill,” no impairment charge has been required to be recorded. As further described above, under the heading “Change in Accounting Principle,” after the completion of the July 1, 2009 impairment test, DPL changed the annual impairment testing date to November 1, and will perform its next annual impairment test on November 1, 2009.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in DPL’s gross revenues were $3 million and $4 million for the three months ended June 30, 2009 and 2008, respectively, and $7 million for the six months ended June 30, 2009 and 2008.

Reclassifications and Adjustments

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

Income Tax Adjustments

During the second quarter of 2009, DPL recorded an adjustment to correct certain income tax errors related to prior periods. The adjustment, which is not considered material, resulted in a decrease in income tax expense of $1 million for the three and six months ended June 30, 2009.

(3)NEWLY ADOPTED ACCOUNTING STANDARDS

Statement of Financial Accounting Standards (SFAS) No. 141(R), “Business Combinations—a Replacement of FASB Statement No. 141” (SFAS No. 141 (R))

SFAS No. 141(R) replaces FASB Statement No. 141, “Business Combinations,” and retains the fundamental requirements that the acquisition method of accounting be used for all business combinations and for an acquirer to be identified for each business combination. However, SFAS No. 141(R) expands the definition of a business and amends FASB Statement No. 109, “Accounting for Income Taxes,” to require 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 FASB Staff Position (FSP) Financial Accounting Standards (FAS) 141(R)-1, “Accounting for Assets and Liabilities Assumed in a Business Combination that Arise from Contingencies” (FSP FAS 141(R)-1), 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. FSP FAS 141(R)-1 requires that assets acquired and liabilities assumed in a business combination that arise from contingencies be measured at fair

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value if the acquisition date fair value of that asset and liability can be determined during the measurement period in accordance with SFAS No. 157. If the acquisition date fair value cannot be determined, then the asset or liability would be measured in accordance with SFAS No. 5, “Accounting for Contingencies,” and FIN No. 14, “Reasonable Estimate of the Amount of Loss.”

SFAS No. 141(R) and the guidance provided in FSP FAS 141(R)-1 applies prospectively to business combinations for which the acquisition date is on or after January 1, 2009. DPL adopted SFAS No. 141(R) on January 1, 2009, and it did not have a material impact on DPL’s overall financial condition, results of operations, or cash flows.

FSP 157-2, “Effective Date of FASB Statement No. 157” (FSP 157-2)

FSP 157-2 deferred the effective date of SFAS No. 157, “Fair Value Measurements,” (SFAS No. 157) for all nonrecurring fair value measurements of non-financial assets and non-financial liabilities until January 1, 2009 for DPL. The adoption of SFAS No. 157 did not have a material impact on the fair value measurements of DPL’s non-financial assets and non-financial liabilities.

SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements—an Amendment of ARB No. 51” (SFAS No. 160)

SFAS No. 160 establishes 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. It clarifies 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.

SFAS No. 160 establishes accounting and reporting standards that require (i) the ownership interests and the related consolidated net income in subsidiaries held by parties other than the parent be clearly identified, labeled, and presented in the consolidated balance sheets within equity, but separate from the parent’s equity, and presented separately on the face of the consolidated statements of income, (ii) the changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for as equity transactions, and (iii) when a subsidiary is deconsolidated, any retained non-controlling equity investment in the former subsidiary must be initially measured at fair value.

SFAS No. 160 is 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 SFAS No. 160, and the provisions did not have a material impact on DPL’s overall financial condition, results of operations, or cash flows.

SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities—an Amendment of FASB Statement No. 133” (SFAS No. 161)

SFAS No. 161 enhances the disclosure requirements for derivative instruments and hedging activities. Some of the new disclosures include derivative objectives and strategies, derivative volumes by product type, location and gross fair values of derivative assets and liabilities, location and amounts of gains and losses on derivatives and related hedged items, and credit-risk-related contingent features in derivatives.

SFAS No. 161 is effective for financial statement reporting periods beginning January 1, 2009 for DPL. SFAS No. 161 encourages but does not require disclosures for earlier periods presented for comparative purposes at initial adoption. DPL adopted the provisions of SFAS No. 161 beginning with its March 31, 2009 financial statements with comparative disclosures for prior periods. The disclosures for the current financial statements are included within Footnote (10), “Derivative Instruments and Hedging Activities.”

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Emerging Issues Task Force (EITF) Issue No. 08-5, “Issuer’s Accounting for Liabilities Measured at Fair Value with a Third Party Credit Enhancement” (EITF 08-5)

In September 2008, the FASB issued EITF 08-5 to provide guidelines for the determination of the unit of accounting for a liability issued with an inseparable third-party credit enhancement when it is measured or disclosed at fair value on a recurring basis. EITF 08-5 applies to entities that incur liabilities with inseparable third-party credit enhancements or guarantees that are recognized or disclosed at fair value. This would include guaranteed debt obligations, 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 is 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.

EITF 08-5 is effective on a prospective basis for reporting periods beginning on and after January 1, 2009 for DPL. As of January 1, 2009, DPL adopted the provisions of EITF 08-5, and it did not have a material impact on DPL’s overall financial condition, results of operations, or cash flows.

FSP FAS 107-1 and Accounting Principles Board (APB) 28-1, “Interim Disclosures about Fair Value of Financial Instruments” (FSP FAS 107-1 and APB 28-1)

In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1, which require quarterly disclosures of the fair values of financial instruments. This FSP is effective for interim reporting periods ending after June 15, 2009. The disclosures for prior reporting periods are required.

DPL adopted the disclosure requirements in its second quarter 2009 reporting. The primary impact of the new standard is disclosing the fair value of debt issued by DPL on a quarterly basis as presented in Footnote (11), “Fair Value Disclosures.”

FSP FAS 157-4, “Determining Whether a Market is Not Active and a Transaction is Not Distressed” (FSP FAS 157-4)

In April 2009, the FASB issued FSP FAS 157-4, which 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. This FSP is effective for interim reporting periods ending after June 15, 2009.

DPL adopted the provisions of this FSP in the second quarter of 2009. The standard would primarily apply 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. FSP FAS 157-4 did not have a material impact on DPL’s overall financial condition, results of operations, or cash flows.

Statement of Financial Accounting Standards (SFAS) No. 165, “Subsequent Events” (SFAS No. 165)

In May 2009, the FASB issued SFAS No. 165 to establish guidelines for the accounting and disclosures of events that occur after the balance sheet reporting date but before the financial statements are issued. The statement has not resulted in any significant changes from U.S. Auditing Standards “AU” 560,Subsequent Events;however, it places the responsibility on the reporting entity and not just the auditors to assess the impact of subsequent events on the financial statements. The statement was effective for interim or annual financial periods ending after June 15, 2009, which for DPL was the second quarter of 2009. DPL addresses subsequent events in Footnote (2), “Significant Accounting Policies.”

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(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Statement of Financial Accounting Standards (SFAS) No. 166, “Accounting for Transfers of Financial Assets—an amendment of SFAS No. 140” (SFAS No. 166)

In June 2009, the FASB issued SFAS No. 166 to remove the concept of qualifying special-purpose entity (“QSPE”) from SFAS No. 140 and the QSPE scope exception in FIN 46(R). The statement changes 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 it will have on its overall financial condition and financial statements.

Statement of Financial Accounting Standards (SFAS) No. 167, “Consolidation of Variable Interest Entities—an amendment of FIN 46(R)” (SFAS No. 167)

In June 2009, the FASB issued SFAS No. 167 to amend FIN 46(R), Consolidation of Variable Interest Entities, which eliminates the existing quantitative analysis requirement and adds new qualitative factors to determine whether consolidation is required that would have to be applied on a quarterly basis to interests in variable interest entities. Under the new standard, 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 standard retained the provision in FIN 46(R) 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 amendment will be effective on January 1, 2010 for DPL. Comparative disclosures under this provision are encouraged but not required for earlier periods presented. DPL is evaluating the impact that it will have on its overall financial condition and financial statements.

Statement of Financial Accounting Standards (SFAS) No. 168, “The FASB Accounting Standards Codification^TM and the Hierarchy of Generally Accepted Accounting Principles” (SFAS No. 168)

In June 2009, the FASB issued SFAS No. 168 to identify the sources of accounting principles and the framework for selecting the principles used in the preparation of non-governmental financial statements that are presented under U.S. GAAP. In addition, SFAS No. 168 replaces the current reference system for standards and guidance with a new numerical designation system known as the Codification. The Codification will be the single source reference system for all authoritative non-governmental GAAP. The Codification is numerically organized by topic, subtopic, section, and subsection.

SFAS No. 168 replaces SFAS No. 162,The Hierarchy of Generally Accepted Accounting Principles and is effective for financial statements issued for interim and annual periods ending after September 15, 2009. There is an option to early adopt beginning with interim periods ending after June 15, 2009. DPL has not elected to early adopt and therefore, the Codification referencing required by SFAS No. 168 will become effective in its September 30, 2009 financial statements. Entities are not required to revise previous financial statements for the change in references.

The adoption of SFAS No. 168 is not expected to result in a change in accounting for DPL. Therefore, the provisions of SFAS No. 168 are not expected to have a material impact on DPL’s overall financial condition, results of operations, or cash flows. However, there will be a change in how accounting standards are referenced in the financial statements.

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(5) SEGMENT INFORMATION

In accordance with SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information,” DPL has one segment, its regulated utility business.

(6)GOODWILL

As of June 30, 2009 and December 31, 2008, DPL had goodwill of approximately $8 million, all of which was generated by DPL’s acquisition of Conowingo Power Company in 1995.

DPL’s July 1, 2009 annual impairment test indicated that its goodwill was not impaired. DPL performed an interim impairment test as of December 31, 2008 which indicated that goodwill was not impaired. At March 31, 2009, after review of its significant assumptions in the goodwill impairment analysis, DPL concluded that there was no triggering event requiring DPL to perform a comprehensive goodwill assessment during the first quarter of 2009. DPL also concluded that its goodwill was not impaired at June 30, 2009, with the completion of the July 1, 2009 annual impairment test.

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 since the adoption of SFAS No. 142.

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 whether there is goodwill impairment.

(7)PENSION AND OTHER POSTRETIREMENT BENEFITS

DPL accounts for its participation in the Pepco Holdings benefit plans as participation in a multi-employer plan. PHI’s pension and other postretirement net periodic benefit cost for the three months ended June 30, 2009 before intercompany allocations from the PHI Service Company, of $44 million includes $7 million for DPL’s allocated share. PHI’s pension and other post retirement net periodic benefit cost for the six months ended June 30, 2009 of $75 million includes $12 million for DPL’s allocated share. PHI’s pension and other postretirement net periodic benefit cost for the three months ended June 30, 2008 before intercompany allocations, of $17 million included $1 million for DPL’s allocated share. PHI’s pension and other post retirement net periodic benefit cost for the six months ended June 30, 2008 of $32 million includes $2 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

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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.

DPL historically has issued commercial paper to meet its short-term working capital requirements. As a result of disruptions in the commercial paper markets in 2008, DPL has borrowed under the credit facility to create a cash reserve for future short-term operating needs. At June 30, 2009, DPL had an outstanding loan of $50 million under the credit facility, which it repaid in July 2009.

At June 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 $549 million and $843 million, respectively.

Other Financing Activities

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

In April 2009, DPL resold $9 million of its Pollution Control Revenue Refunding Bonds, which previously had been issued for the benefit of DPL by the Delaware Economic Development Authority. These bonds were repurchased by DPL in November 2008 in response to disruption in the tax-exempt bond market that made it difficult for the remarketing agent to successfully remarket the bonds. As the owner of the bonds, DPL received the proceeds of the sale, which it intends to use for general corporate purposes.

In May 2009, DPL repaid, prior to maturity, $50 million of a $150 million short-term loan, which matured in July 2009.

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

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

In July 2009, DPL redeemed the $15 million Series 2003 A and $18.2 million Series 2003 B Delaware Economic Development Authority tax exempt bonds that were repurchased in 2008 due to the disruptions in the tax exempt capital markets.

(9)INCOME TAXES

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

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2009		2008		2009		2008
Federal statutory rate	35.0	%	35.0	%	35.0	%	35.0	%
Increases (decreases) resulting from:
Depreciation	5.7		2.5		2.0		1.9
State income taxes, net of federal effect	5.7		5.5		5.5		5.4
Tax credits	(2.9	)	(1.0	)	(1.0	)	(.6	)
Change in estimates and interest related to uncertain and effectively settled tax positions	(18.6	)	(10.5	)	(6.0	)	(8.9	)
Other, net	3.7		—		(.5	)	(.2	)
Effective Income Tax Rate	28.6	%	31.5	%	35.0	%	32.6	%

DPL’s effective tax rates for the three months ended June 30, 2009 and 2008 were 28.6% and 31.5%, respectively. The decrease in the rate resulted from the change in estimates and interest related to uncertain and effectively settled tax positions due to the filing of an amended state income tax return to recover unused net operating losses, partially offset by the second quarter 2008 settlement of the mixed service cost issue. See Footnote (12), “Commitments and Contingencies” for additional discussion.

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DPL’s effective tax rates for the six months ended June 30, 2009 and 2008 were 35.0% and 32.6% respectively. The increase in the rate resulted from the change in estimates and interest related to uncertain and effectively settled tax positions due to the filing of an amended state income tax return to recover unused net operating losses, partially offset by the second quarter 2008 settlement of the mixed service cost issue and the filing of a claim with the IRS related to certain casualty losses.

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.

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

(10)DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

DPL accounts for its derivative activities in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” (SFAS No. 133) as amended by subsequent pronouncements.

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 Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation,” until recovered based on the Fuel Adjustment clause approved by the DPSC.

The table below identifies the balance sheet location and fair values of derivative instruments as of June 30, 2009 and December 31, 2008:

	As of June 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)	$	—		$	7		$	7		$	(7	)	$	—
Derivative Assets (non-current assets)		—			—			—			—			—
Total Derivative Assets		—			7			7			(7	)		—
Derivative Liabilities (current liabilities)		(21	)		(21	)		(42	)		31			(11	)
Derivative Liabilities (non-current liabilities)		—			(18	)		(18	)		(1	)		(19	)
Total Derivative Liabilities		(21	)		(39	)		(60	)		30			(30	)
Net Derivative (Liability) Asset	$	(21	)	$	(32	)	$	(53	)	$	23		$	(30	)

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	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 FSP FIN 39-1, DPL offsets the fair value amounts recognized for derivative instruments and fair value amounts recognized for related collateral positions executed with the same counterparty under a master netting arrangement. The amount of cash collateral that was offset against these derivative positions is as follows:

	June 30, 2009		December 31, 2008
	(millions of dollars)
Cash collateral pledged to counterparties with the right to reclaim	$	23	$	28

As of June 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.

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 gains and losses related to hedging activities, are deferred under SFAS No. 71 until recovered based on the fuel adjustment clause approved by the DPSC. The following table indicates the amounts deferred as regulatory assets or liabilities and the location in the statements of income of amounts reclassified to income through the fuel adjustment clause for the three and six months ended June 30, 2009 and 2008:

	Three Months Ended June 30,					Six Months Ended June 30,
	2009			2008		2009			2008
	(millions of dollars)
Net Gain Deferred as a Regulatory Asset/Liability	$	11		$	4	$	11		$	10
Net (Loss) Gain Reclassified from Regulatory Asset/Liability to Purchased Energy		(10	)		2		(26	)		1

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

	Quantities
Commodity	June 30, 2009	December 31, 2008
Forecasted Purchases Hedges:
Natural Gas (One Million British Thermal Units (MMBtu))	8,225,000	10,805,000

Other Derivative Activity

DPL holds certain derivatives that do not qualify as hedges. Under SFAS No. 133, these derivatives are recorded at fair value on the balance sheet with the gain or loss recorded in income. In accordance with SFAS No. 71, offsetting regulatory assets or regulatory liabilities are recorded on the balance sheet and the recognition of the gain or recovery of the loss is deferred. For the three and six months ended June 30, 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 June 30,					Six Months Ended June 30,
	2009			2008		2009			2008
	(millions of dollars)
Net Gain (Loss) Deferred as a Regulatory Asset/Liability	$	4		$	12	$	(10	)	$	16
Net Gain (Loss) Reclassified from Regulatory Asset/Liability to Purchased Energy		(2	)		—		(5	)		—

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

	June 30, 2009		December 31, 2008
Commodity	Quantity	Net Position	Quantity	Net Position
Natural Gas (MMBtu)	10,727,069	Long	8,928,750	Long

Contingent Credit Risk Features

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

The collateral requirements under the ISDA or similar agreements generally work as follows. The parties establish a dollar threshold of unsecured credit for each party in excess of which the party would be required to post collateral to secure its obligations to the other party. The amount of the unsecured credit threshold varies according to the senior, unsecured debt rating of the respective parties or that of a guarantor of the party’s obligations. The fair values of all transactions between the parties are netted under the master netting provisions. Transactions may include derivatives accounted for on-balance sheet as well as normal purchases and normal sales that are accounted for off-balance sheet under SFAS No. 133. 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 be typically 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.

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DPL

The gross fair value of DPL’s derivative liabilities, excluding the impact of offsetting transactions or collateral under master netting agreements, with credit-risk-related contingent features on June 30, 2009, was $37 million. As of that date, DPL had posted cash collateral of $3 million in the normal course of business against the gross derivative liability resulting in a net liability of $34 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 June 30, 2009, would have been approximately $18 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 June 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 $549 million.

(11) FAIR VALUE DISCLOSURES

Fair Value of Assets and Liabilities Excluding Debt

Effective January 1, 2008, DPL adopted SFAS No. 157 which established a framework for measuring fair value and expanded disclosures about fair value measurements.

As defined in SFAS No. 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). DPL utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. Accordingly, DPL utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. DPL is able to classify fair value balances based on the observability of those inputs. SFAS No. 157 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 defined by SFAS No. 157 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.

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DPL

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 June 30, 2009 and December 31, 2008. As required by SFAS No. 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. DPL’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Fair Value Measurements at June 30, 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	$	70	$	70	$	—	$	—
Executive deferred compensation plan assets		4		3		—		1
	$	74	$	73	$	—	$	1
LIABILITIES
Derivative instruments	$	53	$	21	$	—	$	32
Executive deferred compensation plan liabilities		—		—		—		—
	$	53	$	21	$	—	$	32
	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

80

DPL

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

	Six Months Ended June 30, 2009
	Net Derivative Instruments Assets (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		(15	)		—
Purchases and issuances		—			—
Settlements		7			—
Transfers in and/or out of Level 3		—			—
Ending balance as of June 30, 2009	$	(32	)	$	1
				Other Operation and Maintenance Expense
				(millions of dollars)
Gains or (losses) (realized and unrealized) included in income for the period above are reported in Other Operation and Maintenance Expense as follows:
Total losses included in income for the period above				$	—
Change in unrealized gains relating to assets still held at reporting date				$	—
	Six Months Ended June 30, 2008
	Net Derivative Instruments Assets (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		15			—
Purchases and issuances		—			—
Settlements		—			—
Transfers in and/or out of Level 3		—			—
Ending balance as of June 30, 2008	$	5		$	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				$	—

81

DPL

Fair Value of Debt Instruments

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

	June 30, 2009				December 31, 2008
	(millions of dollars)
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	686	$	676	$	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.

(12)COMMITMENTS AND CONTINGENCIES

Regulatory and Other Matters

Rate Proceedings

In recent electric service and natural gas distribution base rate cases, DPL has proposed the adoption of a bill stabilization adjustment mechanism (BSA) for retail customers. To date, a BSA has been approved and implemented for DPL electric service in Maryland, and a method of revenue decoupling similar to a BSA, referred to as a modified fixed variable rate design (MFVRD), has been approved for DPL electric and natural gas service in Delaware, which will be implemented in the context of DPL’s next Delaware base rate case. Under the BSA, customer delivery rates are subject to adjustment (through a surcharge or credit 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 DPL’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. 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 Hearing Examiner’s report recommending approval of the settlement agreement was issued on July 21, 2009. DPSC approval of the settlement agreement is pending.

82

DPL

On June 25, 2009, DPL filed two applications requesting approval 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.

Maryland

In July 2007, the MPSC issued orders in the electric service distribution rate cases 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 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 appealed the MPSC’s July 2007, July 2008 and August 2008 orders. The case currently is pending before the Circuit Court for Baltimore City. In a brief filed on March 9, 2009, DPL contended 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. The MPSC and OPC filed briefs on April 23, 2009 and oral arguments were held on May 12, 2009. A decision by the Circuit Court is pending.

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 return on equity 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 $4 million. Hearings are scheduled for September 21 through September 24, 2009, with a decision expected from the MPSC 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 would be included in its cost of service for ratemaking purposes.

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. DPL has not yet been served with the complaint.

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.

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DPL

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 June 30, 2009 and 2008 were $31 million and $30 million, respectively. PHI Service Company costs directly charged or allocated to DPL for the six months ended June 30, 2009 and 2008 were approximately $63 million and $60 million respectively.

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

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
Income (Expenses)	2009			2008			2009			2008
	(millions of dollars)
SOS with Conectiv Energy Supply (a)	$	(22	)	$	(43	)	$	(59	)	$	(104	)
Intercompany lease transactions (b)		2			2			4			4
Transcompany pipeline gas purchases with Conectiv Energy Supply (c)		—			(1	)		—			(1	)

(a) Included in purchased energy expense.

(b) Included in electric revenue.

(c) Included in gas purchased.

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

	June 30, 2009			December 31, 2008
Liability	(millions of dollars)
Payable to Related Party (current)
PHI Service Company	$	(16	)	$	(15	)
Conectiv Energy Supply		(3	)		(14	)
Pepco Energy Services (a)		(2	)		(6	)
The items listed above are included in the “Accounts payable due to associated companies” balances on the Balance Sheets of $22 million and $34 million at June 30, 2009 and December 31, 2008, respectively.
Money Pool Balance with Pepco Holdings (included in cash and cash equivalents)	$	40		$	—

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

84

ACE

ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	(millions of dollars)
Operating Revenue	$	287		$	387		$	631		$	748
Operating Expenses
Purchased energy		239			273			516			518
Other operation and maintenance		47			43			95			89
Depreciation and amortization		24			25			49			49
Other taxes		5			6			10			12
Deferred electric service costs		(57	)		(17	)		(84	)		8
Total Operating Expenses		258			330			586			676
Operating Income		29			57			45			72
Other Income (Expenses)
Interest and dividend income		—			—			—			1
Interest expense		(17	)		(15	)		(34	)		(30	)
Other income		—			1			1			2
Total Other Expenses		(17	)		(14	)		(33	)		(27	)
Income Before Income Tax Expense		12			43			12			45
Income Tax Expense		4			16			2			13
Net Income		8			27			10			32
Retained Earnings at Beginning of Period		144			147			166			142
Dividends Paid to Parent		—			(31	)		(24	)		(31	)
Retained Earnings at End of Period	$	152		$	143		$	152		$	143

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

85

ACE

ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30, 2009			December 31, 2008
	(millions of dollars)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	5		$	65
Restricted cash equivalents		9			10
Accounts receivable, less allowance for uncollectible accounts of $7 million and $6 million, respectively		163			195
Inventories		16			15
Prepayments of income taxes		40			47
Prepaid expenses and other		74			16
Total Current Assets		307			348
INVESTMENTS AND OTHER ASSETS
Regulatory assets		742			768
Restricted funds held by trustee		5			5
Assets and accrued interest related to uncertain tax positions		77			113
Income taxes receivable		75			12
Prepaid pension expense		62			6
Other		12			12
Total Investments and Other Assets		973			916
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		2,267			2,216
Accumulated depreciation		(684	)		(666	)
Net Property, Plant and Equipment		1,583			1,550
TOTAL ASSETS	$	2,863		$	2,814

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

86

ACE

ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30, 2009		December 31, 2008
	(millions of dollars, except shares)
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Short-term debt	$	139	$	23
Current maturities of long-term debt		33		32
Accounts payable and accrued liabilities		120		122
Accounts payable due to associated companies		29		28
Taxes accrued		15		7
Interest accrued		14		14
Liabilities and accrued interest related to uncertain tax positions		—		6
Other		38		35
Total Current Liabilities		388		267
DEFERRED CREDITS
Regulatory liabilities		259		377
Deferred income taxes, net		570		549
Investment tax credits		10		10
Other postretirement benefit obligation		43		41
Liabilities and accrued interest related to uncertain tax positions		12		3
Other		17		14
Total Deferred Credits		911		994
LONG-TERM LIABILITIES
Long-term debt		610		610
Transition Bonds issued by ACE Funding		385		401
Total Long-Term Liabilities		995		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		385		344
Retained earnings		152		166
Total Equity		563		536
TOTAL LIABILITIES AND EQUITY	$	2,863	$	2,814

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

87

ACE

ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended June 30,
	2009			2008
	(millions of dollars)
OPERATING ACTIVITIES
Net income	$	10		$	32
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		49			49
Deferred income taxes		23			34
Changes in:
Accounts receivable		32			(24	)
Regulatory assets and liabilities		(109	)		4
Accounts payable and accrued liabilities		2			117
Pension contributions		(60	)		—
Prepaid New Jersey sales and excise tax		(58	)		(54	)
Taxes accrued		(3	)		(27	)
Interest accrued		—			(2	)
Other assets and liabilities		6			4
Net Cash (Used By) From Operating Activities		(108	)		133
INVESTING ACTIVITIES
Investment in property, plant and equipment		(67	)		(89	)
Proceeds from sale of assets		—			1
Net other investing activities		1			2
Net Cash Used By Investing Activities		(66	)		(86	)
FINANCING ACTIVITIES
Dividends paid to Parent		(24	)		(31	)
Capital contribution from Parent		40			35
Reacquisition of long-term debt		(15	)		(119	)
Issuances of short-term debt, net		116			78
Net other financing activities		(3	)		(8	)
Net Cash From (Used By) Financing Activities		114			(45	)
Net (Decrease) Increase in Cash and Cash Equivalents		(60	)		2
Cash and Cash Equivalents at Beginning of Period		65			7
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	5		$	9
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash (received) paid for income taxes (includes payments to PHI for Federal income taxes)	$	(16	)	$	7

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

88

ACE

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). 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 June 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 six months ended June 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 August 6, 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 Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46(R) (revised December 2003), “Consolidation of Variable Interest Entities” (FIN 46(R)) and FASB Staff Position (FSP) FIN 46(R)-6, “Determining the Variability to Be Considered in Applying FASB Interpretation No. 46(R)” (FSP FIN 46(R)-6), ACE continued, during the second 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 FIN 46(R) 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 application of FIN 46(R) 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 June 30, 2009 and 2008 were approximately $61 million and $82 million, respectively, of which approximately $59 million and $74 million, respectively, consisted of power purchases under the PPAs. Net power purchase activities with the counterparties under the PPAs for the six months ended June 30, 2009 and 2008 were approximately $144 million and $171 million, respectively, of which approximately $131 million and $150 million, respectively, consisted of power purchases under the PPAs. ACE does not have exposure to loss under the PPAs because ACE is able to recover its costs from its customers through regulated rates.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in ACE’s gross revenues were $5 million for the three months ended June 30, 2009 and 2008 and $10 million for the six months ended June 30, 2009 and 2008.

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Reclassifications and Adjustments

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

Income Tax Adjustments

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 an increase in income tax expense of $1 million for the three months ended June 30, 2009, and a decrease in income tax expense of $1 million for the six months ended June 30, 2009.

(3)NEWLY ADOPTED ACCOUNTING STANDARDS

Statement of Financial Accounting Standards (SFAS) No. 141(R), “Business Combinations—a Replacement of FASB Statement No. 141” (SFAS No. 141 (R))

SFAS No. 141(R) replaces FASB Statement No. 141, “Business Combinations,” and retains the fundamental requirements that the acquisition method of accounting be used for all business combinations and for an acquirer to be identified for each business combination. However, SFAS No. 141(R) expands the definition of a business and amends FASB Statement No. 109, “Accounting for Income Taxes,” to require 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 FSP Financial Accounting Standards (FAS) 141(R)-1, “Accounting for Assets and Liabilities Assumed in a Business Combination that Arise from Contingencies” (FSP FAS 141(R)-1), 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. FSP FAS 141(R)-1 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 in accordance with SFAS No. 157. If the acquisition date fair value cannot be determined, then the asset or liability would be measured in accordance with SFAS No. 5, “Accounting for Contingencies,” and FIN No. 14, “Reasonable Estimate of the Amount of Loss.”

SFAS No. 141(R) and the guidance provided in FSP FAS 141(R)-1 applies prospectively to business combinations for which the acquisition date is on or after January 1, 2009. ACE adopted SFAS No. 141(R) on January 1, 2009, and it did not have a material impact on ACE’s overall financial condition, results of operations, or cash flows.

FSP 157-2, “Effective Date of FASB Statement No. 157” (FSP 157-2)

FSP 157-2 deferred the effective date of SFAS No. 157, “Fair Value Measurements,” (SFAS No. 157) for all nonrecurring fair value measurements of non-financial assets and non-financial liabilities until January 1, 2009 for ACE. The adoption of SFAS No. 157 did not have a material impact on the fair value measurements of ACE’s non-financial assets and non-financial liabilities.

SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements—an Amendment of ARB No. 51” (SFAS No. 160)

SFAS No. 160 establishes 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. It clarifies 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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SFAS No. 160 establishes accounting and reporting standards that require (i) the ownership interests and the related consolidated net income in subsidiaries held by parties other than the parent be clearly identified, labeled, and presented in the consolidated balance sheets within equity, but separate from the parent’s equity, and presented separately on the face of the consolidated statements of income, (ii) the changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for as equity transactions, and (iii) when a subsidiary is deconsolidated, any retained non-controlling equity investment in the former subsidiary must be initially measured at fair value.

SFAS No. 160 is 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 SFAS No. 160, and the provisions did not have a material impact on ACE’s overall financial condition, results of operations, or cash flows.

FSP FAS 107-1 and Accounting Principles Board (APB) 28-1, “Interim Disclosures about Fair Value of Financial Instruments” (FSP FAS 107-1 and APB 28-1)

In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1, which require quarterly disclosures of the fair values of financial instruments. This FSP is effective for interim reporting periods ending after June 15, 2009. The disclosures for prior reporting periods are required.

ACE adopted the disclosure requirements in its second quarter 2009 reporting. The primary impact of the new standard is disclosing the fair value of debt issued by ACE on a quarterly basis as presented in Footnote (9), “Fair Value Disclosures.”

Statement of Financial Accounting Standards (SFAS) No. 165, “Subsequent Events” (SFAS No. 165)

In May 2009, the FASB issued SFAS No. 165 to establish guidelines for the accounting and disclosures of events that occur after the balance sheet reporting date but before the financial statements are issued. The statement has not resulted in any significant changes from U.S. Auditing Standards “AU” 560,Subsequent Events;however, it places the responsibility on the reporting entity and not just the auditors to assess the impact of subsequent events on the financial statements. The statement was effective for interim or annual financial periods ending after June 15, 2009, which for ACE was the second quarter of 2009. ACE addresses subsequent events in Footnote (2), “Significant Accounting Policies.”

(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Statement of Financial Accounting Standards (SFAS) No. 166, “Accounting for Transfers of Financial Assets—an amendment of SFAS No. 140” (SFAS No. 166)

In June 2009, the FASB issued SFAS No. 166 to remove the concept of a qualifying special-purpose entity (QSPE) from SFAS No. 140 and the QSPE scope exception in FIN 46(R). The statement changes 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 it will have on its overall financial condition and financial statements.

Statement of Financial Accounting Standards (SFAS) No. 167, “Consolidation of Variable Interest Entities—an amendment of FIN 46(R)” (SFAS No. 167)

In June 2009, the FASB issued SFAS No. 167 to amend FIN 46(R), Consolidation of Variable Interest Entities, which eliminates the existing quantitative analysis requirement and adds new qualitative factors to determine whether consolidation

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is required. The new qualitative factors would be applied on a quarterly basis to interests in variable interest entities. Under the new standard, 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 standard retained the provision in FIN 46(R) 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 amendment will be effective on January 1, 2010 for ACE. Comparative disclosures under this provision are encouraged but not required for earlier periods presented. ACE is evaluating the impact that it will have on its overall financial condition and financial statements.

Statement of Financial Accounting Standards (SFAS) No. 168, “The FASB Accounting Standards Codification^TM and the Hierarchy of Generally Accepted Accounting Principles” (SFAS No. 168)

In June 2009, the FASB issued SFAS No. 168 to identify the sources of accounting principles and the framework for selecting the principles used in the preparation of non-governmental financial statements that are presented under U.S. GAAP. In addition, SFAS No. 168 replaces the current reference system for standards and guidance with a new numerical designation system known as the Codification. The Codification will be the single source reference system for all authoritative non-governmental GAAP. The Codification is numerically organized by topic, subtopic, section, and subsection.

SFAS No. 168 replaces SFAS No. 162,The Hierarchy of Generally Accepted Accounting Principles and is effective for financial statements issued for interim and annual periods ending after September 15, 2009. There is an option to early adopt beginning with interim periods ending after June 15, 2009. ACE has not elected to early adopt and therefore, the Codification referencing required by SFAS No. 168 will become effective in its September 30, 2009 financial statements. Entities are not required to revise previous financial statements for the change in references.

The adoption of SFAS No. 168 is not expected to result in a change in accounting for ACE. Therefore, the provisions of SFAS No. 168 are not expected to have a material impact on ACE’s overall financial condition, results of operations, or cash flows. However, there will be a change in how accounting standards are referenced in the financial statements.

(5) SEGMENT INFORMATION

In accordance with SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information,” 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 June 30, 2009 before intercompany allocations from the PHI Service Company, of $44 million includes $6 million for ACE’s allocated share. PHI’s pension and other postretirement net periodic benefit cost for the six months ended June 30, 2009 of $75 million includes $10 million for ACE’s allocated share. PHI’s pension and other postretirement net periodic benefit cost for the three months ended June 30, 2008 before intercompany allocations, of $17 million included $3 million for ACE’s allocated share. PHI’s pension and other postretirement net periodic benefit cost for the six months ended June 30, 2008 of $32 million includes $6 million for ACE’s allocated share.

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(7) DEBT

Credit Facilities

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

At June 30, 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 $549 million and $843 million, respectively.

Other Financing Activities

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

In April 2009, ACE Funding made principal payments of $5.3 million on Series 2002-1 Bonds, Class A-2, and $2.1 million on Series 2003-1 Bonds, Class A-1.

In June 2009, ACE completed the remarketing of approximately $23 million of Pollution Control Revenue Refunding Bonds which previously had been issued for the benefit of ACE by The Pollution Control Financing Authority of Salem County, New Jersey. The bonds were purchased during late 2008 and early 2009 by the Bank of New York Mellon pursuant to a standby bond purchase agreement in response to disruption in the municipal variable rate demand bond market that made it difficult for the remarketing agent to successfully remarket the bonds. The proceeds of the remarketing were used to reimburse the Bank of New York Mellon.

Subsequent to June 30, 2009, the following financing activity 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 $0.7 million on Series 2003-1 Bonds, Class A-2.

In July 2009, ACE redeemed the $25 million Series 2004 A and $6.5 million Series 2004 B Pollution Control Financing Authority of Cape May County tax exempt bonds that were repurchased in 2008 due to the disruptions in the tax exempt capital markets.

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(8) INCOME TAXES

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

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2009		2008		2009		2008
Federal statutory rate	35.0	%	35.0	%	35.0	%	35.0	%
Increases (decreases) resulting from:
Depreciation	(.8	)	(.5	)	(2.5	)	(1.1	)
State income taxes, net of federal effect	8.3		6.6		10.0		7.2
Tax credits	(2.5	)	(.7	)	(4.2	)	(1.1	)
Change in estimates and interest related to uncertain and effectively settled tax positions	(3.3	)	(5.0	)	(14.2	)	(13.3	)
Adjustment to prior year taxes	—		—		(8.3	)	—
Other, net	(3.4	)	.3		.9		(.3	)
Consolidated Effective Income Tax Rate	33.3	%	35.7	%	16.7	%	26.4	%

ACE’s consolidated effective tax rates for the three months ended June 30, 2009 and 2008 were 33.3% and 35.7%, respectively. The decrease in the rate resulted from the amortization of tax credits as a percentage of pre-tax income, and changes in estimates and interest related to uncertain and effectively settled positions primarily due to the mixed service cost settlement (see Footnote (10), “Commitments and Contingencies” for additional discussion), partially offset by the settlement of certain fuel over and under recoveries and the impact of certain permanent state tax differences as a percentage of pre-tax income.

ACE’s consolidated effective tax rates for the six months ended June 30, 2009 and 2008 were 16.7% and 26.4% respectively. The decrease in the rate resulted from non-recurring adjustments to prior year taxes and amortization of tax credits as a percentage of pre-tax income, partially offset by the impact of certain permanent state tax differences as a percentage of pre-tax income.

In March 2009, the Internal Revenue Service (IRS) issued a Revenue Agent’s Report (RAR) for the audit of PHI’s consolidated federal income tax returns for the calendar years 2003 to 2005. The IRS has proposed adjustments to PHI’s tax returns, including adjustments to 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, such as casualty losses and believes it has adequately reserved for the adjustments included in the RAR.

(9) FAIR VALUE DISCLOSURES

Fair Value of Assets and Liabilities Excluding Debt

Effective January 1, 2008, ACE adopted SFAS No. 157 which established a framework for measuring fair value and expanded disclosures about fair value measurements.

As defined in SFAS No. 157, 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. SFAS No. 157 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 defined by SFAS No. 157 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.

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Level 2 – Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using broker quotes in liquid markets, and other observable 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.

The following tables set forth by level within the fair value hierarchy ACE’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2009 and December 31, 2008. As required by SFAS No. 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. ACE’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Fair Value Measurements at June 30, 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	$	14	$	14	$	—	$	—
Executive deferred compensation plan assets		1		1		—		—
	$	15	$	15	$	—	$	—
LIABILITIES
Executive deferred compensation plan liabilities	$	1	$	—	$	1	$	—
	$	1	$	—	$	1	$	—

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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	$	76	$	76	$	—	$	—
Executive deferred compensation plan assets		1		1		—		—
	$	77	$	77	$	—	$	—
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 June 30, 2009 and December 31, 2008 are shown below:

	June 30, 2009				December 31, 2008
	(millions of dollars)
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	610	$	649	$	610	$	638
Transition Bonds issued by ACE Funding		418		434		433		431
Redeemable Serial Preferred Stock		6		4		6		4

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

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

New Jersey Rate Proceedings

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 bill stabilization adjustment mechanism (BSA). Under New Jersey law, the NJBPU is required to approve, modify or deny the application within 180 days. The NJBPU has advised ACE that the 180-day period commenced on February 23, 2009 and, therefore, unless otherwise extended by the parties by consent, ACE anticipates that NJBPU will act on ACE’s application by late August 2009.

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Under the BSA, customer delivery rates are subject to adjustment (through a surcharge or credit 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.

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.

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 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

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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.

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 the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA), and that the sales transactions may have constituted an arrangement for the disposal or treatment of hazardous substances at the site, which could be a basis for liability under CERCLA. The EPA’s letter also states that as of the date of the letter, EPA’s expenditures for response measures at the site exceed $6 million. EPA estimates approximately $6 million as the cost for future response measures it recommends. ACE understands that the EPA sent similar general notice letters to three other companies and various individuals.

ACE believes that the B.L. England boiler slag sold to MDC was a valuable material with various industrial applications, and therefore, the sale was not an arrangement for the disposal or treatment of any hazardous substances as would be necessary to constitute a basis for liability under CERCLA. ACE intends to contest any 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 is helpful to 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. ACE has not yet been served with the complaint.

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.

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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 and six months ended June 30, 2009 and 2008 were $25 million and $23 million and $50 million and $46 million, respectively.

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

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
Income (Expense)	2009			2008			2009			2008
	(millions in dollars)
Purchased power from Conectiv Energy Supply (a)	$	(41	)	$	(36	)	$	(87	)	$	(58	)
Meter reading services provided by Millennium Account Services LLC (b)		(1	)		(1	)		(2	)		(2	)
Intercompany lease transactions (b)		—			—			(1	)		(1	)
Intercompany use revenue (c)		1			1			3			1
Intercompany use expense (c)		—			(1	)		(1	)		(1	)

(a) Included in purchased energy expense.

(b) Included in other operation and maintenance expense.

(c) Included in operating revenue.

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

Liability	June 30, 2009			December 31, 2008
	(millions of dollars)
Payable to Related Party (current)
PHI Service Company	$	(12	)	$	(11	)
Conectiv Energy Supply		(16	)		(16	)

The items listed above are included in the “Accounts payable due to associated companies” balances on the Consolidated Balance Sheets of $29 million and $28 million at June 30, 2009 and December 31, 2008, respectively.

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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	101
Pepco	140
DPL	146
ACE	153

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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).

For the three months ended June 30, 2009 and 2008, PHI’s Power Delivery operations produced 53% and 51%, respectively, of PHI’s consolidated operating revenues (including revenues from intercompany transactions) and 79% and 133%, respectively, of PHI’s consolidated operating income (including income from intercompany transactions). For the six months ended June 30, 2009 and 2008, PHI’s Power Delivery operations produced 54% and 50%, respectively of PHI’s consolidated operating revenues (including revenues from intercompany transactions) and 76% of PHI’s consolidated operating income for each period (including income from intercompany transactions).

The Power Delivery business consists primarily of the transmission, distribution and default supply of electricity, which for the three months ended June 30, 2009 and 2008, was responsible for 96% and 94%, respectively, of Power Delivery’s operating revenues. For the six months ended June 30, 2009 and 2008, respectively, the distribution, transmission and default supply of electricity accounted for 93% and 92% of Power Delivery’s operating revenues. The distribution and supply of natural gas contributed 4% and 6%, respectively, of Power Delivery’s operating revenues for the three months ended June 30, 2009 and 2008. For the six months ended June 30, 2009 and 2008, the distribution of natural gas contributed 7% and 8% of Power Delivery’s operating revenues. 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 and 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 (SOS) 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.

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

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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.

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

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

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

Each of Conectiv Energy and Pepco Energy Services is a separate operating segment for financial reporting purposes. For the three months ended June 30, 2009 and 2008, the operating revenues of the Competitive Energy business (including revenue from intercompany transactions) were equal to 50% and 56%, respectively, of PHI’s consolidated operating revenues, and the operating income of the Competitive Energy business (including operating income from intercompany transactions) was 9% and 59% of PHI’s consolidated operating income for the three months ended June 30, 2009 and 2008, respectively. For the six months ended June 30, 2009 and 2008, the operating revenues of the Competitive Energy business (including revenue from intercompany transactions) were equal to 49% and 56%, respectively, of PHI’s consolidated operating revenues, and the operating income of the Competitive Energy business (including operating income from intercompany transactions) was 14% and 50% of PHI’s consolidated operating income for the six months ended June 30, 2009 and 2008, respectively. 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 June 30, 2009 and 2008, 6% 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 six months ended June 30, 2009 and 2008, 6% 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 June 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 Item 1 of this Form 10-Q.

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Earnings Overview

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

PHI’s net income for the three months ended June 30, 2009 was $25 million, or $0.11 per share, compared to $15 million, or $0.07 per share, for the three months ended June 30, 2008.

Net income for the three months ended June 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 under Financial Accounting Standards Board (FASB) Staff Position (FSP) No. 13-2, “Accounting for a Change in the Timing of Cash Flows Relating to Income Taxes Generated by a Leveraged-Lease Transaction” (FSP13-2) to reflect the impact of a change in assumptions regarding the estimated timing of the tax benefits	$	(86	)
Additional interest accrued under FASB Interpretation Number (FIN) 48 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	)

Excluding the items listed above, net income would have been $108 million, or $0.53 per share, for the three months ended June 30, 2008.

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

	2009			2008			Change
Power Delivery	$	31		$	75		$	(44	)
Conectiv Energy		(14	)		21			(35	)
Pepco Energy Services		10			16			(6	)
Other Non-Regulated		8			(84	)		92
Corp. & Other		(10	)		(13	)		3
Total PHI Net Income	$	25		$	15		$	10

Discussion of Operating Segment Net Income Variances:

Power Delivery’s $44 million decrease in earnings is primarily due to the following:

• $10 million decrease due to lower distribution sales related to customer usage (weather and non-weather).

• $10 million decrease from ACE Basic Generation Service related to unbilled revenue.

• $9 million decrease due to favorable income tax adjustments in 2008 primarily related to FIN 48 interest.

• $7 million decrease due to higher operating and maintenance costs (primarily higher pension costs).

• $6 million decrease due to higher interest expense associated with an increase in outstanding debt.

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Conectiv Energy’s $35 million decrease in earnings is primarily due to the following:

Merchant Generation & Load Service earnings decreased approximately $40 million primarily due to:

• $32 million decrease resulting from significantly lower run-time (down 44%) and reduced spark spreads and dark spreads (down 70%).

• $13 million decrease primarily related to economic fuel hedges that were favorable in the second quarter of 2008 due to rising fuel prices and unfavorable in the second quarter of 2009 due to falling fuel prices.

• $2 million decrease due to lower gross margins from default electricity supply contracts and associated hedges.

• $7 million increase due to an increase in capacity margins.

Energy Marketing earnings increased approximately $3 million primarily due to:

• $8 million increase in power origination due to the cancellation of a forward capacity contract.

• $3 million decrease in gas marketing due to low natural gas prices and demand, resulting in the inability to cover firm storage and transportation costs.

Pepco Energy Services’ $6 million decrease in earnings is primarily due to the following:

• $7 million decrease due to higher interest and other expenses primarily associated with credit and collateral facilities for the retail energy supply business.

• $7 million decrease due to lower generation output and higher Reliability Pricing Model (RPM) charges associated with the power plants.

• $9 million increase due to favorable electric supply costs, ancillary and other electric-related wholesale supply costs, and favorable natural gas supply costs; partially offset by less favorable mark-to-market gains on energy contracts.

Other Non-Regulated’s $92 million increase in earnings is primarily due to the impact of the cross-border energy lease investment re-evaluation adjustment recorded in June 2008.

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008

PHI’s net income for the six months ended June 30, 2009 was $70 million, or $0.32 per share, compared to $114 million, or $0.57 per share, for the six months ended June 30, 2008.

Net income for the six months ended June 30, 2009, includes the $8 million credit for the Mirant Corporation (Mirant) bankruptcy settlement which is net of federal and state income taxes. Excluding this item, net income would have been $62 million, or $0.28 per share, for the six months ended June 30, 2009.

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PHI’s net income for the six months ended June 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 under FSP 13-2 to reflect the impact of a change in assumptions regarding the estimated timing of the tax benefits	$	(86	)
Additional interest accrued under FIN 48 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	)

Excluding the items listed above, net income would have been $207 million, or $1.03 per share, for the six months ended June 30, 2008.

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

	2009			2008			Change
Power Delivery	$	73		$	122		$	(49	)
Conectiv Energy		(10	)		69			(79	)
Pepco Energy Services		18			25			(7	)
Other Non-Regulated		14			(74	)		88
Corp. & Other		(25	)		(28	)		3
Total PHI Net Income	$	70		$	114		$	(44	)

Discussion of Operating Segment Net Income Variances:

Power Delivery’s $49 million decrease in earnings is primarily due to the following:

• $14 million decrease due to favorable income tax adjustments in 2008 primarily related to FIN 48 interest.

• $12 million decrease due to higher operating and maintenance costs (primarily higher pension costs).

• $11 million decrease due to higher interest expense associated with an increase in outstanding debt.

• $8 million decrease from ACE Basic Generation Service related to unbilled revenues.

• $7 million decrease due to lower distribution sales related to customer usage.

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

Conectiv Energy’s $79 million decrease in earnings is primarily due to the following:

Merchant Generation & Load Service earnings decreased approximately $82 million primarily due to:

• $47 million decrease resulting from significantly lower run-time (down 30%) and reduced spark spreads and dark spreads (down 61%).

• $40 million decrease primarily related to economic fuel hedges that were favorable in the first six months of 2008 due to rising fuel prices and unfavorable in the first six months of 2009 due to falling fuel prices. The decrease includes significantly fewer opportunities to benefit from generating unit operating flexibility and fuel switching capability, and from remarketing activities around firm natural gas transportation and storage positions, especially during the first quarter.

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• $6 million decrease due to lower gross margins from default electricity supply contracts and associated hedges.

• $11 million increase due to an increase in capacity margins.

Energy Marketing earnings increased approximately $3 million primarily due to:

• $8 million increase in power origination due to the cancellation of a forward capacity contract.

• $5 million decrease in gas marketing due to low natural gas prices and demand, resulting in the inability to cover firm storage and transportation costs.

Pepco Energy Services’ $7 million decrease in earnings is primarily due to the following:

• $9 million decrease due to higher interest and other expenses primarily associated with credit and collateral facilities for the retail energy supply business.

• $9 million decrease due to lower generation output and higher RPM charges associated with the power plants.

• $15 million increase due to favorable electric supply costs, ancillary and other electric-related wholesale supply costs, and favorable natural gas supply costs; partially offset by less favorable mark-to-market gains on energy contracts.

Other Non-Regulated’s $88 million increase in earnings is primarily due to the impact of the cross-border energy lease investment re-evaluation adjustment recorded in June 2008.

Consolidated Results Of Operations

The following results of operations discussion is for the three months ended June 30, 2009, compared to the three months ended June 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	$	1,095		$	1,297		$	(202	)
Conectiv Energy		469			789			(320	)
Pepco Energy Services		560			631			(71	)
Other Non-Regulated		14			(105	)		119
Corp. & Other		(73	)		(94	)		21
Total Operating Revenue	$	2,065		$	2,518		$	(453	)

Power Delivery Business

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

	2009		2008		Change
Regulated T&D Electric Revenue	$	394	$	421	$	(27	)
Default Supply Revenue		642		777		(135	)
Other Electric Revenue		19		16		3
Total Electric Operating Revenue		1,055		1,214		(159	)

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	2009		2008		Change
Regulated Gas Revenue		30		36		(6	)
Other Gas Revenue		10		47		(37	)
Total Gas Operating Revenue		40		83		(43	)
Total Power Delivery Operating Revenue	$	1,095	$	1,297	$	(202	)

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.

Electric Operating Revenue

Regulated T&D Electric Revenue	2009		2008		Change
Residential	$	130	$	134	$	(4	)
Commercial and industrial		202		201		1
Other		62		86		(24	)
Total Regulated T&D Electric Revenue	$	394	$	421	$	(27	)
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	3,448	3,674	(226	)
Commercial and industrial	7,819	8,392	(573	)
Other	56	56	—
Total Regulated T&D Electric Sales	11,323	12,122	(799	)
Regulated T&D Electric Customers (in thousands)	2009	2008	Change
Residential	1,614	1,604	10
Commercial and industrial	197	197	—
Other	2	2	—
Total Regulated T&D Electric Customers	1,813	1,803	10

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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 $27 million primarily due to:

• A decrease of $21 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 $8 million due to lower non-weather related customer usage.

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

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

The aggregate amount of these decreases was partially offset by:

• An increase of $6 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 $5 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	$	383	$	388	$	(5	)
Commercial and industrial		232		302		(70	)
Other		27		87		(60	)
Total Default Supply Revenue	$	642	$	777	$	(135	)

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	3,328	3,551	(223	)
Commercial and industrial	2,148	2,605	(457	)
Other	21	24	(3	)
Total Default Electricity Supply Sales	5,497	6,180	(683	)

Default Electricity Supply Customers (in thousands)	2009	2008	Change
Residential	1,568	1,562	6
Commercial and industrial	163	167	(4	)
Other	2	2	—
Total Default Electricity Supply Customers	1,733	1,731	2

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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 $135 million primarily due to:

• A decrease of $59 million in wholesale energy revenues due to the sale at lower market prices of electricity purchased from NUGs.

• A decrease of $33 million primarily due to commercial and industrial customer migration to competitive suppliers.

• A decrease of $24 million due to lower sales as a result of milder weather during the 2009 spring months as compared to 2008.

• A decrease of $22 million due to lower non-weather related customer usage.

The aggregate amount of these decreases was partially offset by:

• An increase of $5 million as the result of higher Default Electricity Supply rates.

The decrease in total Default Supply Revenue noted above includes a decrease of $18 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 three months ended June 30, 2009 as compared to the comparable period for 2008, BGS unbilled revenue decreased by $18 million, which resulted in a $10 million decrease in PHI’s net income. The decrease was due to milder weather, lower customer usage and increased customer migration during the three months ended June 30, 2009 as compared to 2008.

Gas Operating Revenue

Regulated Gas Revenue	2009		2008		Change
Residential	$	17	$	20	$	(3	)
Commercial and industrial		11		14		(3	)
Transportation and Other		2		2		—
Total Regulated Gas Revenue	$	30	$	36	$	(6	)
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		2		3		(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.

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

• A decrease of $7 million primarily associated with the recognition of the unbilled portion of Gas Cost Rate revenue since the first quarter of 2009. Recognition of the unbilled revenue had the effect of including less of the winter heating season revenue in the second quarter of 2009 as compared to the second quarter of 2008. This decrease in revenue is offset in Fuel and Purchased Energy and Other Services Cost of Sales.

• A decrease of $3 million due to lower non-weather related customer usage.

The aggregate amount of these decreases was partially offset by:

• An increase of $4 million primarily due to the Gas Cost Rate changes effective November 2008 and March 2009.

Other Gas Revenue

Other Gas Revenue, which is substantially offset in Fuel and Purchased Energy and Other Services Cost of Sales, decreased by $37 million primarily due to lower revenue from off-system sales resulting from:

• A decrease of $20 million due to lower demand from electric generators and gas marketers.

• A decrease of $17 million due to lower market prices.

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	Three Months Ended June 30,					Change
	2009			2008
Operating Revenue ($ millions):
Merchant Generation & Load Service	$	343		$	487	$	(144	)
Energy Marketing		126			302		(176	)
Total Operating Revenue (a)	$	469		$	789	$	(320	)
Cost of Sales($ millions):
Merchant Generation & Load Service	$	325		$	402	$	(77	)
Energy Marketing		113			294		(181	)
Total Cost of Sales (b)	$	438		$	696	$	(258	)
Gross Margin($ millions):
Merchant Generation & Load Service	$	18		$	85	$	(67	)
Energy Marketing		13			8		5
Total Gross Margin	$	31		$	93	$	(62	)
Generation Fuel and Purchased Power Expenses($ millions) (c):
Generation Fuel Expenses (d),(e)
Natural Gas	$	41		$	68	$	(27	)
Coal		—			13		(13	)
Oil		—			14		(14	)
Other (f)		1			—		1
Total Generation Fuel Expenses	$	42		$	95	$	(53	)
Purchased Power Expenses (e)	$	240		$	214	$	26
Statistics:
Generation Output (Megawatt hours(MWh)):
Base-Load (g)		107,428			367,891		(260,463	)
Mid-Merit (Combined Cycle) (h)		374,052			588,430		(214,378	)
Mid-Merit (Oil Fired) (i)		(2,959	)		67,719		(70,678	)
Peaking		5,647			41,624		(35,977	)
Tolled Generation		125,976			28,641		97,335
Total		610,144			1,094,305		(484,161	)
Load Service Volume (MWh) (j)		1,484,561			2,335,027		(850,466	)
Average Power Sales Price (k) ($/MWh):
Generation Sales (d)	$	41.34		$	139.01	$	(97.67	)
Non-Generation Sales (l)	$	83.38		$	87.11	$	(3.73	)
Total	$	71.08		$	102.02	$	(30.94	)
Average on-peak spot power price at PJM East Hub ($/MWh) (m)	$	40.68		$	109.29	$	(68.61	)
Average around-the-clock spot power price at PJM East Hub ($/MWh) (m)	$	35.35		$	87.85	$	(52.50	)
Average spot natural gas price at market area M3 ($/MMBtu) (n)	$	4.04		$	12.13	$	(8.09	)
Weather (degree days at Philadelphia Airport): (o)
Heating degree days		413			410		3
Cooling degree days		333			393		(60	)

Notes:

(a) Includes $69 million and $88 million of affiliate transactions for 2009 and 2008, respectively.

(b) Includes less than $1 million and $1 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. Generation output for these units was negative for the second quarter of 2009 because of station service consumption.

(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 June 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 second 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 $67 million primarily due to:

• A decrease of approximately $54 million of physical generation gross margin resulting from significantly lower run-time (down 44%) and reduced spark spreads and dark spreads (down 70%).

• A decrease of approximately $23 million of gross margin primarily related to economic fuel hedges that were favorable in the second quarter of 2008 due to rising fuel prices and unfavorable in the second quarter of 2009 due to falling fuel prices.

• A decrease of approximately $2 million resulting from lower gross margins from default electricity supply contracts and associated hedges.

• An increase of approximately $12 million due to an increase in capacity gross margin.

Energy Marketing gross margin increased approximately $5 million primarily due to:

• An increase of approximately $13 million in power origination margins due to the cancellation of a forward capacity contract.

• A decrease of approximately $4 million in gas marketing margins resulting from low natural gas prices and demand resulting in the inability to cover firm storage and transportation costs.

Pepco Energy Services

Pepco Energy Services’ operating revenue decreased $71 million primarily due to:

• $23 million decrease due to lower construction activities.

• $21 million decrease due to lower generation output.

• $15 million decrease due to lower retail natural gas prices partially offset by higher customer load.

• $12 million decrease due to lower volumes of retail electric load served due to fewer customer acquisitions.

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Other Non-Regulated

Other Non-Regulated revenues increased by $119 million from $(105) million for the three months ended June 30, 2008 to $14 million for the three months ended June 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 FSP 13-2, 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	$	700		$	827		$	(127	)
Conectiv Energy		438			696			(258	)
Pepco Energy Services		505			582			(77	)
Corp. & Other		(70	)		(93	)		23
Total	$	1,573		$	2,012		$	(439	)

Power Delivery Business

Power Delivery’s Fuel and Purchased Energy and Other Services Cost of Sales decreased by $127 million primarily due to:

• A decrease of $61 million due to lower non-weather related customer electricity usage.

• A decrease of $36 million in the cost of gas purchases for off-system sales, the result of lower average gas prices and volumes purchased.

• A decrease of $26 million due to lower electricity sales as a result of milder weather during the 2009 spring months as compared to 2008.

• A decrease of $21 million due to the transfer of the Panda PPA.

• A decrease of $13 million in average electricity costs under new Default Electricity Supply contracts.

• A decrease of $11 million in the cost of gas purchases for system sales, the result of lower average gas prices and volumes purchased.

• A decrease of $7 million due to a lower rate of recovery of natural gas supply costs primarily as a result of recording the unbilled portion of Gas Cost Rate revenue as discussed under Gas Operating Revenue.

The aggregate amount of these decreases was partially offset by:

• An increase of $34 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 $13 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 $77 million primarily due to:

• $26 million decrease due to lower volumes of electricity purchased to serve decreased retail customer load.

• $24 million decrease due to lower wholesale natural gas prices partially offset by higher retail customer load.

• $16 million decrease due to lower construction activities.

• $10 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	$	185		$	173		$	12
Conectiv Energy		37			42			(5	)
Pepco Energy Services		21			21			—
Other Non-Regulated		2			—			2
Corp. & Other		(8	)		(5	)		(3	)
Total	$	237		$	231		$	6

Other Operation and Maintenance expense for Power Delivery increased by $12 million; however, excluding a decrease of $1 million primarily related to administrative expenses that are deferred and recoverable, Other Operation and Maintenance expense increased by $13 million. The $13 million increase was primarily due to:

• An increase of $18 million in employee-related costs primarily due to higher pension and other post-employment benefit expenses.

The increase was partially offset by:

• A decrease of $2 million primarily due to lower emergency restoration costs.

Other Taxes

Other Taxes increased by $5 million to $90 million in 2009 from $85 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).

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Deferred Electric Service Costs

Deferred Electric Service Costs, which relate only to ACE, decreased by $40 million resulting from a reduction of expenses of $57 million in 2009 as compared to a reduction of expenses of $17 million in 2008. The decrease was primarily due to:

• A decrease of $69 million associated with 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 $22 million associated with a higher rate of recovery of deferred energy costs.

• An increase of $6 million associated with a higher rate of recovery of New Jersey Societal Benefit program costs.

• An increase of $2 million associated with 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.

Other Income (Expenses)

Other Expenses (which are net of Other Income) increased by $18 million to a net expense of $89 million in 2009 from a net expense of $71 million in 2008. The increase was primarily due to an $11 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 June 30, 2009 and 2008 were 34.2% and 65.3%, respectively. The decrease in the rate resulted from the second quarter 2008 charge related to the cross-border energy leases investments and corresponding state tax benefits related to the charge, the 2008 benefit for interest received on a state income tax refund, and the 2009 change in deductions related to deferred compensation funding.

Income Tax Adjustments

During the second quarter of 2009, DPL recorded an adjustment to correct certain income tax errors related to prior periods. The adjustment, which is not considered material, resulted in a decrease in income tax expense of $1 million for the three months ended June 30, 2009.

During the second quarter of 2009, ACE recorded adjustments to correct certain income tax errors related to prior periods. These adjustments, which are not considered material, resulted in an increase in income tax expense of $1 million for the three months ended June 30, 2009.

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The following results of operations discussion is for the six months ended June 30, 2009 compared to the six months ended June 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	$	2,467		$	2,592		$	(125	)
Conectiv Energy		1,044			1,612			(568	)
Pepco Energy Services		1,217			1,252			(35	)
Other Non-Regulated		27			(87	)		114
Corp. & Other		(170	)		(210	)		40
Total Operating Revenue	$	4,585		$	5,159		$	(574	)
Power Delivery Business
The following table categorizes Power Delivery’s operating revenue by type of revenue.
	2009			2008			Change
Regulated T&D Electric Revenue	$	781		$	800		$	(19	)
Default Supply Revenue		1,478			1,562			(84	)
Other Electric Revenue		37			31			6
Total Electric Operating Revenue		2,296			2,393			(97	)
Regulated Gas Revenue		149			128			21
Other Gas Revenue		22			71			(49	)
Total Gas Operating Revenue		171			199			(28	)
Total Power Delivery Operating Revenue	$	2,467		$	2,592		$	(125	)

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

	2009		2008		Change
Regulated T&D Electric Revenue
Residential	$	274	$	267	$	7
Commercial and industrial		382		370		12
Other		125		163		(38	)
Total Regulated T&D Electric Revenue	$	781	$	800	$	(19	)

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	8,222	8,159	63
Commercial and industrial	15,312	15,957	(645	)
Other	126	126	—
Total Regulated T&D Electric Sales	23,660	24,242	(582	)
	2009	2008	Change
Regulated T&D Electric Customers (in thousands)
Residential	1,614	1,604	10
Commercial and industrial	197	197	—
Other	2	2	—
Total Regulated T&D Electric Customers	1,813	1,803	10

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 $19 million primarily due to:

• A decrease of $36 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 $9 million due to lower non-weather related customer usage.

The aggregate amount of these decreases was partially offset by:

• An increase of $15 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).

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• An increase of $9 million due to higher pass-through revenue primarily resulting from a tax rate change in Montgomery County, Maryland (substantially offset in Other Taxes).

• An increase of $4 million due to a distribution rate change in the District of Columbia that became effective in February 2008.

Default Electricity Supply

	2009		2008		Change
Default Supply Revenue
Residential	$	900	$	839	$	61
Commercial and industrial		492		550		(58	)
Other		86		173		(87	)
Total Default Supply Revenue	$	1,478	$	1,562	$	(84	)

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	7,966	7,896	70
Commercial and industrial	4,620	4,945	(325	)
Other	48	50	(2	)
Total Default Electricity Supply Sales	12,634	12,891	(257	)
	2009	2008	Change
Default Electricity Supply Customers (in thousands)
Residential	1,568	1,562	6
Commercial and industrial	163	167	(4	)
Other	2	2	—
Total Default Electricity Supply Customers	1,733	1,731	2

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 $84 million primarily due to:

• A decrease of $86 million in wholesale energy revenues due to the sale at lower market prices of electricity purchased from NUGs.

• A decrease of $32 million due to lower non-weather related customer usage.

• A decrease of $15 million primarily due to commercial customer migration to competitive suppliers.

The aggregate amount of these decreases was partially offset by:

• An increase of $38 million as the result of higher Default Electricity Supply rates.

• An increase of $8 million due to higher sales as a result of colder weather during the 2009 winter heating season as compared to 2008.

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The decrease in total Default Supply Revenue noted above includes a decrease of $15 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 six months ended June 30, 2009 as compared to the comparable period for 2008, BGS unbilled revenue decreased by $15 million, which resulted in a $8 million decrease in PHI’s net income. The decrease was due to milder weather, lower customer usage and increased customer migration during the six months ended June 30, 2009 as compared to 2008.

Gas Operating Revenue

	2009		2008		Change
Regulated Gas Revenue
Residential	$	92	$	77	$	15
Commercial and industrial		53		47		6
Transportation and Other		4		4		—
Total Regulated Gas Revenue	$	149	$	128	$	21

	2009	2008	Change
Regulated Gas Sales (billion cubic feet)
Residential	5	5	—
Commercial and industrial	3	3	—
Transportation and Other	3	4	(1	)
Total Regulated Gas Sales	11	12	(1	)

	2009	2008	Change
Regulated Gas Customers (in thousands)
Residential	113	112	1
Commercial and industrial	9	10	(1	)
Transportation and Other	—	—	—
Total Default Electricity Supply 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.

Regulated Gas Revenue increased by $21 million primarily due to:

• An increase of $18 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 $8 million due to lower non-weather related customer usage.

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Other Gas Revenue

Other Gas Revenue, which is substantially offset in Fuel and Purchased Energy and Other Services Cost of Sales, decreased by $49 million primarily due to lower revenue from off-system sales resulting from:

• A decrease of $27 million due to lower market prices.

• A decrease of $22 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	Six Months Ended June 30,				Change
	2009		2008
Operating Revenue ($ millions):
Merchant Generation & Load Service	$	711	$	994	$	(283	)
Energy Marketing		333		618		(285	)
Total Operating Revenue (a)	$	1,044	$	1,612	$	(568	)
Cost of Sales($ millions):
Merchant Generation & Load Service	$	650	$	794	$	(144	)
Energy Marketing		306		595		(289	)
Total Cost of Sales (b)	$	956	$	1,389	$	(433	)
Gross Margin($ millions):
Merchant Generation & Load Service	$	61	$	200	$	(139	)
Energy Marketing		27		23		4
Total Gross Margin	$	88	$	223	$	(135	)
Generation Fuel and Purchased Power Expenses($ millions) (c):
Generation Fuel Expenses (d),(e)
Natural Gas	$	58	$	101	$	(43	)
Coal		9		29		(20	)
Oil		19		26		(7	)
Other (f)		2		1		1
Total Generation Fuel Expenses	$	88	$	157	$	(69	)
Purchased Power Expenses (e)	$	482	$	483	$	(1	)
Statistics:
Generation Output (MWh):
Base-Load (g)		410,932		933,954		(523,022	)
Mid-Merit (Combined Cycle) (h)		683,198		963,785		(280,587	)
Mid-Merit (Oil Fired) (i)		31,181		64,397		(33,216	)
Peaking		7,759		45,157		(37,398	)
Tolled Generation		305,990		35,438		270,552
Total		1,439,060		2,042,731		(603,671	)
Load Service Volume (MWh) (j)		3,494,519		5,268,368		(1,773,849	)
Average Power Sales Price (k) ($/MWh):
Generation Sales (d)	$	55.82	$	117.98	$	(62.16	)
Non-Generation Sales (l)	$	88.12	$	87.74	$	.38
Total	$	78.70	$	94.96	$	(16.26	)
Average on-peak spot power price at PJM East Hub ($/MWh) (m)	$	50.67	$	96.77	$	(46.10	)
Average around-the-clock spot power price at PJM East Hub ($/MWh) (m)	$	45.06	$	81.31	$	(36.25	)
Average spot natural gas price at market area M3 ($/MMBtu) (n)	$	5.15	$	11.13	$	(5.98	)
Weather (degree days at Philadelphia Airport): (o)
Heating degree days		2,947		2,732		215
Cooling degree days		333		393		(60	)

(a) Includes $160 million and $195 million of affiliate transactions for 2009 and 2008, respectively.

(b) Includes less than $1 million and $4 million of affiliate transactions for 2009 and 2008, respectively. Also, excludes depreciation and amortization expense of $19 million and $18 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.

(e) Includes associated hedging gains and losses.

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(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 six months ended June 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 first and second 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 $139 million primarily due to:

• A decrease of approximately $79 million of physical generation margin resulting from significantly lower run-time (down 30%) and reduced spark spreads and dark spreads (down 61%).

• A decrease of approximately $67 million of gross margin primarily related to economic fuel hedges that were favorable in the first six months of 2008 due to rising fuel prices and unfavorable in the first six months of 2009 due to falling fuel prices. The decrease includes significantly fewer opportunities to benefit from generating unit operating flexibility and fuel switching capability, and from remarketing activities around firm natural gas transportation and storage positions, especially during the first quarter. In the first quarter of 2008, the magnitude of the gross margin increase related to these activities was greater than had been typically realized in the past due, in part, to significant fuel price increases in conjunction with less significant increases in power prices.

• A decrease of approximately $11 million resulting from lower gross margins from default electricity supply contracts and associated hedges. Reduced demand caused hedged volumes to exceed load in some locations.

• An increase of approximately $18 million due to an increase in capacity margin.

Energy Marketing gross margin increased approximately $4 million primarily due to:

• An increase of approximately $13 million in power origination margin due to the cancellation of a forward capacity contract.

• A decrease of $9 million due to low natural gas prices and demand, resulting in the inability to cover firm storage and transportation costs.

Pepco Energy Services

Pepco Energy Services’ operating revenue decreased $35 million primarily due to:

• $40 million decrease due to lower construction activities.

• $16 million decrease due to lower generation output.

• $12 million decrease due to lower retail natural gas prices partially offset by higher customer load.

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• $33 million increase due to higher customer prices for retail electric load.

Other Non-Regulated

Other Non-Regulated revenues increased by $114 million from $(87) million for the six months ended June 30, 2008 to $27 million for the six months ended June 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 FSP 13-2, 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	$	1,646		$	1,663		$	(17	)
Conectiv Energy		956			1,389			(433	)
Pepco Energy Services		1,119			1,166			(47	)
Corporate and Other		(165	)		(208	)		43
Total	$	3,556		$	4,010		$	(454	)

Power Delivery Business

Power Delivery’s Fuel and Purchased Energy and Other Services Cost of Sales decreased by $17 million primarily due to:

• A decrease of $47 million in the cost of gas purchases for off-system sales, the result of lower average gas prices and volumes purchased.

• A decrease of $45 million due to lower non-weather related customer electricity usage.

• A decrease of $36 million due to the transfer of the Panda PPA.

• A decrease of $16 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 $73 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 $31 million from the settlement of financial hedges (entered into as part of DPL’s hedge program for regulated natural gas).

• An increase of $11 million due to higher electricity sales as a result of colder weather during the 2009 winter heating season as compared to 2008.

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• An increase of $7 million in average electricity costs under new Default Electricity Supply contracts.

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 $47 million primarily due to:

• $29 million decrease due to lower construction activities.

• $20 million decrease due to lower wholesale natural gas prices partially offset by higher retail customer load.

• $6 million decrease due to lower generation output.

• $8 million increase due to higher prices of electricity purchased to serve retail customer load.

Other Operation and Maintenance

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

	2009			2008			Change
Power Delivery	$	371		$	344		$	27
Conectiv Energy		70			75			(5	)
Pepco Energy Services		44			40			4
Other Non-Regulated		2			1			1
Corporate and Other		(14	)		(10	)		(4	)
Total	$	473		$	450		$	23

Other Operation and Maintenance expense for Power Delivery increased by $27 million; however, excluding an increase of $3 million primarily related to bad debt and administrative expenses that are deferred and recoverable, Other Operation and Maintenance expense increased by $24 million. The $24 million increase was primarily due to:

• An increase of $26 million in employee-related costs primarily due to higher pension and other post-employment benefit expenses.

• An increase of $4 million in regulatory expenses incurred in connection with distribution rate cases.

The aggregate amount of these increases was partially offset by:

• A decrease of $4 million primarily due to lower emergency restoration and tree trimming costs.

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Other Taxes

Other Taxes increased by $8 million to $181 million in 2009 from $173 million in 2008. The increase was primarily due to increased pass-throughs experienced by Power Delivery resulting from tax rate changes in Maryland (substantially offset in Regulated T&D Electric Revenue).

Deferred Electric Service Costs

Deferred Electric Service Costs, which relate only to ACE, reflected a net decrease of $92 million resulting from a reduction of expenses of $84 million in 2009 as compared to an increase in expenses of $8 million in 2008. The decrease was primarily due to:

• A decrease of $125 million due to a lower rate of recovery of costs associated with energy and capacity purchased under the NUG contracts.

The decrease was partially offset by:

• An increase of $14 million associated with a higher rate of recovery of deferred energy costs.

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

• An increase of $5 million associated with 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 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 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. A gain of between $26 million and $28 million will be recorded in the third quarter reflecting a settlement allocating the Maryland portion of the remaining Mirant bankruptcy settlement proceeds between Pepco and its Maryland customers, which was approved by the Maryland Public Service Commission in July 2009.

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 $33 million to a net expense of $175 million in 2009 from a net expense of $142 million in 2008. The increase was primarily due to a $22 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 six months ended June 30, 2009 and 2008 were 34.6% and 41.4%, respectively. The decrease in the rate resulted from the second quarter 2008 charge related to the cross-border energy lease investments and corresponding state tax benefits related to the charge.

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Income Tax Adjustments

During the second quarter of 2009, DPL recorded an adjustment to correct certain income tax errors related to prior periods. The adjustment, which is not considered material, resulted in a decrease in income tax expense of $1 million for the six months ended June 30, 2009.

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 six months ended June 30, 2009.

Capital Resources and Liquidity

This section discusses Pepco Holdings’ working capital, cash flow activity, capital requirements and other uses and sources of capital.

Working Capital

At June 30, 2009, Pepco Holdings’ current assets on a consolidated basis totaled $2.1 billion and its current liabilities totaled $2.4 billion. At December 31, 2008, Pepco Holdings’ current assets totaled $2.6 billion and its current liabilities totaled $2 billion. The decrease in working capital from December 31, 2008 to June 30, 2009 is primarily due to the additional $220 million of pension contributions and an increase in the current maturities of long-term debt.

At June 30, 2009, Pepco Holdings’ cash and current cash equivalents totaled $120 million of which $95 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 $9 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.

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

	As of June 30, 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		75		—		—		116		—		—		—		—		—		191
Bank Loans		—		—		100		—		—		—		—		—		—		100
Credit Facility Loans		150		—		50		—		—		—		—		—		—		200
Total Short-Term Debt	$	225	$	—	$	255	$	139	$	—	$	—	$	21	$	—	$	—	$	640
Current Maturities of Long-Term Debt and Project Funding	$	450	$	16	$	—	$	—	$	33	$	—	$	3	$	—	$	—	$	502

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	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
Commercial Paper		—		—		—		—		—		—		—		—		—		—
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 June 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 June 30, 2009, PHI had an outstanding loan of $150 million and DPL had an outstanding loan of $50 million under the credit facility. DPL repaid its loan in July 2009.

In April 2009, Atlantic City Electric Transition Funding LLC (ACE Funding) made principal payments of $5.3 million on Series 2002-1 Bonds, Class A-2, and $2.1 million on Series 2003-1 Bonds, Class A-1.

In April 2009, Pepco repaid, prior to maturity, a $25 million short-term loan.

In April 2009, DPL resold $9 million of its Pollution Control Revenue Refunding Bonds which previously had been issued for the benefit of DPL by the Delaware Economic Development Authority. These bonds were repurchased by DPL in November 2008 in response to disruption in the tax-exempt bond market that made it difficult for the remarketing agent to successfully remarket the bonds. As the owner of the bonds, DPL received the proceeds of the sale, which it intends to use for general corporate purposes.

In April 2009, PHI and its utility subsidiaries entered into a $25 million line of credit that can be used by these entities for equipment leasing through February 2010. As of June 30, 2009, $7 million of this line of credit has been utilized.

In May 2009, DPL repaid, prior to maturity, $50 million of a $150 million short-term loan, which matured in July 2009.

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 June 2009, ACE completed the remarketing of approximately $23 million of Pollution Control Revenue Refunding Bonds which previously had been issued for the benefit of ACE by The Pollution Control Financing Authority of Salem County, New Jersey. The bonds were purchased during late 2008 and early 2009 by the Bank of New York Mellon pursuant to a standby bond purchase agreement in response to disruption in the municipal variable rate demand bond market that made it difficult for the remarketing agent to successfully remarket the bonds. The proceeds of the remarketing were used to reimburse the Bank of New York Mellon.

Financing Activity Subsequent to June 30, 2009

In July 2009, ACE Funding made principal payments of $5.2 million on Series 2002-1 Bonds, Class A-2, and $1.4 million on Series 2003-1 Bonds, Class A-1, and $0.7 million on Series 2003-1 Bonds, Class A-2.

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

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.

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In July 2009, DPL redeemed the $15 million Series 2003 A and $18.2 million Series 2003 B Delaware Economic Development Authority tax exempt bonds that were repurchased in 2008 due to the disruptions in the tax exempt capital markets.

In July 2009, ACE redeemed the $25 million Series 2004 A and $6.5 million Series 2004 B Pollution Control Financing Authority of Cape May County tax exempt bonds that were repurchased in 2008 due to the disruptions in the tax exempt capital markets.

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.

In November 2008, PHI entered into a second unsecured credit facility in the amount of $400 million. Under the facility, PHI may obtain revolving loans and swingline loans over the term of the facility, which expires on November 6, 2009. 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.”

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Cash and Credit Facilities Available as of June 30, 2009

	Consolidated PHI			PHI Parent			Utility Subsidiaries
	(millions of dollars)
Credit Facilities (Total Capacity)	$	1,950		$	1,325		$	625
Borrowings under Credit Facilities		(200	)		(150	)		(50	)
Letters of Credit		(190	)		(185	)		(5	)
Commercial Paper Outstanding		(191	)		(75	)		(116	)
Remaining Credit Facilities Available		1,369			915			454
Cash Invested in Money Market Funds (a)		95			—			95
Total Cash and Credit Facilities Available	$	1,464		$	915		$	549

(a) Cash and cash equivalents reported on the Balance Sheet total $120 million, which includes the $95 million invested in money market funds and $25 million held in cash and uncollected funds.

The continuing disruptions in the capital and credit markets, combined with the volatility of energy prices, have had a negative impact on borrowing capacity and liquidity of PHI and its subsidiaries. To address the challenges posed by the current 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 half 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 (see “Financing Activities During the Three Months ended June 30, 2009”).

At June 30, 2009, the amount of cash, plus borrowing capacity under PHI’s primary credit facilities available to meet the liquidity needs of PHI and its utility subsidiaries on a consolidated basis totaled $1.5 billion, of which $549 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 of PHI’s utility subsidiaries in the aggregate.

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 June 30, 2009, approximately 32% 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 six months ended June 30, 2009, approximately $7 million and $8 million, respectively, of the fees have been amortized.

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

Depending on the contract terms, the collateral required to be posted by Pepco Energy Services and Conectiv Energy can be of varying forms, including cash and letters of credit. As of June 30, 2009, the Competitive Energy business (including Pepco Energy Services’ retail energy supply business) had posted net cash collateral of $443 million and letters of credit of $182 million. At December 31, 2008, the Competitive Energy business had posted net cash collateral of $331 million and letters of credit of $558 million.

At June 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 $915 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 $112 million in 2009, as compared to $49 million in 2008. For the three months ended June 30, 2009 and 2008, PHI’s pension and other postretirement benefit expense was $33 million and $12 million, respectively. For the six months ended June 30, 2009 and 2008, PHI’s pension and other postretirement benefit expense was $57 million and $24 million, respectively.

During 2009, PHI has made discretionary tax-deductible contributions totaling $300 million 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, $220 million was contributed prior to June 30, 2009, through tax-deductible contributions from Pepco, ACE and DPL in the amounts of $150 million, $60 million and $10 million, respectively. The remaining $80 million contribution was made in July 2009 through tax-deductible contributions from Pepco of $20 million and $60 million from the PHI Service Company.

Cash Flow Activity

PHI’s cash flows for the six months ended June 30, 2009 and 2008 are summarized below:

	Cash (Use) Source
	2009			2008
	(millions of dollars)
Operating Activities	$	7		$	693
Investing Activities		(382	)		(361	)
Financing Activities		111			(96	)
Net (decrease) increase in cash and cash equivalents	$	(264	)	$	236

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Operating Activities

Cash flows from operating activities during the six months ended June 30, 2009 and 2008 are summarized below:

	Cash Source
	2009			2008
	(millions of dollars)
Net Income	$	70		$	114
Non-cash adjustments to net income		199			237
Pension contributions		(220	)		—
Changes in cash collateral related to derivative activities		(104	)		395
Changes in other assets and liabilities		62			(53	)
Net cash from operating activities	$	7		$	693

Net cash from operating activities was $686 million lower for the six months ended June 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 to the decrease in net income after adjusting for non-cash items, pension contributions of $220 million were made during the six months ended June 30, 2009 that resulted in a further reduction in cash flow from operating activities. The pension contributions were made to achieve the 2009 funding target level, as defined in the Pension Protection Act of 2006, for the PHI Retirement Plan. The cash collateral requirements related to derivative activities of the Competitive Energy business also contributed significantly to the decrease in cash flow from operating activities. In the six months ended June 30, 2009, during a period of declining energy and commodity prices, PHI posted net cash collateral with derivative instrument counterparties of $104 million, as compared to an inflow of cash collateral of $395 million for the comparable period in 2008, when energy and commodity prices were sharply rising.

Investing Activities

Cash flows from investing activities during the six months ended June 30, 2009 and 2008 are summarized below:

	Cash Use
	2009			2008
	(millions of dollars)
Construction expenditures	$	(388	)	$	(366	)
Cash proceeds from sale of assets		—			51
All other investing cash flows, net		6			(46	)
Net cash used by investing activities	$	(382	)	$	(361	)

Net cash used by investing activities increased $21 million for the six months ended June 30, 2009 compared to the same period in 2008. The change is a result of a $32 million increase in Conectiv Energy capital expenditures due to the construction of new generating facilities offset by lower capital expenditures by Pepco Energy Services.

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Financing Activities

Cash flows from financing activities during the six months ended June 30, 2009 and 2008 are summarized below:

	Cash Source (Use)
	2009			2008
	(millions of dollars)
Dividends paid on common and preferred stock	$	(119	)	$	(109	)
Common stock issued under the Shareholder Dividend Reinvestment Plan		15			14
Issuance of common stock		11			15
Issuances of long-term debt		110			400
Reacquisition of long-term debt		(67	)		(405	)
Issuances of short-term debt, net		175			20
All other financing cash flows, net		(14	)		(31	)
Net cash provided (used) by financing activities	$	111		$	(96	)

Net cash from financing activities increased $207 million for the six months ended June 30, 2009, compared to the same period in 2008, principally due to increases in short-term debt.

Common Stock Dividends

Common stock dividend payments were $119 million and $109 million for the six months ended June 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 when compared to 2008. Under the Long-Term Incentive Plan, PHI issued 165,870 shares of common stock during the six months ended June 30, 2009, and 548,216 shares of common stock during the six months ended June 30, 2008. In addition, under PHI’s Shareholder Dividend Reinvestment Plan, 1,148,428 shares of common stock were issued during the six months ended June 30, 2009 and 571,271 were issued during the six months ended June 30, 2008.

Changes in Outstanding Long-Term Debt

Cash flows from the issuance and reacquisitions of long-term debt for the six months ended June 30, 2009 and for the six months ended June 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	$	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 (the 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.

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	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 2030-2031 (b)		—		36
		—		98
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		15		14
6.73% - 6.75% Medium-term notes due 2008		—		25
6.71% - 6.73% Medium-term notes due 2008		—		9
		15		119
Pepco Energy Services		2		—
Total	$	67	$	405

(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.

Changes in Short-Term Debt

The $155 million increase in short-term debt during the six months ended June 30, 2009 as compared to the six months ended June 30, 2008, was primarily due to borrowing under the $1.5 billion credit facility of $100 million by PHI and an increase in commercial paper issued of $191 million. These increases are offset by the Pepco repayment of all short term bank loans and credit facility loans outstanding in the 2008 period.

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

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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 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 and the MPSC staff under which Pepco will distribute 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 expects to record a pre-tax gain between $26 million and $28 million in the quarter ending September 30, 2009.

As of June 30, 2009, approximately $64 million in remaining proceeds from the Mirant settlement was accounted for as restricted cash and as a regulatory liability. In the third quarter of 2009, the restricted cash will be released and the regulatory liability will be extinguished as a consequence of the MPSC order.

Capital Requirements

Capital Expenditures

Pepco Holdings’ total capital expenditures for the six months ended June 30, 2009 totaled $388 million, of which $130 million was incurred by Pepco, $84 million was incurred by DPL, $67 million was incurred by ACE and $91 million was incurred by Conectiv Energy. The remainder was incurred primarily by Pepco Energy Services. 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 and moved the section of the line that would run from DPL’s Indian River substation near Millsboro, Delaware, to Salem, New Jersey, into PJM’s “continuing study” category. 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.

	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

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Pepco Holdings expects to fund these expenditures through internally generated cash and external financing.

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 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 July 23, 2009, Pepco Holdings’ Board of Directors declared a dividend on common stock of 27 cents per share payable September 30, 2009, to shareholders of record on September 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 six months ended June 30, 2009. The balances reflected in the table are stated gross, pre-tax and before the netting of collateral required by FIN 39-1.

	Energy Commodity Activities (a)
	(millions of dollars)
Total Fair Value of Energy Contract Net Liabilities at December 31, 2008	$	(314	)
Current period unrealized losses		(12	)
Effective portion of changes in fair value - recorded in Accumulated Other Comprehensive Loss		(275	)
Cash flow hedge ineffectiveness - recorded in income		(3	)
Recognition of realized gains (losses) on settlement of contracts		170
Total Fair Value of Energy Contract Net Liabilities at June 30, 2009	$	(434	)
	Total
Detail of Fair Value of Energy Contract Net Liabilities at June 30, 2009 (see above)
Derivative assets (current assets)	$	66
Derivative assets (non-current assets)		34
Total Fair Value of Energy Contract Assets		100
Derivative Liabilities (current liabilities)		(421	)
Derivative liabilities (non-current liabilities)		(113	)
Total Fair Value of Energy Contract Liabilities		(534	)
Total Fair Value of Energy Contract Net Liabilities	$	(434	)

Notes:

(a) Includes all Statement of Financial Accounting Standards (SFAS) No. 133 hedge activity and trading activities recorded at fair value through Accumulated Other Comprehensive Loss (AOCL) or on the Statements of Income, as required.

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The $434 million net liability on energy contracts at June 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 SFAS No. 133. Prices of electricity and natural gas declined during the first and second quarter of 2009, which resulted in unrealized losses on the energy contracts of the Competitive Energy business. Competitive Energy recorded unrealized losses of $275 million on energy contracts in Accumulated Other Comprehensive Loss as these energy contracts were effective hedges under SFAS No. 133. 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 June 30, 2009 and are subject to change as a result of changes in these factors:

	Fair Value of Contracts at June 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	$	(101	)	$	(87	)	$	(9	)	$	—		$	(197	)
Prices provided by other external sources (b)		(88	)		(126	)		(24	)		(13	)		(251	)
Modeled (c)		3			4			(3	)		10			14
Total	$	(186	)	$	(209	)	$	(36	)	$	(3	)	$	(434	)

Notes:

(a) Includes all SFAS No. 133 hedge activity and trading activities recorded at fair value through AOCL or on the Statements of Income, as required.

(b) Prices provided by other external sources reflect information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms that is 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 June 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 $533 million, $295 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 Item 1 of this Form 10-Q. The remaining $238 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.

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Many of the contractual arrangements entered into by PHI’s subsidiaries in connection with Competitive Energy and Default Electricity Supply activities include margining rights pursuant to which the PHI subsidiary or a counterparty may request collateral if the market value of the contractual obligations reaches levels in excess of the credit thresholds established in the applicable arrangements. Pursuant to these margining rights, the affected PHI subsidiary may receive, or be required to post, collateral due to energy price movements. As of June 30, 2009, Pepco Holdings’ subsidiaries engaged in Competitive Energy activities and Default Electricity Supply activities provided net cash collateral in the amount of $469 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 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 SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS No. 142). Management has identified Power Delivery as a single reporting unit based on the aggregation of components. The first step of the goodwill impairment test under SFAS No. 142 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 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 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 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 on 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 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.

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

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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 since the adoption of SFAS No. 142.

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 SFAS No. 142, 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 SFAS No. 142. 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 defined in SFAS No. 142, 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 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 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 June 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 2007 Maryland Rate Order), 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 six months ended June 30, 2009, to the six months ended June 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		$	443	$	470	$	(27	)
Default Supply Revenue			634		578		56
Other Electric Revenue			18		16		2
Total Operating Revenue	��	$	1,095	$	1,064	$	31

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	$	122	$	119	$	3
Commercial and industrial		270		261		9
Other		51		90		(39	)
Total Regulated T&D Electric Revenue	$	443	$	470	$	(27	)
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		3,792		3,699		93
Commercial and industrial		9,135		9,242		(107	)
Other		78		78		—
Total Regulated T&D Electric Sales		13,005		13,019		(14	)
Regulated T&D Electric Customers (in thousands)	2009		2008		Change
Residential		695		687		8
Commercial and industrial		73		73		—
Other		—		—		—
Total Regulated T&D Electric Customers		768		760		8

Regulated T&D Electric Revenue decreased by $27 million primarily due to:

• A decrease of $36 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 $9 million due to higher pass-through revenue primarily resulting from a tax rate change in Montgomery County, Maryland (substantially offset in Other Taxes).

• An increase of $4 million due to a distribution rate change in the District of Columbia that became effective in February 2008.

Default Electricity Supply

Default Supply Revenue	2009		2008		Change
Residential	$	410	$	359	$	51
Commercial and industrial		220		215		5
Other		4		4		—
Total Default Supply Revenue	$	634	$	578	$	56

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Default Electricity Supply Sales (GWh)	2009	2008	Change
Residential	3,582	3,505	77
Commercial and industrial	2,101	1,950	151
Other	4	5	(1	)
Total Default Electricity Supply Sales	5,687	5,460	227
Default Electricity Supply Customers (in thousands)	2009	2008	Change
Residential	657	655	2
Commercial and industrial	52	53	(1	)
Other	—	—	—
Total Default Electricity Supply Customers	709	708	1

Default Supply Revenue, which is substantially offset in Purchased Energy, increased by $56 million primarily due to:

• An increase of $34 million as the result of higher Default Electricity Supply rates.

• An increase of $17 million primarily due to commercial customer migration from competitive suppliers.

• An increase of $8 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 $6 million due to lower non-weather related customer usage.

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 six months ended June 30.

	2009		2008
Sales to District of Columbia customers	34	%	32	%
Sales to Maryland customers	51	%	50	%

Operating Expenses

Purchased Energy

Purchased Energy, which is primarily associated with Default Electricity Supply sales, increased by $20 million to $622 million in 2009 from $602 million in 2008. The increase was primarily due to the following:

• An increase of $63 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 $10 million due to higher electricity sales as a result of colder weather during the 2009 winter heating season as compared to 2008.

• An increase of $15 million primarily due to commercial customer migration from competitive suppliers.

The aggregate amount of these increases was partially offset by:

• A decrease of $36 million due to the transfer of the Panda PPA.

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• A decrease of $32 million in average electricity costs under new Default Electricity Supply contracts.

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 $13 million to $160 million in 2009 from $147 million in 2008. Excluding a decrease of $1 million primarily related to administrative expenses that are deferred and recoverable, Other Operation and Maintenance expense increased by $14 million. The $14 million increase was primarily due to the following:

• An increase of $10 million in employee-related costs primarily due to higher pension and other post-employment benefit expenses.

• An increase of $4 million in regulatory expenses incurred in connection with distribution rate cases.

Other Taxes

Other Taxes increased by $8 million to $147 million in 2009 from $139 million in 2008. The increase was primarily due to increased pass-throughs resulting from a tax rate change in Maryland (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. A gain of between $26 million and $28 million will be recorded in the third quarter reflecting a settlement allocating the Maryland portion of the remaining Mirant bankruptcy settlement proceeds between Pepco and its Maryland customers that was approved by the MPSC in July 2009.

Other Income (Expenses)

Other Expenses (which are net of Other Income) increased by $8 million to a net expense of $45 million in 2009 from a net expense of $37 million in 2008. The increase was primarily due to a $10 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 six months ended June 30, 2009 and 2008 were 42.9% and 34.4%, respectively. The increase in the rate resulted from the change in estimates and interest related to uncertain tax positions. During the second quarter of 2008, there was a reduction in previously accrued interest and estimates resulting from the settlement of the mixed service cost issue and a benefit was recorded for interest received on a state income tax refund.

Capital Requirements

Liquidity

The continued disruptions in the capital and credit markets, combined with the volatility of energy prices, have 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.

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PEPCO

Capital Expenditures

Pepco’s capital expenditures for the six months ended June 30, 2009, totaled $130 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 changes 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.

	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

Pepco expects to fund these expenditures through internally generated cash and from external financing and capital contributions from PHI.

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 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.

145

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 territories who do not elect to purchase electricity from a competitive supplier. Default Electricity Supply is known as Standard Offer Service in both Delaware and Maryland. DPL’s electricity distribution service territory covers approximately 5,000 square miles and has a population of approximately 1.3 million. As of June 30, 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 2007 Maryland Rate Order), the Maryland Public Service Commission (MPSC) 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 six months ended June 30, 2009, to the six months ended June 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	$	170	$	173	$	(3	)
Default Supply Revenue		390		401		(11	)
Other Electric Revenue		12		10		2
Total Electric Operating Revenue	$	572	$	584	$	(12	)

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	$	80	$	82	$	(2	)
Commercial and industrial		50		53		(3	)
Other		40		38		2
Total Regulated T&D Electric Revenue	$	170	$	173	$	(3	)

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

Regulated T&D Electric Sales (Gigawatt hours (GWh))	2009	2008	Change
Residential	2,469	2,474	(5	)
Commercial and industrial	3,612	3,950	(338	)
Other	25	25	—
Total Regulated T&D Electric Sales	6,106	6,449	(343	)
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 $3 million primarily due to:

• A decrease of $4 million due to lower non-weather related customer usage.

Default Electricity Supply

Default Supply Revenue	2009		2008		Change
Residential	$	275	$	262	$	13
Commercial and industrial		111		134		(23	)
Other		4		5		(1	)
Total Default Supply Revenue	$	390	$	401	$	(11	)
Default Electricity Supply Sales (GWh)	2009		2008		Change
Residential		2,423		2,405		18
Commercial and industrial		1,054		1,293		(239	)
Other		21		22		(1	)
Total Default Electricity Supply Sales		3,498		3,720		(222	)

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DPL

Default Electricity Supply Customers (in thousands)	2009	2008	Change
Residential	430	427	3
Commercial and industrial	48	49	(1	)
Other	1	1	—
Total Default Electricity Supply Customers	479	477	2

Default Supply Revenue, which is substantially offset in Purchased Energy, decreased by $11 million primarily due to:

• A decrease of $18 million primarily due to commercial and industrial customer migration to competitive suppliers.

• A decrease of $15 million due to lower non-weather related customer usage.

The aggregate amount of these decreases was partially offset by:

• An increase of $16 million as the result of higher Default Electricity Supply rates.

• An increase of $6 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 jurisdictions that are derived from customers receiving Default Electricity Supply distribution from DPL. Amounts are for the six months ended June 30:

	2009		2008
Sales to Delaware customers	53	%	54	%
Sales to Maryland customers	65	%	65	%

Natural Gas Operating Revenue

	2009		2008		Change
Regulated Gas Revenue	$	149	$	128	$	21
Other Gas Revenue		22		71		(49	)
Total Natural Gas Operating Revenue	$	171	$	199	$	(28	)

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	$	92	$	77	$	15
Commercial and industrial		53		47		6
Transportation and Other		4		4		—
Total Regulated Gas Revenue	$	149	$	128	$	21
Regulated Gas Sales (billion cubic feet)	2009		2008		Change
Residential		5		5		—
Commercial and industrial		3		3		—
Transportation and Other		3		4		(1	)
Total Regulated Gas Sales		11		12		(1	)

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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 $21 million primarily due to:

• An increase of $18 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 $8 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 $49 million primarily due to lower revenue from off-system sales resulting from:

• A decrease of $27 million due to lower market prices.

• A decrease of $22 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 $7 million to $380 million in 2009 from $387 million in 2008. The decrease was primarily due to:

• A decrease of $29 million due to lower non-weather related customer electricity usage.

The decrease was partially offset by:

• An increase of $11 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 $7 million due to higher electricity sales as a result of colder weather during the 2009 winter heating season as compared to 2008.

• An increase of $5 million in average electricity costs under new Default Electricity Supply contracts.

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 $29 million to $128 million in 2009 from $157 million in 2008. The decrease is primarily due to:

• A decrease of $47 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 $16 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 $31 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 $8 million to $118 million in 2009 from $110 million in 2008. Excluding an increase of $2 million primarily related to administrative expenses that are deferred and recoverable, Other Operation and Maintenance expense increased by $6 million. The $6 million increase was primarily due to:

• An increase of $10 million in employee-related costs primarily due to higher pension and other post-employment benefit expenses.

The increase was partially offset by:

• A decrease of $2 million in preventative and corrective maintenance costs.

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 $6 million to a net expense of $21 million in 2009 from a net expense of $15 million in 2008. The increase was primarily due to a $5 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 six months ended June 30, 2009 and 2008 were 35.0% and 32.6% respectively. The increase in the rate resulted from the change in estimates and interest related to uncertain and effectively settled tax positions due to the filing of an amended state income tax return to recover unused net operating losses, partially offset by the second quarter 2008 settlement of the mixed service cost issue and the filing of a claim with the Internal Revenue Service related to certain casualty losses.

Income Tax Adjustment

During the second quarter of 2009, DPL recorded an adjustment to correct certain income tax errors related to prior periods. The adjustment, which is not considered material, resulted in a decrease in income tax expense of $1 million for the six months ended June 30, 2009.

Capital Requirements

Liquidity

The continued disruptions in the capital and credit markets, combined with the volatility of energy prices, have 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 six months ended June 30, 2009, totaled $84 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 and moved the section of the line that would run from DPL’s Indian River substation near Millsboro, Delaware, to Salem, New Jersey, into PJM’s “continuing study” category. 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.

	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

DPL expects to fund these expenditures through internally generated cash and from external financing and capital contributions from PHI.

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 Indian River to Salem line in a future planning period.

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DPL

Forward-Looking Statements

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

The forward-looking statements contained herein are qualified in their entirety by reference to the following important factors, which are difficult to predict, contain uncertainties, are beyond DPL’s control and may cause actual results to differ materially from those contained in forward-looking statements:

• 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.

152

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 six months ended June 30, 2009, to the six months ended June 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	$	168	$	157	$	11
Default Supply Revenue		454		583		(129	)
Other Electric Revenue		9		8		1
Total Operating Revenue	$	631	$	748	$	(117	)

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 not generally 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	$	72	$	66	$	6
Commercial and industrial		62		56		6
Other		34		35		(1	)
Total Regulated T&D Electric Revenue	$	168	$	157	$	11

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

Regulated T&D Electric Sales (Gigawatt hours (GWh))	2009	2008	Change
Residential	1,961	1,986	(25	)
Commercial and industrial	2,565	2,765	(200	)
Other	23	23	—
Total Regulated T&D Electric Sales	4,549	4,774	(225	)
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 $11 million primarily due to:

• An increase of $15 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 $4 million due to lower non-weather related customer usage.

Default Electricity Supply

Default Supply Revenue	2009		2008		Change
Residential	$	215	$	218	$	(3	)
Commercial and industrial		161		201		(40	)
Other		78		164		(86	)
Total Default Supply Revenue	$	454	$	583	$	(129	)

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	1,961	1,986	(25	)
Commercial and industrial	1,465	1,702	(237	)
Other	23	23	—
Total Default Electricity Supply Sales	3,449	3,711	(262	)
Default Electricity Supply Customers (in thousands)	2009	2008	Change
Residential	481	480	1
Commercial and industrial	63	65	(2	)
Other	1	1	—
Total Default Electricity Supply Customers	545	546	(1	)

Default Supply Revenue, which is substantially offset in Purchased Energy and Deferred Electric Service Costs, decreased by $129 million primarily due to:

• A decrease of $86 million in wholesale energy revenues due to the sale at lower market prices of electricity purchased from NUGs.

• A decrease of $14 million primarily due to commercial customer migration to competitive suppliers.

• A decrease of $12 million as the result of lower Default Electricity Supply rates.

• A decrease of $11 million due to lower non-weather related customer usage.

• A decrease of $6 million due to lower sales as a result of milder weather during the 2009 spring months as compared to 2008.

The decrease in total Default Supply Revenue noted above includes a decrease of $15 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 six months ended June 30, 2009 as compared to the comparable period for 2008, BGS unbilled revenue decreased by $15 million, which resulted in a $8 million decrease in ACE’s net income. The decrease was due to milder weather, lower customer usage and increased customer migration during the six months ended June 30, 2009 as compared to 2008.

For the six months ended June 30, 2009 and 2008, the percentage of ACE’s total distribution sales that are derived from customers receiving Default Electricity Supply are 76% and 78% respectively.

Operating Expenses

Purchased Energy

Purchased Energy, which is primarily associated with Default Electricity Supply sales, decreased by $2 million to $516 million in 2009 from $518 million in 2008. The decrease was primarily due to:

• A decrease of $31 million due to lower non-weather related customer electricity usage.

• A decrease of $6 million due to lower electricity sales as a result of milder weather during the 2009 spring months as compared to 2008.

The aggregate amount of these decreases was partially offset by:

• An increase of $34 million in average electricity costs under new Default Electricity Supply contracts.

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ACE

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 $95 million in 2009 from $89 million in 2008. Excluding an increase of $2 million primarily related to bad debt expenses that are deferred and recoverable, Other Operation and Maintenance expense increased by $4 million primarily due to an increase of $7 million in employee-related costs primarily due to higher pension and other post-employment benefit expenses.

Deferred Electric Service Costs

Deferred Electric Service Costs reflected a net decrease of $92 million resulting from a reduction of expenses of $84 million in 2009 as compared to an increase in expenses of $8 million in 2008. The decrease was primarily due to:

• A decrease of $125 million associated with 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 $14 million associated with a higher rate of recovery of deferred energy costs.

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

• An increase of $5 million associated with 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 $6 million to a net expense of $33 million in 2009 from a net expense of $27 million in 2008. The increase was primarily due to a $7 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 six months ended June 30, 2009 and 2008 were 16.7% and 26.4% respectively. The decrease in the rate resulted from non-recurring adjustments to prior year taxes and amortization of tax credits as a percentage of pre-tax income, partially offset by the impact of certain permanent state tax differences as a percentage of pre-tax income.

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 six months ended June 30, 2009.

Capital Requirements

Liquidity

The continued disruptions in the capital and credit markets, combined with the volatility of energy prices, have 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 5.8% senior notes due in 2018.

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ACE

Capital Expenditures

ACE’s capital expenditures for the six months ended June 30, 2009, totaled $67 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 changes 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.

	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

ACE expects to fund these expenditures through internally generated cash and from external financing and capital contributions from PHI.

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 through an Infrastructure Investment Surcharge 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 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�� and 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 under Statement of Financial Accounting Standards (SFAS) No. 133. 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 six months ended June 30, 2009 in millions of dollars:

	VaR for Competitive Energy Commodity Activity (a)
95% confidence level, one-day holding period, one-tailed Period end	$	3
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 under SFAS No. 133, 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 ISONE. 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 June 30, 2009, the electricity sold forward by Conectiv Energy as a percentage of projected plant output combined with energy purchase commitments was 98%, 87%, and 36% 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 SFAS No. 133.

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 June 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	$	277	$	—	$	277	2	$	146
Non-Investment Grade		15		7		8	—		—
No External Ratings		35		9		26	—		—
Credit reserves					$	2

(a) Investment Grade - primarily determined using publicly available credit ratings of the counterparty. If the counterparty has provided a guarantee by a higher-rated entity (e.g., its parent), it is determined based upon the rating of its guarantor. Included in “Investment Grade” are counterparties with a minimum Standard & Poor’s or Moody’s Investor Service rating of BBB- or Baa3, respectively.

(b) Exposure before credit collateral - includes the marked to market (MTM) energy contract net assets for open/unrealized transactions, the net receivable/payable for realized transactions and net open positions for contracts not subject to MTM. Amounts due from counterparties are offset by liabilities payable to those counterparties to the extent that legally enforceable netting arrangements are in place. Thus, this column presents the net credit exposure to counterparties after reflecting all allowable netting, but before considering collateral held.

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(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 June 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 June 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.

On June 1, 2009, Pepco Energy Services, a subsidiary of Pepco Holdings, completed implementation of new energy transaction software that provides additional functionality for its retail natural gas business, including enhanced retail and wholesale deal capture, position reporting and monitoring, wholesale settlements and retail customer invoice processing.

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 June 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 June 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 June 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 June 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 June 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 June 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 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 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 June 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. 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, as of June 30, 2009, PHI would have been obligated to pay approximately $522 million in additional federal and state taxes and $94 million of interest. In addition, the IRS could require PHI to pay a penalty of up to 20% on the amount of additional taxes due. PHI anticipates, however that any additional taxes that it would be required to pay as a result of the disallowance of prior deductions or a recharacterization of leases as loans would be recoverable in the form of lower taxes over the remaining term of the investments.

For further discussion of this matter, see 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.

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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 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 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.

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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 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.

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.

165

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 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.

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.

166

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

(a) The Annual Meeting of Shareholders was held on May 15, 2009.

(b) Directors who were elected at the annual meeting:

For Term Expiring in 2010:
Jack B. Dunn IV	Votes cast for:	116,838,842
	Votes withheld:	49,147,336
Terence C. Golden	Votes cast for:	154,210,045
	Votes withheld:	11,776,133
Patrick T. Harker	Votes cast for:	156,714,914
	Votes withheld:	9,271,263
Frank O. Heintz	Votes cast for:	122,815,953
	Votes withheld:	43,170,225
Barbara J. Krumsiek	Votes cast for:	154,082,420
	Votes withheld:	11,903,758
George F. MacCormack	Votes cast for:	154,251,274
	Votes withheld:	11,734,904
Lawrence C. Nussdorf	Votes cast for:	153,786,619
	Votes withheld:	12,199,559
Joseph M. Rigby	Votes cast for:	155,297,714
	Votes withheld:	10,688,464
Frank K. Ross	Votes cast for:	122,700,507
	Votes withheld:	43,285,670
Pauline A. Schneider	Votes cast for:	85,068,878
	Votes withheld:	80,917,300
Lester P. Silverman	Votes cast for:	154,268,004
	Votes withheld:	11,718,174

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(c) The following proposal was voted on at the meeting:

The Board of Directors approved and submitted to a vote of the shareholders a proposal to ratify the appointment of PricewaterhouseCoopers LLP as independent registered public accounting firm of PHI for 2009.

This proposal passed. The number of shares present and entitled to vote on the proposal was 165,998,397. Adoption of the proposal required the affirmative vote of the holders of a majority of the shares of Pepco Holdings Common Stock present and entitled to vote or 82,999,199 shares. 164,097,870 shares were voted for the proposal, 1,243,072 shares were voted against the proposal, 640,524 shares abstained and there were no broker non-votes.

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.

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Item 6.EXHIBITS

The documents listed below are being filed or furnished 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
10.1	PHI	Separation Agreement of Paul H. Barry, dated June 12, 2009	Exhibit 10.1 to PHI’s Form 8-K, 6/12/09
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.
18.1	PHI	PricewaterhouseCoopers Preferability Letter	Filed herewith.
18.2	DPL	PricewaterhouseCoopers Preferability Letter	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.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, each of the registrants has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	PEPCO HOLDINGS, INC. (PHI) POTOMAC ELECTRIC POWER COMPANY (Pepco) DELMARVA POWER & LIGHT COMPANY (DPL) ATLANTIC CITY ELECTRIC COMPANY (ACE) (Registrants)
August 6, 2009	By	/s/    A.J. KAMERICK
		Anthony J. Kamerick
		Senior Vice President and Chief Financial Officer, PHI, Pepco and DPL Chief Financial Officer, ACE

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INDEX TO EXHIBITS FILED HEREWITH

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
18.1	PHI	PricewaterhouseCoopers Preferability Letter
18.2	DPL	PricewaterhouseCoopers Preferability Letter
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
101.INS	PHI, Pepco, DPL, ACE	XBRL Instance Document
101.SCH	PHI, Pepco, DPL, ACE	XBRL Taxonomy Extension Schema Document
101.CAL	PHI, Pepco, DPL, ACE	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	PHI, Pepco, DPL, ACE	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	PHI, Pepco, DPL, ACE	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	PHI, Pepco, DPL, ACE	XBRL Taxonomy Extension Presentation Linkbase Document
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